DAQ-2024-010899

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DAQC-1000-24
Site IDs 10335, 15659 (B1)
MEMORANDUM

TO: FILE – TESORO REFINING AND MARKETING COMPANY AND TESORO
LOGISTICS OPERATIONS, LLC

THROUGH: Harold Burge, Major Source Compliance Section Manager

FROM: Jeremiah Marsigli, Environmental Scientist

DATE: October 1, 2024

SUBJECT: FULL COMPLIANCE EVALUATION, Major, Salt Lake County,
FRS ID # UT0000004903500004 / UT0000004903500008

DATE OF INSPECTION: September 4, 2024

SOURCE LOCATION: 474 West 900 North, Salt Lake City, UT

Mailing Address:

Tesoro Logistics Operations, LLC
19100 Ridgewood Parkway
San Antonio, TX 78259

SOURCE CONTACTS: Chris Kaiser, Environmental Superintendent (REF):
801-521-4959, Cell: 801-520-1860, ENV duty: 801-550-1400.
Kirt Rhoads, Senior Environmental Specialist (TLO)
Brian Mensinger, Consultant (TLO): 801-946-7342
Shawn Acerson, Manager (TLO)
Oliver Dugas, Environmental Coordinator (TLO): 505-966-6757
Michelle Bujdoso, Environmental Engineer (REF):
801-366-2036
Mike Stark, LDAR Coordinator
Peter Henrix, QQQ Coordinator
Eric Sjunnesen, GM Refinery
Mike Bergeson, HESS Manger
Catherine Wiemers, HESS
James Beardall, Tanks Coordinator

OPERATING STATUS: Operating

PROCESS DESCRIPTION:

Tesoro operates a refinery that is capable of processing 60,000 barrels of crude oil per day. The crude oil
is processed by fractionating, reforming, cracking, alkylation, sulfur recovery, and other intermediate and
final blending processes, into various fuel products. Other activities include steam/electricity generation
(Cogeneration Plant), equipment cooling (cooling tower), wastewater treatment, and product storage and
distribution.

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Crude oil is piped into the Crude Unit, which heats the oil and separates (fractionate) it by boiling point.
The Ultraformer converts low octane naphtha into high-octane gasoline and hydrogen. The Fluid
Catalytic Cracking Unit (FCCU) cracks heavy gas oil feed (large hydrocarbon chains) into higher quality
gasoline blending components and light gas oil (small hydrocarbon chains). The cooling towers circulate
cooled water to equipment and products, which return hot water to be cooled. The Alkylation Unit takes
olefins and combines them with isobutane in the presence of sulfuric acid to form gasoline range
hydrocarbons. The Cogeneration Plant uses a combination of process fuel gas and natural gas and
produces steam to power turbines, heat reboilers, tanks, and buildings as well as producing a maximum
capacity of 24Kw electricity to be used at the refinery and the remainder to be sold to the power grid.

Sulfur Recovery Unit/Sour Water Stripper (SRU/SWS): Water with high sulfur content is called sour
water. Sour water from the Crude Unit and FCCU are stored in tank T-104. Sour water is then sent to the
SWS. Acid gas leaving the SWS is passed through the sour water scrubber (water knockout F-262). If the
scrubber goes down, the SWS system shuts down. The acid gas is then sent to the SRU.

Amine Plant: Sour fuel gas is sent to the amine absorber where the sulfur is removed. The amine solution
is then sent through a regenerator and recycled through the absorber until the amine solution is completely
used up or spent. Emissions from the amine plant are called amine acid gas and are processed through a
scrubber, and then the SRU. If the scrubber goes down, the entire system will shut down (including the
SRU).

SRU/SWS acid gas and amine acid gas are sent to the reactor furnace or acid gas burner. 60% or more of
the H2S is converted to sulfur in the reactor furnace. The reactor furnace starts up on natural gas and then
switches to plant gas. The acid gas then vents to a waste heat reclaimer, catalytic reactor, and three pass
condenser where the remaining H2S is converted to sulfur. Sulfur is drained to the sulfur pit. The sulfur
pit is vented to the SRU tail gas incinerator (TGI) through an eductor system. The truck and rail load out
systems also use eductors to vent sulfur to the SRU TGI. The SRU TGI burns any remaining H2S in the
gas stream. A flare system is installed inside the incinerator stack and is available in the event of a process
upset.

Wet Gas Scrubber has an ozone generation system to react with and remove NOx from the FCCU/CO
boiler exhaust stream. The exhaust gases are then passed through a new spray tower, which removes the
NOx compounds, as well as SO2/SO3 and particulates. The removed compounds are retained in the spray
tower's liquid medium - water, buffered with a sodium hydroxide reagent. The liquid is then processed in
a purge treatment unit, which separates and dewaters the solids.

Tesoro has monitors installed for the following processes: SO2 analyzer on the SRU TGI, SO2 analyzer
on CO Boiler ESP stack, H2S analyzer on the V-917 tank, opacity monitor on the CO Boiler ESP stack,
and oxygen monitors on Subpart J units. The V-917 tank is located at the Boiler Plant.

Tesoro is required to monitor equipment such as valves, pumps, compressors, and drains for leaks of
volatile organic compounds (VOCs). Monitoring consists of visual inspections as well as leak checks
made with a vapor analyzer following EPA Method 21. Each component that needs to be monitored is
identified, tagged, and tracked using a commercial computer program specifically designed for this
application. Each component tag has an identification number on it that is read into a hand-held computer
prior to sniffing it with the vapor analyzer. As the component is sniffed, any reading is automatically
recorded into the hand-held computer. The VOC Technician attempts minor repairs as the monitoring is
completed. A work order is sent to the maintenance department for any major repairs. After all of the
components for any unit are checked, the information from the hand-held computer is down-loaded onto a
desktop computer where the database is managed and reports are prepared. All of the required records are
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included in this database and quarterly reports are generated from this information and submitted to the
UDAQ for review.

Tesoro also operates a wastewater treatment plant (WWTP) for the refinery. All wastewater is received at
the treatment plant prior to discharge. The oil is separated and sent to Tank 298. From there it goes back
to the crude storage tanks in the remote tank farm where it will be processed along with the other crude.
Sludge from the WWTP is pumped to a holding tank (Tank 52). The sludge is then pumped to a mixing
tank (Tank 51) where a large mixer blends it with an emulsion breaker. After mixing in Tank 51, the
sludge and water are separated and the sludge is then handled as hazardous waste. The water from Tank
51 goes back to the treatment plant. Stormwater also goes to the WWTP. During high runoff, the
stormwater is held in dikes and surge tank 241 until it can be processed in the plant.

Tesoro submits quarterly reports for MACT, NSPS, and the EPA consent decree. They submit a separate
quarterly report for UAC. All other required reports are submitted as required.

APPLICABLE
REGULATIONS: Approval Order DAQE-AN103350075-18, dated January 11, 2018 (Refinery)
Approval Order DAQE-AN103350081A-21, dated January 12, 2021 (Refinery)

Title V Operating Permit # 3500008002 dated. October 17, 2023 (TLO)

MACT (Part 63), CC – Petroleum Refineries – source is subject to rule
MACT (Part 63), UUU – Petroleum Refineries – source is subject to rule
MACT (Part 63), ZZZZ – RICE – Source is subject to rule

NSPS (Part 60), A – General - source subject – flares
NSPS (Part 60), GGGa – VOC Leaks – applicable to GHT only
NSPS (Part 60), GG – Stationary Turbines - DDU and Cogen Units
NSPS (Part 60), J – Refineries - sources subject: FCCU, UFU, Cogen Unit and
Crude Unit
NSPS (Part 60), Ja – Refineries – source subject for flare gas recovery systems
NSPS (Part 60), Kb, Ka – Tanks - source is subject
NSPS (Part 60), QQQ – VOC from Wastewater Systems - wastewater system is
subject
NSPS (Part 63), R – Gasoline Distribution Facilities
NSPS (Part 60), VVa- Standards of Performance for Equipment Leaks of VOC in
Synthetic Organic Chemicals Manufacturing Industry
NSPS (Part 60), XX - Standards of Performance for Bulk Terminals
UAC R307-326 - Control of Hydrocarbon Emissions in Refineries
UAC R307-327 - Petroleum Liquid Storage.
UAC R307-328-4 - Loading of Tank Trucks, Trailers, Railroad Tank Cars

SOURCE INSPECTION EVALUATION:

Approval Order DAQE-AN103350075-18, dated January 11, 2018 (Refinery)
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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 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. Limits set forth in this AO have not been exceeded.

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. Only approved modifications have been made.

I.4 All records referenced in this AO, 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. Records shall be kept for a minimum
of five (5) years. Records for the Consent Decree, Civil Action No. 2:96 CV 095 RL shall be
kept for the life of the Consent Decree. [R307-415-6a]

Status: In Compliance. Records were made available upon request. Records have been
kept for a minimum of five years.

I.5 The owner/operator shall comply with R307-401-4: General Requirements. [R307-401-4]

Status: Requirements of R307-401-4 have been incorporated into Approval Orders and the
Title V Permit. See applicable conditions.

I.6 A. The owner/operator shall comply with R307-150 Series. Inventories.

B. The owner/operator shall maintain records of annual actual emissions of NOx, SO2,
VOC, and H2SO4 on a calendar year basis in accordance with 40 CFR 52.21(r)(6).
These records will be maintained for the following emission units:

Crude Unit Furnace H-101
FCCU/CO Boiler
Ultraformer Unit Furnace F-1
UFU Regeneration Heater F-15
DDU Charge Heater F-680
DDU Rerun Boiler F-681
SRU/TGTU/TGI
GHT Unit F-701
Ultraformer Compressors K1s
Cogeneration Unit Turbines
Cogeneration Unit HRSGs
DDU Reactor (SSM events)
VRU Vessels (SSM events)
FGDU/SWS (SRU) Flare
Cooling Tower UU3
LPG Rack
Gasoline and Diesel Truck Loadout Rack
Storage Tanks (186, 188, 204, 212, 213, 242, 243, 252, 321, 324, 325, 326, 327, 330,
331, 503, 504)
New and Replaced Components

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[R307-150, R307-405-19]

Status: In Compliance. Emission inventories have been submitted as required. The
owner/operator maintains records of annual actual emissions.

I.7 The owner/operator shall comply with UAC R307-107. General Requirements: Breakdowns.
[R307-107]

Status: In Compliance. Breakdown reports have been submitted as required.

I.8 The owner/operator shall submit documentation of the status of construction or modification of
the following new items to the Director within 18 months from the date of this AO:

New HCN Storage Tank (Tank 248)
New Gasoline Storage Tank (Tank 205)
New GHT Reactor Vessel
New Equipment in VOC Service at the GHT, BCLR, and Alkylation Unit

This AO may become invalid if construction is not commenced within 18 months from the date
of this AO or if construction is discontinued for 18 months or more. To ensure proper credit
when notifying the Director, send the documentation to the Director, attn.: NSR Section.
[R307-401-18]

Status: In Compliance. Construction on the equipment has been completed. The GHT
stack was tested on January 30, 2020.

Section II: SPECIAL PROVISIONS

II.A The approved installations shall consist of the following equipment:

II.A.1 Permitted Source
Permitted Source

II.A.2 H-101
Crude Unit Furnace, with ultra-low NOx burners and one (1) stack, PS #1

II.A.3 F-1
Ultraformer Unit (UFU) Furnace, with ultra-low NOx burners and four (4) stacks, PS #2

II.A.4 F-15
UFU Regeneration Heater, with low NOx burners and one (1) stack, PS #3

II.A.5 FCCU/CO Boiler
Fluid catalytic Cracking Unit (FCCU) Regenerator, Carbon Monoxide Boiler (Heat Recovery
Unit), with CONOx oxygen injection, ammonia injection, electrostatic precipitator (ESP), wet
gas scrubber/LoTOx system (WGS), and one (1) stack, PS #4

II.A.6 F-680 and F-681
Distillate Desulfurization Unit (DDU) charge heater and rerun boiler, combined rating
approx. 37.8 MMBtu/hr, equipped with "ultra-ultra" low NOx burners. Heaters share common
convection section and stack, PS #5.

II.A.7 K1s
Hydrogen Compressors (Ultraformer compressors), with catalytic converters and two (2)
stacks, PS #6

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II.A.8 South Flare
Flare covering Crude/UFU Unit/DDU,
Flare gas header routed to FGR system, PS #7

II.A.9 North Flare
Flare covering FCCU/VRU/Alkylation Unit/GHT,
Flare gas header routed to FGR system, PS #8

II.A.10 Modular FGR System (FGR)
Flare gas recovery compressors (electrically driven) and associated equipment

II.A.11 CO Boiler Bypass
CO Boiler Bypass, with one (1) stack, PS #9

II.A.12 SRU/TGI/TGTU
Sulfur Recovery Unit/Tail Gas Incinerator/Tail Gas Treatment Unit, PS #10

II.A.13 FGDU/SWS
Fuel Gas Desulfurization Unit/Sour Water Stripper (FGDU/SWS) Flare (this unit is
physically integrated with the Sulfur Recovery Unit (SRU)), PS #11

II.A.14 T-104
Sour Water Storage Tank

II.A.15 Emergency/Standby Sources
Waste Water Treatment Plant (WWTP) Generator, Electrical Generators, Plant Air
Compressors, Miscellaneous Air Compressors, Fire Water Pumps, B-1 Air Preheater,
Package Boilers, Fire House Generator

II.A.16 F-701
Gasoline Hydrotreater (GHT) Unit with 8.0 MMBtu/hr process heater, new process vessel
and new components in VOC service

II.A.17 BSU
Benzene Saturation Unit (BSU):
3,000 bpd Bensat reactor and 10,000 bpd reformate splitter.

II.A.18 CG1 and CG2
Cogeneration Unit: two (2) cogeneration trains (CG1 and CG2), each with one (1) 11.8 MW
(based on an annual average) turbine with SoLoNOx controls and one (1) heat recovery steam
generating unit rated at approx. 157.8 MMBtu/hr (HHV). Both rates based on an annual
average.

II.A.19 Loading/Unloading Racks

II.A.20 Blending Component Loading Rack (BCLR)
Loading rack capacity 1,000 gallons per minute, controlled by VRU with two (2) carbon
adsorption units and supplemental VRU control equipment; new components in VOC service

II.A.21 Tank 140: Storage vessel - petroleum liquids
Storage tank with internal floating roof and primary seals

II.A.22 Tank 141: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.23 Tank 142: Storage vessel - petroleum liquids
Storage tank with fixed roof

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II.A.24 Tank 144: Storage vessel - petroleum liquids
Storage tank with external floating roof, primary and secondary seal

II.A.25 Tank 157: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.26 Tank 158: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.27 Tank 186: Storage vessel - petroleum liquids
Storage tank with internal floating roof, primary and secondary seals

II.A.28 Tank 188: Storage vessel - petroleum liquids
Storage tank with internal floating roof, primary and secondary seals

II.A.29 Tank 189: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.30 Tank 190: Storage vessel - petroleum liquids
Storage tank with internal floating roof, primary and secondary seals

II.A.31 Tank 201: Storage vessel - amine
Storage tank with fixed roof

II.A.32 Tank 204: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.33 Tank 205: Storage Vessel - Petroleum Liquids
Storage tank with internal floating roof, primary and secondary seals

II.A.34 Tank 206: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.35 Tank 212: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.36 Tank 213: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.37 Tank 236: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.38 Tank 241: Storage vessel - surge tank
Storage tank with external floating roof, primary and secondary seals

II.A.39 Tank 242: Storage vessel - petroleum liquids
Storage tank with external floating roof, primary and secondary seals

II.A.40 Tank 243: Storage vessel - petroleum liquids
Storage tank with external floating roof, primary and secondary seals

II.A.41 Tank 244: Storage vessel - petroleum liquids
Storage tank with internal floating roof, primary and secondary seals

II.A.42 Tank 246: Storage vessel - petroleum liquids
Storage tank with external floating roof, primary and secondary seals

II.A.43 Tank 247: Storage vessel - petroleum liquids
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Storage tank with external floating roof, primary and secondary seals

II.A.44 Tank 248: Storage Vessel - Petroleum Liquids
Storage tank with internal floating roof, primary and secondary seals

II.A.45 Tank 252: Storage vessel - petroleum liquids
Storage tank with external floating roof, primary and secondary seals

II.A.46 Tank 291: Storage vessel - petroleum liquids
Storage tank with fixed roof to be retrofitted with internal floating roof

II.A.47 Tank 297: Storage vessel - petroleum liquids
Storage tank with internal floating roof and primary seals

II.A.48 Tank 298: Storage vessel - petroleum liquids
Storage tank with external floating roof, primary and secondary seals

II.A.49 Tank 307: Storage vessel - petroleum liquids
Storage tank with external floating roof, primary and secondary seals

II.A.50 Tank 308: Storage vessel - chemicals
Storage tank with external floating roof, primary and secondary seals

II.A.51 Tank 309: Storage vessel - petroleum liquids
Storage tank with external floating roof, primary and secondary seals (OOS)

II.A.52 Tank 310: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.53 Tank 311: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.54 Tank 312: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.55 Tank 313: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.56 Tank 314: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.57 Tank 315: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.58 Tank 321: Storage vessel - petroleum liquids
Storage tank with internal floating roof and primary seals

II.A.59 Tank 322: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.60 Tank 323: Storage vessel - petroleum liquids
Storage tank with fixed roof

II.A.61 Tank 324: Storage vessel - petroleum liquids
Storage tank with external floating roof, primary and secondary seals

II.A.62 Tank 325: Storage vessel - petroleum liquids
Storage tank with external floating roof, primary and secondary seals
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II.A.63 Tank 326: Storage vessel - petroleum liquids
Storage tank with external floating roof, primary and secondary seals

II.A.64 Tank 327: Storage vessel - gasoline
Storage tank with external floating roof, primary and secondary seals, and slotted guide pole
controls

II.A.65 Tank 328: Storage vessel - petroleum liquids
Storage tank with external floating roof, primary and secondary seals

II.A.66 Tank 330: Storage vessel - petroleum liquids
Storage tank with external floating roof, primary and secondary seals

II.A.67 Tank 331: Storage vessel - petroleum liquids
Storage tank with internal floating roof, primary and secondary seals

II.A.68 SO2 Cap Sources
Sources included in emissions cap: includes F-701, CG1 and CG2, H-101, FCCU/CO Boiler,
K1s, F-1, F-15 , F-680 and F-681

II.A.69 NOx Cap Sources
Sources included in emissions cap: includes F-701, CG1 and CG2, H-101, FCCU/CO Boiler,
K1s, F-1, F-15 , F-680 and F-681

II.A.70 PM10 Cap Sources
Sources included in emissions cap: includes F-701, CG1 and CG2, H-101, FCCU/CO Boiler,
K1s, F-1, F-15 , F-680 and F-681

Status: In Compliance. No unapproved equipment was observed at the time of this
inspection. The BCLR is no longer operating. Tank 104 has been replaced with Tank
103 (AO DAQE-AN103350081A-21). The wastewater plant construction is on schedule
and expected to be completed by June of 2025. Tank 241 has been demolished and is
being replaced with a tank constructed to meet the expected requirements of Subpart
Kc.

II.B Requirements and Limitations

II.B.1 Conditions on Permitted Source

II.B.1.a Visible emissions from the stacks of combustion units without controls shall be no greater than
10% opacity. Other fugitive emissions (not including fugitive dust) shall not exceed 15%
opacity. Compliance shall be determined using opacity observations performed in accordance
with 40 CFR 60, Appendix A, Method 9. [R307-309-4, R307-401-8(1)(a)]

Status: In Compliance. No visible emissions were observed coming from any emission
unit during this inspection.

II.B.1.b Visible emissions from the FCCU/CO Boiler shall not exceed 20% opacity. Compliance shall
be determined using opacity observations performed in accordance with 40 CFR 60, Appendix
A, Method 9.

Visible emissions from process flares, fugitive dust, and the FCCU (when going through the
bypass stack) shall not exceed 20% opacity. Compliance shall be determined using opacity
observations performed in accordance with 40 CFR 60, Appendix A, Method 9. [40 CFR 60,
R307-309-5, R307-401-8(1)(a)]

Status: In Compliance. No visible emissions were observed coming from any emission
unit this inspection.
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II.B.1.c Tesoro shall submit to the Director a projection of planned and required process shutdowns for
the upcoming calendar year by January 15 of each year. [R307-401]

Status: In Compliance. DAQ received a projection of planned and required process
shutdowns letter on January 9, 2024.

II.B.1.d Tesoro shall control the sulfur pit emissions by continuing to route sulfur pit emissions to the
incinerator at the SRU. [R307-401]

Status: In Compliance. Sulfur pit emissions are routed to the incinerator at the SRU.
Design diagrams are available upon request.

II.B.1.e Tesoro shall supply no more than one-third of its potential electrical output capacity on an
annual basis to any utility power distribution system for sale (on a gross basis). Records of
capacity and annual electrical sales shall be maintained. [R307-401]

Status: In Compliance. Records showed that Tesoro provided 4% of its potential
electrical output on a gross basis to utilities during the 12-month period ending
September 3, 2024.

II.B.1.f Tesoro shall install and operate a flare gas recovery system designed to limit hydrocarbon
flaring from each of the North Flare and South Flare to levels below the values listed in 40
CFR 60.103a(c), except during periods of start-up, shut down, or malfunction. [40 CFR 60
Subpart Ja, SIP Section IX.H.11]

Status: In Compliance. The flare gas recovery system requirement was applicable
November 11, 2015, and was installed prior to the issuance of this Approval Order.

II.B.1.g Plant-wide Emission Limits:

By no later than January 1, 2019, combined emissions of:

1. Total (Filterable + Condensable) PM10 shall not exceed 2.25 tons per day,

2. Filterable PM2.5 shall not exceed 0.42 tons per day and 110 tons per rolling
12-month period,

3. NOx shall not exceed 1.988 tons per day and 475 tons per rolling 12-month
period, and

4. SO2 shall not exceed 3.1 tons per day and 300 tons per rolling 12-month
period

For purposes of this requirement, a "day" is defined as a period of 24-hours commencing at
midnight and ending at the following midnight. Compliance with the emission limits shall be
determined as outlined in Section IX.H.2 and Section IX.H.12 of the SIP, as adopted by the
Air Quality Board on December 2, 2015. [SIP Section IX.H.12, SIP Section IX.H.2]

Status: In Compliance. Three listed limits are not up-to-date with the current SIP – The
daily SIP source cap for NOx is 2.3 tons per day and 475 tons per year (IX.H.2), SO2 is
3.8 tons per day and 300 tons per year (IX.H.2), and PM2.5 is 2.25 tons per day and 179
tons per rolling 12-month period (IX.H.12). For the 12 month period ending August 31,
2024, the following was recorded:

30 tons of Filterable PM2.5. The highest daily total recorded during the period was 0.107
tons on January 16, 2024.

256 tons of NOx. The highest daily total recorded during the period was 0.987 tons on
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May 26, 2024.

25 tons of SO2. The highest daily total recorded during the period was 1.530 tons on
October 31, 2023.

No exceedances of the 2.25 tons per day total (Filterable + Condensable) PM10 limit was
recorded. Alarms are set for daily limits. Calculations were checked and the correct
emissions factors appear to be used.

II.B.1.h Tesoro shall notify the Director in writing within 30 days after the new ultra-low NOx burners
(II.A.3) and wet gas scrubber/LoTOx system (II.A.5) are installed and operational, as an initial
compliance inspection is required. To ensure proper credit when notifying the Director, send
your correspondence to the Director, Attn: Compliance Section.

Approval orders issued by the Director in accordance with the provisions of R307-401 will be
reviewed 18 months after the date of issuance to determine the status of construction,
installation, modification, relocation or establishment. If a continuous program of construction,
installation, modification, relocation or establishment is not proceeding, the Director may
revoke the approval order. [R307-401-18]

Status: In Compliance. The ultra-low NOx burners (II.A.3) and the wet gas scrubber
(II.A.5) are installed and notifications were made.

II.B.2 Requirements on the BCLR (loading rack)

II.B.2.a Total loading at the BCLR shall not exceed 1,460,000 barrels per 12-month rolling period.

The owner/operator shall keep a daily record of the material that is loaded. By the twentieth
day of each month, both a total of the previous month's loading and a summation of the
previous twelve (12) months totals shall be calculated. This summation shall serve as the total
per 12-month rolling period listed above. [R307-401-8(1)(a)]

Status: Not Applicable. The BCLR did not operate during the 12-month period
preceding this inspection.

II.B.2.b The owner/operator shall keep a record of the activated carbon replacements and the
occurrence and duration of alternative flaring control. [R307-401-8(1)(a)]

Status: Not Applicable. The BCLR is no longer operated. Since the time of the previous
inspection, no activated carbon replacements or instances of alternative flaring have
occurred.

II.B.3 Conditions on Crude Unit Furnace (H-101)

II.B.3.a Emissions of NOx shall not exceed 0.054 lb/MMBtu on a 3-hour average basis.

Compliance shall be demonstrated by means of annual NOx emissions testing as directed in 40
CFR 60 Appendix A, Test Method 7, 7A, 7B, 7C, 7D or 7E. [R307-401]

Status: In Compliance. Stack testing was last conducted May 8, 2024. Test results were
submitted to DAQ and audited in DAQC-669-24. DAQ calculated results for NOx were
0.045 lb/MMBtu.

II.B.4 Conditions on FCCU/CO Boiler and CO Boiler Bypass

II.B.4.a As of January 1, 2018, emissions of NOx and SO2 shall not exceed the following values:

1. 10 ppmvd NOx at 0% O2 on a 365-day rolling average basis
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2. 20 ppmvd NOx at 0% O2 on a 7-day rolling average basis

3. 10 ppmvd SO2 at 0% O2 on a 365-day rolling average basis

4. 18 ppmvd SO2 at 0% O2 on a 7-day rolling average basis

For the 365-day NOx and SO2 limits, the first complete 365-day rolling average shall be
calculated on January 1, 2019, based on monitoring data from January 1, 2019, and the 364
days prior to January 1, 2019.

NOx and SO2 emissions during periods of start-up, shutdown, or malfunction of the FCCU, or
malfunction of the associated NOx or SO2 control equipment, if any, shall not be used in
determining compliance with the 7-day NOx and SO2 limits established above provided that
during such periods Tesoro, to the extent practicable, maintains and operates the FCCU,
including associated air pollution control equipment, in a manner consistent with good air
pollution control practices for minimizing emissions. The 365-day NOx and SO2 limits shall
apply at all times.

Tesoro shall use NOx, SO2, and O2 CEMS to monitor performance of the FCCU. CEMS shall
be used to demonstrate compliance with the 7-day and 365-day NOx emission limits
established above. Tesoro shall make CEMS data available to UDAQ or EPA within thirty
(30) days of a written request. Tesoro shall install, certify, calibrate, maintain, and operate all
CEMS at the FCCU required by this paragraph in accordance with the provisions of 40 C.F.R.
§ 60.13 that are applicable to CEMS (excluding those provisions applicable only to COMS)
and Part 60 Appendices A and F, and the applicable performance specification test of 40
C.F.R. Part 60 Appendix B. [R307-401]

Status: Not Evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.

II.B.4.b By no later than January 1, 2018, Tesoro shall comply with an SO2 emission limit of 25 ppmvd
@ 0% excess air on a 365-day rolling average basis and 50 ppmvd @ 0% excess air on a 7-day
rolling average basis.

Compliance with this limit shall be determined by following 40 C.F.R. §60.105a(g). [SIP
Section IX.H.11.g.i ]

Status: Not Evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.

II.B.4.c By no later than January 1, 2018, Tesoro shall comply with an emission limit of 1.0 pounds
PM per 1000 pounds coke burned on a 3-hour average basis.

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. Stack tests shall be conducted
once every five (5) years.

By no later than January 1, 2019, each owner or operator of an FCCU shall install, operate,
and maintain a continuous parameter monitor system (CPMS) to measure and record operating
parameters for determination of source-wide PM2.5 emissions as appropriate. [SIP Section
IX.H.11.g.i]

Status: In Compliance. 40 CFR 60.104a(b) requires performance testing annually (SIP
IX.H.g.i.B.II requires stack testing every three years). Stack testing was last conducted
May 1, 2024, to determine compliance with the 1.0 lb/1000 lb coke burn off limit. Test
results were submitted to DAQ, and audited in DAQC-775-24. DAQ calculated results
averaged 0.364 lb/1000 lb.

13
Tesoro has an electrostatic precipitator (ESP) and wet gas scrubber installed, and is now
using the wet gas scrubber to meet emission limits and continuous parametric
monitoring system (CMPS) requirements. The most recent performance test was
conducted with the ESP depowered. As such, total power and secondary current
continuous parametric monitoring limits are both zero. Daily average exhaust coke
burn-off rate monitoring is required for units controlled by an ESP. This limit is still
monitored even though the ESP is not being used for compliance purposes. A
computerized trend line was observed during this inspection. Alarm set points notify
operators if the Subpart Ja limit is being approached.

For units controlled by a wet gas scrubber, Subpart Ja requires 3-hour pressure drop
and average liquid-to-gas ratio to not fall below the level established during the most
recent performance test (60.102a (c)(2)). These are monitored and recorded. Pressure
drop was 13.3” and liquid-to-gas ratio was 70.9 when checked during this inspection.

Tesoro has submitted Subpart Ja reports, which included monitor downtime and excess
emissions events, including details regarding each exceedance.

II.B.4.d By no later than October 1, 2015, Tesoro shall comply with the following CO limits at the
FCCU: (1) a short-term FCCU CO emission limit of 500 ppmvd CO @ 0% O2 (one-hour
block average); and (2) a long-term FCCU CO emission limit of 100 ppmvd CO @ 0% O2
(365-day rolling average). For 365-day CO emission limit, the first complete 365-day rolling
average shall be calculated on October 1, 2015, based on monitoring data from October 1,
2015, and the 364 days prior to October 1, 2015.

CO emissions during periods of startup, shutdown, or malfunction of the FCCU, or
malfunction of the associated CO control equipment, if any, shall not be used in determining
compliance with the short-term FCCU CO emission limit established above, provided that
during such periods Tesoro, to the extent practicable, maintains and operates the FCCU,
including associated air pollution control equipment, in a manner consistent with good air
pollution control practices for minimizing emissions. The long-term CO emission limit
established above, shall apply at all times.

Tesoro shall use a CO and O2 CEMS to monitor the performance of the FCCU. Tesoro shall
make CEMS data available to UDAQ or EPA within thirty (30) days of a written request.
Tesoro shall install, certify, calibrate, maintain, and operate all CEMS at the FCCU required
by this paragraph in accordance with the provisions of 40 C.F.R. § 60.13 that are applicable to
CEMS (excluding those provisions applicable only to COMS) and Part 60 Appendices A and
F, and the applicable performance specification test of 40 C.F.R. Part 60 Appendix B.
[R307-401]

Status: Not Evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.

II.B.4.e The FCCU Catalyst Regenerator is an "affected facility" as that term is used in 40 C.F.R. Part
60, Subparts A and J for PM, SO2, and CO. On and after October 1, 2015, until January 1,
2018, the FCCU Catalyst Regenerator shall continue to be subject to and shall comply with 40
C.F.R. Part 60, Subparts A and J for SO2. [40 CFR 60 Subpart J]

Status: Not Evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.

II.B.4.f Beginning on October 1, 2015, the FCCU shall become an "affected facility" as that term is
used in 40 C.F.R. Part 60, Subpart Ja for PM and CO in lieu of Subpart J. Beginning on
14
January 1, 2018, the FCCU shall become an "affected facility" as that term is used in 40
C.F.R. Part 60, Subpart Ja for NOx, and Subpart Ja for SO2 in lieu of Subpart J. On and after
January 1, 2018, Tesoro shall comply with all applicable requirements in 40 C.F.R. Part 60,
Subpart Ja at the FCCU. [40 CFR 60 Subpart J, 40 CFR 60 Subpart Ja]

Status: Not Evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.

II.B.5 Conditions on SRU/TGI/TGTU

II.B.5.a Gaseous emissions from the SRU shall be treated by the TGTU during normal operations prior
to final treatment at the TGI. [R307-401-8]

Status: In Compliance. Gaseous emissions from the SRU are treated by the TGTU
during normal operations prior to final treatment at the TGI.

II.B.5.b The SO2 emissions from the SRU/TGI/TGTU will be limited to 1.68 tpd for up to 21 days per
rolling 12-month period, and will be limited to 0.69 tpd for the remainder of the rolling 12-
month period. Compliance with the daily limitation shall be determined as follows:

Daily sulfur dioxide emissions from the SRU/TGI/TGTU shall be determined by multiplying
the SO2 concentration in the flue gas by the mass flow of the flue gas.

Emissions of SO2 from the SRU/TGI/TGTU shall not exceed 60 tons per rolling 12-month
period. Compliance shall be determined on a 12-month rolling total. Within 20 days of the
beginning of each calendar month, the SO2 emission totals calculated to demonstrate
compliance with the daily limitations shall be totaled for the previous month. The monthly
total shall be added to the totals from the previous 11 months to determine the new 12-month
rolling total. [R307-401]

II.B.5.b.1 The SO2 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. Daily zero
(0-20% of span value) and span (50-100% of span value) calibration drift tests shall be
conducted in accordance with UAC R307-170. Quarterly cylinder gas audits and an annual
relative accuracy test audit shall be conducted in accordance with the procedures outlined in
UAC R307-170. 40 CFR 60 Methods 2, 3 and 6 shall be used to determine relative accuracy.
If a new monitor is installed, an initial performance specification test shall be performed
within 30 days of installation. The performance specification test shall be conducted and data
reduced in accordance with the test methods and procedures contained in 40 CFR 60,
Appendix B, Performance Specification 2. Notification must be made to the Director prior to
conducting the performance specification 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.

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 60 Appendix B. An annual
relative accuracy test audit shall be conducted in accordance with the procedures outlined in
UAC R307-170 and 40 CFR 60 Appendix B. If a new volumetric flow measurement device is
installed, an initial performance specification test shall be performed within 30 days of
installation. The performance specification test shall be conducted and data reduced in
accordance with the test methods and procedures contained in 40 CFR 52 Appendix E.
Notification must be made to the Director prior to conducting the performance specification
test.

Tesoro shall comply with a 95% recovery efficiency requirement for all periods of operation
except during periods of startup, shutdown, or malfunction of the SRU/TGI/TGTU. The 95%
recovery efficiency will be determined on a daily basis; however, compliance will be
determined on a rolling 30-day average basis. Tesoro shall determine the percent recovery by
15
measuring the flow rate and concentration of H2S in the feed streams going to the SRU and by
measuring the SO2 emissions with the CEMS at the SRU incinerator. The feed streams shall
include the overhead stream from the Fuel Gas Desulfurization unit (Amine unit) regenerator
and the overhead stream from the Sour Water Stripper. The flow rate will be determined
continuously; the H2S concentration shall be determined at least once every three (3) years
(samples may be collected as manual grabs or through remote monitoring). The flow rate and
H2S concentration values will be used to determine the daily feed rate. SRU efficiency results
shall be reported to the Director a minimum of once per year. [R307-401]

Status: In Compliance with SRU efficiency results reporting. CEM requirements are
evaluated by DAQ’s CEM specialist. No exceedances of the daily and 12-month limits
were discovered during this inspection. The most recent Annual SRU Efficiency Report
was received on July 9, 2024.

II.B.6 Conditions on SO2 Cap Sources

II.B.6.a Combined emissions of SO2 from the SO2 Cap Sources shall not exceed the following limits:

November 1 through end of February: 3.699 tons/day

March 1 through October 31: 4.374 tons/day

Compliance with the daily limitation shall be determined by summing the emissions calculated
in conditions II.B.6.a.1 and II.B.6.a.2. [R307-401]

II.B.6.a.1 Daily SO2 emissions from the FCCU/CO Boiler stack shall be determined by multiplying the
sulfur dioxide concentration in the flue gas by the mass flow of the flue gas.

The SO2 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
span shall be 350 ppm. No later than January 1, 2018 the span shall be 200 ppm. Daily zero (0-
20% of span value) and span (50-100% of span value) calibration drift tests shall be conducted
in accordance with 40 CFR 60, Appendix F and UAC R307-170. Quarterly cylinder gas audits
and an annual relative accuracy test audit shall be conducted in accordance with 40 CFR 60
Appendix F and UAC R307-170. 40 CFR 60 Methods 2, 3 and 6 shall be used to determine
relative accuracy. If a new SO2 monitor is installed, an initial performance specification test
shall be performed within 30 days of installation. The performance specification test shall be
conducted and data reduced in accordance with the test methods and procedures contained in
40 CFR 60, Appendix B, Performance Specification 2. Notification must be made to the
Director prior to conducting the performance specification test. Whenever the SO2 CEM is
unavailable for short periods (i.e. CO boiler or CO Boiler emergency bypass, FCCU start-up
and shutdowns), SO2 CEM data from the previous three (3) days will be averaged and used as
an emission factor to determine emissions from the FCCU.

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 60 Appendix B. An annual
relative accuracy test audit shall be conducted in accordance with the procedures outlined in
UAC R307-170 and 40 CFR 60 Appendix B. If a new volumetric flow measurement device is
installed, an initial performance specification test shall be performed within 30 days of
installation. The performance specification test shall be conducted and data reduced in
accordance with the test methods and procedures contained in 40 CFR 52 Appendix E.
Notification must be made to the Director prior to conducting the performance specification
test. [R307-401]

II.B.6.a.2 Daily SO2 emissions from other affected units shall be determined by multiplying the quantity
of each fuel used daily (24 hour usage) at each affected unit by the appropriate emission factor
below. The values shall be summed to show the total daily SO2 emission.

16
Emission factors (EF) for the various fuels shall be as follows:

Natural gas: EF = 0.60 lb/MMscf
Propane: EF = 0.60 lb/MMscf
Plant fuel gas: the emission factor shall be calculated from the H2S measurement or from the
SO2 measurement obtained in section II.B.6.g of this permit. The emission factor, where
appropriate, shall be calculated as follows:

EF (lb SO2/MMscf gas) = [(24 hr avg. ppmdv H2S) /10^6] [(64 lb SO2/lb mole)] [(10^6
scf/MMscf)/(379 scf/lb mole)]

Where mixtures of fuel are used in a Unit, the above factors shall be weighted according to the
use of each fuel. [R307-401]

Status: These source cap limits are no longer applicable. New SIP limits have changed
and are now year round limits instead of the different winter time and rest of year limits.
SIP source cap limits were evaluated under Condition II.B.1.g above. CEM requirements
are audited by DAQ’s CEM specialist.

II.B.6.b Emissions of SO2 from the permitted source shall not exceed 1,637 tons per rolling 12-month
period. The SOx limit at the FCCU is 705 tons per rolling 12-month period.

Compliance shall be determined on a 12-month rolling total. Within 20 days of the beginning
of each calendar month, the SO2 emission totals calculated to demonstrate compliance with the
daily (24-hr) limitations shall be totaled for the previous month. The monthly total shall be
added to the totals from the previous 11 months to determine the new 12-month rolling total.
[R307-401]

Status: These source cap limits are no longer applicable. New SIP limits have changed
and are now year round limits instead of the different winter time and rest of year limits.
SIP source cap limits were evaluated under Condition II.B.1.g above.

II.B.6.c Until January 1, 2018, the SOx emissions from the FCCU regenerator shall not exceed 9.8
lbs/1000 lbs coke burned, based on a 7-day average.

The following monitoring protocol has been approved by EPA staff in accordance with 40
CFR 60.106(i)(12), in letters from EPA dated August 29, 1997, May 12, 2003, June 20, 2005
and August 8, 2008, and may not be modified without prior EPA approval. [40 CFR 60
Subpart J]

II.B.6.c.1 Until January 1, 2018, each day, the daily SOx emissions from the FCCU regenerator, as
calculated below, shall be multiplied by a factor of 1.05 and divided by the amount of coke
burned in the FCCU regenerator during the same period. The result shall be added to the
calculated values for the previous 6 days and the total divided by 7 to determine the 7-day
average.

The weight of coke burned in the FCCU regenerator shall be determined by a mass balance
calculation utilizing the measured airflow to the regenerator, and the volume percent CO and
O2 measured in the regenerator flue gas, in accordance with the procedure documented in
correspondence to the DAQ dated November 3, 1995.

This monitoring method is valid only if the following process conditions and procedures are
met.

(a) Sulfur content of the feed to the FCCU is not greater than 0.85 wt%, based on
a 7-day average.

The sulfur content of the feed shall be determined by obtaining and analyzing
17
a minimum of 3 grab-samples per 7day period.

(b) Temperature of the FCCU regenerator is between 1182 °F and 1419 °F, based
on an 8-hour average.

The temperature of the FCCU regenerator shall be determined using a suitable
temperature-sensing device. The device shall be calibrated according to
manufacturer's specifications.

(c) The oxygen concentration in the FCCU regenerator is less than or equal to 3.4
% by volume, based on an 8-hour average.

A CEM shall be used to determine the oxygen concentration in the regenerator
flue gas. The monitor shall meet or exceed the requirements specified in 40
CFR 60, Appendix B, and Performance Specification 3. The monitor span
shall be 1.5-2.0 times the allowable level. Daily zero (0-20% of span value)
and span (50-100% of span value) calibration drift tests shall be conducted in
accordance with UAC R307-170. Quarterly cylinder gas audits and an annual
relative accuracy test audit shall be conducted in accordance with the
procedures outlined in UAC R307-170. 40 CFR 60 Method 3B shall be used
to determine relative accuracy. If a new monitor is installed, an initial
performance specification test shall be performed within 30 days of
installation. The performance specification test shall be conducted and data
reduced in accordance with the test methods and procedures contained in 40
CFR 60, Appendix B, and Performance Specification 3. Notification must be
made to the Director prior to conducting the performance specification test.

(d) The CO concentration in the FCCU regenerator is less than or equal to 4.4%
by volume based on an 8-hour average.

A CEM shall be used to determine the CO concentration in the regenerator
flue gas. The monitor shall meet or exceed the requirements specified in 40
CFR 60, Appendix B, and Performance Specification 4, and 40 CFR 60,
Appendix F. The monitor span shall be 1.5-2.0 times the allowable level.
Daily zero (0-20% of span value) and span (50-100% of span value)
calibration drift tests shall be conducted in accordance with UAC R307-170.
Quarterly cylinder gas audits and an annual relative accuracy test audit shall
be conducted in accordance with the procedures outlined in UAC R307-170.
40 CFR 60 Method 10 or 10A shall be used to determine relative accuracy. If
a new monitor is installed, an initial performance specification test shall be
performed within 30 days of installation. The performance specification test
shall be conducted and data reduced in accordance with the test methods and
procedures contained in 40 CFR 60, Appendix B, and Performance
Specification 4. Notification must be made to the Director prior to conducting
the performance specification test.

If Tesoro intentionally changes the FCCU's operating parameters (FCCU's feed sulfur content,
the regenerator temperature, the regenerator oxygen concentration, or the regenerator CO
concentration) to a value outside the listed ranges, compliance with the sulfur oxides limitation
shall be demonstrated in accordance with 40 CFR 60.106(i). Performance of such compliance
demonstrations shall begin within two (2) weeks of first recording the change in operating
parameters.

Tesoro may then conduct performance tests as required to establish a new set of parameters for
the above alternate monitoring procedure, in accordance with 40 CFR 60.106(i)(12). Tesoro
must submit the new parameters and associated test data for approval by the EPA before use.

An unintentional variation of any of the operating parameters associated with this monitoring
18
method beyond the range allowed by this method shall constitute a violation of this monitoring
condition, unless the variation can be positively identified as the result of an unavoidable
breakdown. [40 CFR 60 Subpart J, R307-401]

Status: No longer applicable.

II.B.6.d Until January 1, 2018, the following information shall be maintained and made available upon
request:

1. The monitoring record of the lbs SOx /1000 lb coke burned

2. Results of the sulfur analysis of the feed, including sample dates, times, and
sulfur concentration

3. The monitoring record of the temperature sensor, the date of each calibration
of the sensor and any corrective actions required or performed

4. The monitoring record of the oxygen CEM and any calibration or maintenance
activity on the monitor

5. The monitoring record of the CO CEM and any calibration or maintenance
activity on the monitor

6. The date, time, and description of any change in the listed FCCU operating
parameters, whether or not such change was intentional

7. All information associated with the performance of 40 CFR 60.106(i)(12),
Compliance Demonstration, if such demonstration is performed.

[40 CFR 60 Subpart J, R307-401]

II.B.6.e Until January 1, 2018, if any of the listed operating parameters are intentionally changed,
Tesoro shall submit written notification of the change and confirmation of the initiation of the
40 CFR 60.106(i)(12), Compliance Demonstration, within 14 days of first recording the
change. The notification shall be submitted to the Director and to EPA.

If any of the listed operating parameters are unintentionally exceeded, Tesoro shall submit a
report of the exceedance to the Director on the next quarterly monitoring report. The report
shall include a description of the exceedance, an estimate of any excess emissions, the time of
the exceedance, and the actions taken to correct the situation. [40 CFR 60 Subpart J, R307-
401]

Status: No longer applicable.

II.B.6.f Until January 1, 2019, the following sources shall not be regulated for SO2 or NOx emissions
nor shall they be included in the emission limitation totals herein:

1. North flare (FCCU/VRU/GHT/Alky Flare)

2. South flare (Crude/UFU/DDU Flare)

[R307-401, SIP Section IX.H.12]

Status: No longer applicable.

II.B.6.g The H2S content of fuel gas combusted at any affected unit shall not exceed 0.10 grains
H2S/dscf (162 ppmdv), based on a rolling 3-hour average. Compliance with this limitation
shall be determined as follows:
19
1. For natural gas, compliance is assumed while the fuel comes from a public
utility.

2. For plant gas, the H2S content of the fuel gas shall be measured with a CMS
that meets or exceeds the requirements contained in 40 CFR 60, Appendix B,
Specification 7. The monitor shall be installed in a location representative of
the H2S content in the fuel gas system. The location shall be approved in
writing by the Director prior to installation. The current approved location of
the H2S monitor is on the outlet of fuel-gas blending vessel V-917. The span
of the monitor shall be 300 ppm. Daily zero (0-20% of span value) and span
(50-100% of span value) calibration drift tests shall be conducted in
accordance with 40 CFR 60 Appendix F and UAC R307-170. Quarterly
cylinder gas audits and an annual relative accuracy test audit shall be
conducted in accordance with 40 CFR 60 Appendix F and UAC R307-170.
40 CFR 60 Method 11 shall be used to determine relative accuracy. If a new
monitor is installed, an initial performance specification test shall be
performed within 30 days of installation. The performance specification test
shall be conducted and data reduced in accordance with the test methods and
procedures contained in 40 CFR 60, Appendix B, and Performance
Specification 7. Notification must be made to the Director prior to conducting
the performance specification test.

If the monitor reading is not available, the refinery fuel gas shall be sampled
as close to the monitor location as safely possible at least once each day. The
sample shall be analyzed for sulfur content with a detection tube capable of
reading the required concentration limit.

3. In lieu of the H2S CMS in paragraph II.B.6.g.2 above, for fuel gas combustion
devices an instrument for continuously monitoring and recording the
concentration by volume (dry basis, zero percent excess air) of SO2 emissions
into the atmosphere may be used. The monitor shall meet the requirements of
40 CFR 60.105.

4. The rolling three-hour average shall be calculated as the arithmetic average of
three (3) contiguous one-hour averages.

[40 CFR 60 Subpart J, R307-401]

Status: In Compliance. CEM requirements are audited by DAQ’s CEM specialist.
Quarterly RATAs are conducted and DAQ audit memorandums of these tests are kept in
the main source files. The alternate listed in 3 is not being used.

II.B.6.h T-104 shall be a fixed-roof vessel with closed vent controls. The tank shall have a closed-vent
system with nitrogen purge, and shall vent gases as required by NSPS Kb and/or the approved
Control Device Operating Plan per 60.113b(c). The tank shall comply with 40 CFR 60 Subpart
Kb. [40 CFR 60 Subpart Kb, R307-401]

Status: Tank T-104 has been decommissioned and replaced by Tank T-103.

II.B.7 Conditions on NOx Cap Sources

II.B.7.a Combined emissions of NOx from the NOx Cap Sources shall be no greater than 1.988
tons/day.

Compliance shall be determined daily 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 listed below, and summing the results. The sources, fuels, and associated emission
factors for this limitation are as follows:
20
Sources included in emission cap Fuel NOx Emission factor

Crude Unit Furnace (H-101) Plant Gas results of last stack test
Ultraformer Furnace (F1) Plant Gas results of last stack test
Regenerator Gas Heater (F15) Plant Gas 81 lb/MMscf
FCCU/CO Boiler FCU Coke & plant gas NOx CEM
DDU charge heater (F-680) Plant gas 0.049 lb/MMBtu
DDU rerun reboiler (F-681) Plant gas 0.052 lb/MMBtu
Cogeneration facility Plant & natural gas results of last stack test
GHT heater (F-701) Plant gas 0.074 lb/MMBtu
Hydrogen Compressors (K1s) Propane/natural gas 1.8 lb/hr

The UFU stack (F1) shall be tested once every calendar year to determine the correct emission
factor for the calculations above.

The initial stack tests were done on the DDU to verify the design emission factor of 0.04
lb/MMBtu for NOx. The new emission factors for the DDU, computed from the results of the
stack tests, are 0.049 lb/MMBtu and 0.052 lb/MMBtu as specified in the above table.
Subsequent testing shall be performed if directed by the Director.

Both trains in the cogeneration facility were stack tested within 180 days of startup to show
emissions equivalency of the trains. Subsequently, both trains shall be tested either
simultaneously or seriatim at least once every two (2) years.

The GHT heater was stack tested within 180 days of startup. Subsequent testing shall be
performed if directed by the Director.

All other units in the above list shall be stack-tested if directed by the Director. Tesoro may
also perform a stack test on any of the above listed sources to provide information for updating
the emission factors listed.

All stack tests shall conform to the following:

Notification: The Director shall be notified at least 30 days prior to conducting any required
emission testing. If directed by the Director, a pretest conference shall be held prior to the test.

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.

40 CFR 60, Appendix A, Method 7, 7A, 7B, 7C, 7D, or 7E shall be used to determine the NOx
emission rate.

40 CFR 60, Appendix A, Method 2 shall be used to determine the volumetric flow rate.
To determine mass emission rates (lbs/hr, etc.), the pollutant concentration, as determined by
the appropriate methods above, shall be multiplied by the volumetric flow rate and any
necessary conversion factors determined by the Director to give the results in the specified
units of the emission limitation.

A NOx CEM shall be used to calculate daily NOx emissions from the FCCU/CO Boiler.
Emissions shall be determined by multiplying the nitrogen dioxide concentration in the flue
gas by the mass flow of the flue gas.

The NOx 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. Daily zero
(0-20% of span value) and span (50-100% of span value) calibration drift tests shall be
conducted in accordance with UAC R307-170. Quarterly cylinder gas audits and an annual
relative accuracy test audit shall be conducted in accordance with the procedures outlined in
21
UAC R307-170. 40 CFR 60 Methods 2, 3 and 7 shall be used to determine relative accuracy.
If a new monitor is installed, an initial performance specification test shall be performed
within 30 days of installation. The performance specification test shall be conducted and data
reduced in accordance with the test methods and procedures contained in 40 CFR 60,
Appendix B, Performance Specification 2. Notification must be made to the Director prior to
conducting the performance specification 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.

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 60 Appendix B. An annual
relative accuracy test audit shall be conducted in accordance with the procedures outlined in
UAC R307-170 and 40 CFR 60 Appendix B. If a new volumetric flow measurement device is
installed, an initial performance specification test shall be performed within 30 days of
installation. The performance specification test shall be conducted and data reduced in
accordance with the test methods and procedures contained in 40 CFR 60 Appendix B.
Notification must be made to the Director prior to conducting the performance specification
test. [R307-401]

Status: In Compliance. See condition II.B.1.g above for current cap source limits. Stack
testing of H101 was last conducted on May 8, 2024. See condition II.B.3.a above for
H-101 stack testing results. Stack testing of F1 was last conducted May 7, 2024. Test
results were submitted to DAQ and audited in DAQC-669-24. DAQ calculated results for
NOx were 0.034 lb/MMBtu. Stack testing of the cogeneration plant was last conducted on
September 6-7, 2022. Test results were submitted to DAQ and audited in DAQC-1573-22.
DAQ calculated results for NOx were 12.3 lb/hr from the east cogen and 16.8 lb/hr from
the west cogen.

CEMs are installed. Quarterly reports are submitted. Quarterly reports are reviewed by
DAQ’s CEM specialist. A spreadsheet is kept to track NOx emissions from all sources.
No exceedances were recorded.

II.B.7.b Emissions of NOx from the sources listed under the NOx cap shall be no greater than 598 tons
per rolling 12-month period. The NOx limit at the FCCU is 174 tons per rolling 12-month
period.

Compliance shall be determined on a 12-month rolling total. By the 20th day of each month,
the NOx emissions calculated to show compliance with the daily limitations for the previous
month shall be summed to give a monthly emission total. This shall be added to the previous
11 months' emission totals to give the new 12-month rolling total. [R307-401]

Status: No longer applicable. See Condition II.b.1.g above for most current NOx cap
source emissions.

II.B.7.c Emissions of NOx from each K1 compressor shall be no greater than 3.20 lb/hr or 933 ppmdv
@10% oxygen and 400°F.

Compliance shall be determined by stack testing in accordance with the procedure for stack
testing other NOx sources as described above. Testing shall be done if directed by the Director.

The maximum fired heat capacity at H-101will be no greater than 174 MMbtu/hr (LHV) based
on a 1-hour average. Orifice plate will be installed to limit fuel gas pressure to 20 psi such that
maximum firing rate of the burner remains unchanged. [R307-401]

Status: In Compliance. Stack testing was conducted on December 9, 1993. Stack test
results were 1.7 lb/hr for the K1 compressor and 1.9 lb/hr for the K2 compressor. The
22
company has not been directed to retest these units since the initial testing was
conducted. The H101 orifice plate was installed during the March 2010 turnaround, and
1-hour averages are shown on the area control board with an alarm set at 10% below the
limit. The maximum fired heat capacity was not being exceeded during this inspection.

II.B.8 Conditions on PM10 Cap Sources

II.B.8.a Combined emissions of filterable PM10 and filterable PM2.5 from the PM10 Cap Sources shall
be no greater than 522 lbs/day. The filterable PM10 limit at the FCCU is 69 tons per rolling 12-
month period.

Compliance shall be determined daily by multiplying the quantity of each fuel combusted at
the affected units by the associated emission factor for that fuel, and summing the results . The
emission factors for this limitation are as follows:

Natural gas: 5 lb/MMscf
Plant gas: 5 lb/MMscf
Cat Coke: results of last stack test
Propane: negligible

The FCCU/COB stack shall be stack tested every year to determine the correct emission factor
for the calculations above. All other units in the above list shall be stack-tested if directed by
the Director. The permitted source may also perform a stack test to provide information for
updating the emission factors listed above. All stack tests shall conform to the following:

Notification: The Director shall be notified at least 30 days prior to conducting any required
emission testing. If directed by the Director, a pretest conference shall be held prior to the test.
The emission point shall conform to the requirements of 40 CFR 60, Appendix A, Method 1.
OSHA approved access shall be provided to the test location. The throughput rate during
compliance testing shall be no less than 90% of the rated throughput, or 90% of the highest
monthly throughput achieved in the previous three (3) years, whichever is least.

40 CFR 51, Appendix M, Methods 201 or 201a shall be used to determine front-half PM10
emissions in stacks in which no liquid drops are present. 40 CFR 51, Appendix M, Method
202 shall be used to determine back half condensables in such stacks.

For stacks in which liquid drops are present, methods to eliminate the liquid drops should be
explored. If no reasonable method to eliminate the drops exists, then the following methods
shall be used: 40 CFR 60, Appendix A, Method 5, 5a, 5d, or 5e as appropriate. The back half
condensables shall also be tested using Method 202. All particulate captured in the back half
shall be considered PM10. For purposes of the PM10 SIP Cap, the back half condensables shall
not be used for compliance demonstration but shall be used for inventory purposes.

40 CFR 60, Appendix A, Method 2 shall be used to determine the volumetric flow rate.

To determine mass emission rates (lbs/hr, etc.), the pollutant concentration, as determined by
the appropriate methods above, shall be multiplied by the volumetric flow rate and any
necessary conversion factors determined by the Director to give the results in the specified
units of the emission limitation. [R307-401]

Status: In Compliance. PM10 emissions from the FCCU were 7 tons during the
12-month period ending August 31, 2024. The source cap limit is no longer applicable.
See Condition II.b.1.g above for most current PM10 cap source emissions.

II.B.9 Conditions on Tanks

II.B.9.a For the primary seals, the accumulated area of gaps between the tank wall and the metallic
23
shoe seal or the liquid-mounted seal shall not exceed 10 square inches per foot of tank
diameter. The width of any portion of any gap shall not exceed 1 1/2 inches. If the seal is a
vapor mounted seal, the accumulated area of gaps between the tank wall and seal shall not
exceed one square inch per foot of tank diameter, and the width of any portion of any gap shall
not exceed one-half inch. This condition applies to Tanks 242, 243, 246, 247, 308, 309, 326,
and 330. [R307-327]

Status: In Compliance. Inspections have been performed and semi-annual reports
submitted. Half of the semi-annual inspections are performed in the spring and the other
half in the fall. Annual measurement inspections are performed in the spring and fall to
alternate with the semi-annual inspections.

II.B.9.b Tanks 246 and 247 shall be used only to store heavy distillate products with a True Vapor
Pressure (TVP) of less than 1.5 psia, such as Jet A fuel. [R307-401-8]

Status: In Compliance. At the time of this inspection, Tanks 246 and 247 were used to
store LSD fuel.

II.B.9.c For the secondary seals, the accumulated area of gaps between the tank wall and the secondary
seal shall not exceed one square inch per foot of tank diameter and the width of any portion of
any gap shall not exceed one-half inch. This condition applies to Tanks 242, 243, 308, 309,
326, and 330. This condition does not apply to Tanks 246 and 247.

The secondary seals shall be properly installed and maintained according to the manufacturer's
recommendations. [R307-327]

Status: In Compliance. Inspections have been performed and semi-annual reports
submitted.

II.B.9.d The owner/operator shall comply with all applicable parts of R307-327 - Petroleum Liquid
Storage. [R307-327]

Status: In Compliance. Compliance with applicable subparts of R307-327 are
determined as follows:

UAC R307-327
R307-327-4. General Requirements.
(1) Any existing stationary storage tank, reservoir or other container with a
capacity greater than 40,000 gallons (150,000 liters) that is used to store
volatile petroleum liquids with a true vapor pressure greater than 10.5 kilo
pascals (kPa) (1.52 psia) at storage temperature shall be fitted with control
equipment that will minimize vapor loss to the atmosphere. Storage tanks,
except those erected before January 1, 1979, which are equipped with external
floating roofs, shall be fitted with an internal floating roof that shall rest on the
surface of the liquid contents and shall be equipped with a closure seal or seals
to close the space between the roof edge and the tank wall, or alternative
equivalent controls, provided the design and effectiveness of such equipment
is documented and submitted to and approved by the executive secretary. The
owner or operator shall maintain a record of the type and maximum true vapor
pressure of stored liquid.
Status: In Compliance. Tank ESP is used to track and record products kept in tanks,
24
throughput, and storage conditions. Tesoro maintains records of roof types, liquid
contents, and maximum true vapor pressure of petroleum liquids stored inside tanks.
Tanks in service with internal floating roofs are designated as 103, 140, 186, 188, 190,
241, 244, 245, 248, 297, 321, 331, 402, 412, 413, 414, 503, and 504. Tank 297 is out of
service and being converted to an internal floating roof.

(2) The owner or operator of a petroleum liquid storage tank not subject to (1)
above, but containing a petroleum liquid with a true vapor pressure greater
than 7.0 kPa (1.0 psia), shall maintain records of the average monthly storage
temperature, the type of liquid, throughput quantities, and the maximum true
vapor pressure.

Status In Compliance. Tesoro maintains records of the storage temperature, the type of
liquid, throughput quantities, and the maximum true vapor pressure for all tanks.
R307-327-5. Installation and Maintenance.
(1) The owner or operator shall ensure that all control equipment on storage
vessels is properly installed and maintained.
(a) There shall be no visible holes, tears or other openings in any seal or seal
fabric and all openings, except stub drains, shall be equipped with covers, lids,
or seals.
(b) All openings in floating roof tanks, except for automatic bleeder vents, rim
space vents, and leg sleeves, shall provide a projection below the liquid
surface.
(c) The openings shall be equipped with a cover, seal, or lid.
(d) The cover, seal, or lid is to be in a closed position at all times except when
the device is in actual use.
(e) Automatic bleeder vents shall be closed at all times except when the roof is
floated off or landed on the roof leg supports. Rim vents shall be set to open
when the roof is being floated off the leg supports or at the manufacturer's
recommended setting.
(f) Any emergency roof drain shall be provided with a slotted membrane
fabric cover or equivalent cover that covers at least 90 percent of the area of
the opening.
(2) The owner or operator shall conduct routine inspections from the top of the
tank for external floating roofs or through roof hatches for internal floating
roofs at six month or shorter intervals to insure there are no holes, tears, or
other openings in the seal or seal fabric.
(a) The cover must be uniformly floating on or above the liquid and there
must be no visible defects in the surface of the cover or petroleum liquid
25
accumulated on the cover.
(b) The seal(s) must be intact and uniformly in place around the circumference
of the cover between the cover and tank wall.
(3) A close visible inspection of the primary seal of an external floating roof is
to be conducted at least once per year from the roof top unless such inspection
requires detaching the secondary seal, which would result in damage to the
seal system.
(4) Whenever a tank is emptied and degassed for maintenance, an emergency,
or any other similar purpose, a close visible inspection of the cover and seals
shall be made.
(5) The executive secretary must be notified 7 days prior to the refilling of a
tank that has been emptied, degassed for maintenance, an emergency, or any
other similar purpose. Any non-compliance with this rule must be corrected
before the tank is refilled.
Status: In Compliance. Tesoro conducts and records semi-annual rooftop seal
inspections for holes, tears, and gaps, and the presence of liquids on top of floating roofs.
Close visible inspections of primary seals on external floating roofs are conducted
annually and whenever tanks are emptied. Tesoro has sent notifications to DAQ when
emptied tanks are being refilled. Openings in the floating roofs provide projections below
the liquid surface. Roof openings are fixed with a cover, seal, or lid, and company policy
is to keep these in a closed position when not in use. Some covers are fitted with gaskets
or seals to meet NSPS requirements.
R307-327-6. Retrofits for Floating Roof Tanks.
(1) Except where specifically exempted in (3) below, all existing external
floating roof tanks with capacities greater than 950 barrels (40,000 gals) shall
be retrofitted with a continuous secondary seal extending from the floating
roof to the tank wall (a rim-mounted secondary seal) if:

(a) The tank is a welded tank, the true vapor pressure of the contained liquid is
27.6 kPa (4.0 psia) or greater and the primary seal is one of the following:

(i) A metallic type shoe seal, a liquid-mounted foam seal, a liquid-mounted
liquid-filled seal, or

(ii) Any other primary seals that can be demonstrated equivalent to the above
primary seals.

(b) The tank is a riveted tank, the true vapor pressure of the contained liquid is
10.5 kPa (1.5 psia) or greater, and the primary seal is as described in (a)
above.

(c) The tank is a welded or riveted tank, the true vapor pressure of the
contained liquid is 10.5 kPa (1.5 psia) or greater and the primary seal is vapor-
26
mounted. When such primary seal closure device can be demonstrated
equivalent to the primary seals described in (a) above, these processes apply.

(2) The owner or operator of a storage tank subject to this rule shall ensure
that all the seal closure devices meet the following requirements:

(a) There shall be no visible holes, tears, or other openings in the seals or seal
fabric.

(b) The seals must be intact and uniformly in place around the circumference
of the floating roof between the floating roof and the tank wall.

(c) For vapor mounted primary seals, the accumulated area of gaps between
the secondary seal and the tank wall shall not exceed 21.2 cm2 per meter of
tank diameter (1.0 in2 per ft. of tank diameter) and the width of any gap shall
not exceed 1.27 cm (1/2 in.). The owner or operator shall measure the
secondary seal gap annually and make a record of the measurement.

(3) The following are specifically exempted from the requirements of (1)
above:

(a) External floating roof tanks having capacities less than 10,000 barrels
(420,000 gals) used to store produced crude oil and condensate prior to
custody transfer.

(b) A metallic type shoe seal in a welded tank that has a secondary seal from
the top of the shoe seal to the tank wall (a shoe mounted secondary seal).

(c) External floating roof tanks storing waxy, heavy pour crudes.

(d) External floating roof tanks with a closure seal device or other devices
installed that will control volatile organic compounds (VOC) emissions with
an effectiveness equal to or greater than the seals required in (1) above. It shall
be the responsibility of the owner or operator of the source to demonstrate the
effectiveness of the alternative seals or devices to the executive secretary. No
exemption under (3) shall be granted until the alternative seals or devices are
approved by the executive secretary.

Status: In Compliance. The following tanks are equipped with external floating roofs:
144, 241, 242, 243, 246, 247, 252, 298, 307, 308, 324, 325, 326, 327, 328, 330, 405, 421, 422,
423, 424, 431, and 432. Tank 144 is out of service, and Tank 241 has been demolished and
a replacement tank is being constructed. These tanks are all equipped with primary and
secondary seals. Secondary seals are inspected semi-annually for gaps, tears, and holes.
Primary seals are inspected every five years or whenever tanks are emptied and refilled.

27
Approval Order DAQE-AN103350081A-21, dated January 12, 2021 (Refinery)

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 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. Limits set forth in this AO have not been exceeded.

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. Only approved modifications have been made. Tank 103 has
been constructed. A construction notification was received February 16, 2022. A seal
inspection notification and a post-fill notification has been received.

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. Records were made available upon request. Records have been
kept for a minimum of five years.

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 plant appeared to be maintaining and operating the emission
units, including associated air pollution control equipment, in a manner consistent with
good air pollution control practices for minimizing emissions. Maintenance activities are
documented using manual documentation and a computerized tracking program (SAP).

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

Status: In Compliance. Breakdown reports have been submitted as required.

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.

28
I.8 The owner/operator shall submit documentation of the status of construction or modification to
the Director within 18 months from the date of this AO. This AO may become invalid if
construction is not commenced within 18 months from the date of this AO or if construction is
discontinued for 18 months or more. To ensure proper credit when notifying the Director, send
the documentation to the Director, attn.: NSR Section. [R307-401-18]

Status: In Compliance. A construction notification was received February 16, 2022.

SECTION II: PERMITTED EQUIPMENT

II.A THE APPROVED EQUIPMENT

II.A.1 Fuel Gas Treatment and Sulfur Recovery
Includes the following systems/equipment

II.A.2 SRU/TGI/TGTU
Sulfur Recovery Unit/Tail Gas Incinerator/Tail Gas Treatment Unit,
Identifier: PS #10

II.A.3 FGDU/SWS
Fuel Gas Desulfurization Unit/Sour Water Stripper (FGDU/SWS) Flare (this unit is physically
integrated with the Sulfur Recovery Unit (SRU)),
Identifier: PS #11

II.A.4 T-103 (NEW)
Sour Water Storage Tank
Capacity: 8,250 bbl

II.A.5 T-104
Sour Water Storage Tank
Capacity: 3,500 bbl

Status: In Compliance. No unapproved equipment was observed during this inspection.

SECTION II: SPECIAL PROVISIONS

II.B REQUIREMENTS AND LIMITATIONS

II.B.1 Sulfur Recovery, Fuel Gas Desulfurization and Sour Water Stripping

II.B.1.a The owner/operator shall comply with the requirements of 40 CFR 60.590a to 60.593a.

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: In Compliance. Tesoro monitors components for leaks under Subpart GGGa
requirements, or more stringent requirements of their consent decree with USEPA. See
status of LDAR requirements under Subpart GGGa, VVa, and UAC R307-326 sections of
this memorandum.

II.B.2 Conditions on the SRU/TGI/TGTU

29
II.B.2.a The owner/operator shall control the sulfur pit emissions by routing sulfur pit emissions to the
incinerator at the SRU. [R307-401-8]

Status: In Compliance. Sulfur pit emissions are routed to the incinerator at the SRU.
Design diagrams are available upon request.

II.B.2.b Gaseous emissions from the SRU shall be treated by the TGTU during normal operations prior to
final treatment at the TGI. [R307-401-8]

Status: In Compliance. Gaseous emissions from the SRU are treated by the TGTU during
normal operations prior to final treatment at the TGI.

II.B.2.c The SO2 emissions from the SRU/TGI/TGTU shall not exceed the following

A. 1.68 tpd for up to 21 days per rolling 12-month period

B. 0.69 tpd for the remainder of the rolling 12- month period.

C. 60 tons per rolling 12-month period.

[R307-401-8]

II.B.2.c.1 Compliance with the daily limitation is as follows:

Daily sulfur dioxide emissions from the SRU/TGI/TGTU shall be determined by multiplying the
SO2 concentration in the flue gas (II.B.2.c.2) by the mass flow of the flue gas (II.B.2.c.3).

Compliance with the 12-month rolling total shall be determined within 20 days of the beginning
of each calendar month, The SO2 emission totals calculated to demonstrate compliance with the
daily limitations shall be totaled for the previous month. The monthly total shall be added to the
totals from the previous 11 months to determine the new 12-month rolling total.

[R307-401-8]

II.B.2.c.2 The SO2 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. Daily zero (0-
20% of span value) and span (50-100% of span value) calibration drift tests shall be conducted in
accordance with UAC R307-170. Quarterly cylinder gas audits and an annual relative accuracy
test audit shall be conducted in accordance with the procedures outlined in UAC R307-170. 40
CFR 60 Methods 2, 3 and 6 shall be used to determine relative accuracy. If a new monitor is
installed, an initial performance specification test shall be performed within 30 days of
installation. The performance specification test shall be conducted and data reduced in
accordance with the test methods and procedures contained in 40 CFR 60, Appendix B,
Performance Specification 2. Notification must be made to the Director prior to conducting the
performance specification 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. [R307-401-8]

30
II.B.2.c.3 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 60 Appendix B. An annual relative
accuracy test audit shall be conducted in accordance with the procedures outlined in UAC R307-
170 and 40 CFR 60 Appendix B. If a new volumetric flow measurement device is installed, an
initial performance specification test shall be performed within 30 days of installation. The
performance specification test shall be conducted and data reduced in accordance with the test
methods and procedures contained in 40 CFR 52 Appendix E. Notification must be made to the
Director prior to conducting the performance specification test. [R307-401-8]

Status: Not Evaluated. CEM requirements are audited by DAQ’s CEM specialist. Records
of emissions were reviewed during this inspection. The plant-wide total SO2 emissions of 25
tons during the 12-month period ending August 31, 2024, was below this SRU/TGI/TGTU
specific limit.

II.B.2.d The owner/operator shall comply with a 95% recovery efficiency requirement for all periods of
operation except during periods of startup, shutdown, or malfunction of the SRU/TGI/TGTU.
[R307-401-8, SIP Section IX.H.1.g.iii.A]

II.B.2.d.1 The owner/operator shall determine 95% recovery efficiency on a daily basis; however,
compliance will be determined on a rolling 30-day average basis. The owner/operator shall
determine the percent recovery by measuring the flow rate and concentration of H2S in the feed
streams going to the SRU and by measuring the SO2 emissions with the CEMS at the SRU
incinerator. The feed streams shall include the overhead stream from the Fuel Gas
Desulfurization unit (Amine unit) regenerator and the overhead stream from the Sour Water
Stripper. The flow rate will be determined continuously; the H2S concentration shall be
determined at least once every three (3) years (samples may be collected as manual grabs or
through remote monitoring). The flow rate and H2S concentration values will be used to
determine the daily feed rate. SRU efficiency results shall be reported to the Director a minimum
of once per year. [R307-401-8]

Status: In Compliance with SRU efficiency results reporting. CEM requirements are
evaluated by DAQ’s CEM specialist. No exceedances of the daily and 12-month limits were
discovered during this inspection. The most recent Annual SRU Efficiency Report was
received on July 9, 2024.

II.B.2.e Flare gas recovery as outlined in SIP Section IX.H.11.g.v is not required for dedicated SRU flare
and header systems. [SIP Section IX.H.11.g.v.B]

Status: This is not an inspection item.

II.B.3 Conditions on Storage Tanks

II.B.3.a T-103 shall be installed with an internal floating roof with a primary seal only. The tank shall
comply with 40 CFR 60 Subpart Kb and 40 CFR 63 Subpart CC. [40 CFR 60 Subpart Kb, 40
CFR 63 Subpart CC, R307-401-8(1)(a)]

Status: In Compliance. T-103 has been installed. An initial seal inspection has been
performed. A post-fill notification has been received and indicated Subpart Kb
applicability.

II.B.3.b T-104 shall be a fixed-roof vessel with closed vent controls. The tank shall have a closed-vent
system with nitrogen purge, and shall vent gases as required by NSPS Kb and/or the approved
Control Device Operating Plan per 60.113b(c). The tank shall comply with 40 CFR 60 Subpart
Kb. [40 CFR 60 Subpart Kb, R307-401-8(1)(a)]

Status: T-104 has been decommissioned.

31
Title V Operating Permit 3500008002, issued October 17, 2023 (TLO)

SECTION I: GENERAL PROVISIONS

I.A Federal Enforcement.

All terms and conditions in this permit, including those provisions designed to limit the
potential to emit, are enforceable by the EPA and citizens under the Clean Air Act of 1990
(CAA) except those terms and conditions that are specifically designated as "State
Requirements". (R307-415-6b)

Status: This is not an inspection item.

I.B Permitted Activity(ies).

Except as provided in R307-415-7b(1), the permittee may not operate except in compliance
with this permit. (See also Provision I.E, Application Shield)

Status: In Compliance. The permittee appeared to be operating in compliance with this
permit. See status of each condition below for details.

I.C Duty to Comply.

I.C.1 The permittee must comply with all conditions of the operating permit. Any permit
noncompliance constitutes a violation of the Air Conservation Act and is grounds for any of
the following: enforcement action; permit termination; revocation and reissuance;
modification; or denial of a permit renewal application. (R307-415-6a(6)(a))

I.C.2 It shall not be a defense for a permittee in an enforcement action that it would have been
necessary to halt or reduce the permitted activity in order to maintain compliance with the
conditions of this permit. (R307-415-6a(6)(b))

I.C.3 The permittee shall furnish to the Director, within a reasonable time, any information that
the Director may request in writing to determine whether cause exists for modifying,
revoking and reissuing, or terminating this permit or to determine compliance with this
permit. Upon request, the permittee shall also furnish to the Director copies of records
required to be kept by this permit or, for information claimed to be confidential, the
permittee may furnish such records directly to the EPA along with a claim of
confidentiality. (R307-415-6a(6)(e))

I.C.4 This permit may be modified, revoked, reopened, and reissued, or terminated for cause.
The filing of a request by the permittee for a permit modification, revocation and
reissuance, or termination, or of a notification of planned changes or anticipated
noncompliance shall not stay any permit condition, except as provided under R307-415-
7f(1) for minor permit modifications. (R307-415-6a(6)(c))

Status: In Compliance. The permittee appeared to be in compliance with all conditions of this
permit at the time of inspection.

I.D Permit Expiration and Renewal.
32
I.D.1 This permit is issued for a fixed term of five years and expires on the date shown under
"Enforceable Dates and Timelines" at the front of this permit. (R307-415-6a(2))

I.D.2 Application for renewal of this permit is due on or before the date shown under
"Enforceable Dates and Timelines" at the front of this permit. An application may be
submitted early for any reason. (R307-415-5a(1)(c))

I.D.3 An application for renewal submitted after the due date listed in I.D.2 above shall be
accepted for processing, but shall not be considered a timely application and shall not
relieve the permittee of any enforcement actions resulting from submitting a late
application. (R307-415-5a(5))

I.D.4 Permit expiration terminates the permittee's right to operate unless a timely and complete
renewal application is submitted consistent with R307-415-7b (see also Provision I.E,
Application Shield) and R307-415-5a(1)(c) (see also Provision I.D.2). (R307-415-7c(2))

Status: This permit will expire on October 17, 2028.

I.E Application Shield.

If the permittee submits a timely and complete application for renewal, the permittee's
failure to have an operating permit will not be a violation of R307-415, until the Director
takes final action on the permit renewal application. In such case, the terms and conditions
of this permit shall remain in force until permit renewal or denial. This protection shall
cease to apply if, subsequent to the completeness determination required pursuant to R307-
415-7a(3), and as required by R307-415-5a(2), the applicant fails to submit by the deadline
specified in writing by the Director any additional information identified as being needed to
process the application. (R307-415-7b(2))

Status: This permit will expire on October 17, 2028. Application for renewal is due by
April 17, 2028.

I.F Severability.

In the event of a challenge to any portion of this permit, or if any portion of this permit is
held invalid, the remaining permit conditions remain valid and in force. (R307-415-6a(5))

Status: This is not an inspection item.

I.G Permit Fee.

I.G.1 The permittee shall pay an annual emission fee to the Director consistent with R307-415-9.
(R307-415-6a(7))

I.G.2 The emission fee shall be due on October 1 of each calendar year or 45 days after the source
receives notice of the amount of the fee, whichever is later. (R307-415-9(4)(a))

Status: In Compliance. Emission fees have been paid as invoiced.

I.H No Property Rights.

33
This permit does not convey any property rights of any sort, or any exclusive privilege.
(R307-415-6a(6)(d))

Status: This is not an inspection item.

I.I Revision Exception.

No permit revision shall be required, under any approved economic incentives, marketable
permits, emissions trading and other similar programs or processes for changes that are
provided for in this permit. (R307-415-6a(8))

Status: This is not an inspection item.

I.J Inspection and Entry.

I.J.1 Upon presentation of credentials and other documents as may be required by law, the
permittee shall allow the Director or an authorized representative to perform any of the
following:

I.J.1.a Enter upon the permittee's premises where the source is located or emissions related
activity is conducted, or where records are kept under the conditions of this permit.
(R307-415-6c(2)(a))

I.J.1.b Have access to and copy, at reasonable times, any records that must be kept under
the conditions of this permit. (R307-415-6c(2)(b))

I.J.1.c Inspect at reasonable times any facilities, equipment (including monitoring and air
pollution control equipment), practice, or operation regulated or required under this
permit. (R307-415-6c(2)(c))

I.J.1.d Sample or monitor at reasonable times substances or parameters for the purpose of
assuring compliance with this permit or applicable requirements. (R307-415-
6c(2)(d))

I.J.2 Any claims of confidentiality made on the information obtained during an inspection shall
be made pursuant to Utah Code Ann. Section 19-1-306. (R307-415-6c(2)(e))

Status: In Compliance. Access was granted to the plant and records. No claims of
confidentiality were made.

I.K Certification.

Any application form, report, or compliance certification submitted pursuant to this permit
shall contain certification as to its truth, accuracy, and completeness, by a responsible
official as defined in R307-415-3. This certification shall state that, based on information
and belief formed after reasonable inquiry, the statements and information in the document
are true, accurate, and complete. (R307-415-5d)

Status: In Compliance. All applications, forms, reports, and compliance certifications
submitted pursuant to this permit have contained certification as to truth, accuracy, and
completeness by a responsible official.
34
I.L Compliance Certification.

I.L.1 Permittee shall submit to the Director an annual compliance certification, certifying
compliance with the terms and conditions contained in this permit, including emission
limitations, standards, or work practices. This certification shall be submitted no later than
the date shown under "Enforceable Dates and Timelines" at the front of this permit, and that
date each year following until this permit expires. The certification shall include all the
following (permittee may cross-reference this permit or previous reports):
(R307-415-6c(5))

I.L.1.a The identification of each term or condition of this permit that is the basis of the
certification;

I.L.1.b The identification of the methods or other means used by the permittee for
determining the compliance status with each term and condition during the
certification period. Such methods and other means shall include, at a minimum, the
monitoring and related recordkeeping and reporting requirements in this permit. If
necessary, the permittee also shall identify any other material information that must
be included in the certification to comply with section 113(c)(2) of the Act, which
prohibits knowingly making a false certification or omitting material information;

I.L.1.c The status of compliance with the terms and conditions of the permit for the period
covered by the certification, including whether compliance during the period was
continuous or intermittent. The certification shall be based on the method or means
designated in Provision I.L.1.b. The certification shall identify each deviation and
take it into account in the compliance certification. The certification shall also
identify as possible exceptions to compliance any periods during which compliance
is required and in which an excursion or exceedance as defined under 40 CFR Part
64 occurred; and

I.L.1.d Such other facts as the Director may require to determine the compliance status.

I.L.2 The permittee shall also submit all compliance certifications to the EPA, Region VIII, at the
following address or to such other address as may be required by the Director:
(R307-415-6c(5)(d))

Environmental Protection Agency, Region VIII
Office of Enforcement, Compliance and Environmental Justice
(mail code 8ENF)
1595 Wynkoop Street
Denver, CO 80202-1129

Status: In Compliance. The most recent annual certification was received by DAQ on August
21, 2024, and covered January 1 through December 31, 2023. This certification was reviewed
under separate cover and found to meet the requirements of this condition.

I.M Permit Shield.

I.M.1 Compliance with the provisions of this permit shall be deemed compliance with any
applicable requirements as of the date of this permit, provided that:

35
I.M.1.a Such applicable requirements are included and are specifically identified in this
permit, or (R307-415-6f(1)(a))

I.M.1.b Those requirements not applicable to the source are specifically identified and listed
in this permit. (R307-415-6f(1)(b))

I.M.2 Nothing in this permit shall alter or affect any of the following:

I.M.2.a The emergency provisions of Utah Code Ann. Section 19-1-202 and Section 19-2-
112, and the provisions of the CAA Section 303. (R307-415-6f(3)(a))

I.M.2.b The liability of the owner or operator of the source for any violation of applicable
requirements under Utah Code Ann. Section 19-2-107(2)(a)(xiii) and Section 19-2-
110 prior to or at the time of issuance of this permit. (R307-415-6f(3)(b)). [R307-
415-6f]

I.M.2.c The applicable requirements of the Acid Rain Program, consistent with the CAA
Section 408(a). (R307-415-6f(3)(c))

I.M.2.d The ability of the Director to obtain information from the source under Utah Code
Ann. Section 19-2-120, and the ability of the EPA to obtain information from the
source under the CAA Section 114. (R307-415-6f(3)(d))

Status: This is not an inspection item.

I.N Emergency Provision.

I.N.1 An "emergency" is any situation arising from sudden and reasonably unforeseeable events
beyond the control of the source, including acts of God, which situation requires immediate
corrective action to restore normal operation, and that causes the source to exceed a
technology-based emission limitation under this permit, due to unavoidable increases in
emissions attributable to the emergency. An emergency shall not include noncompliance to
the extent caused by improperly designed equipment, lack of preventive maintenance,
careless or improper operation, or operator error. (R307-415-6g(1))

I.N.2 An emergency constitutes an affirmative defense to an action brought for noncompliance
with such technology-based emission limitations if the affirmative defense is demonstrated
through properly signed, contemporaneous operating logs, or other relevant evidence that:

I.N.2.a An emergency occurred and the permittee can identify the causes of the emergency.
(R307-415-6g(3)(a))

I.N.2.b The permitted facility was at the time being properly operated. (R307-415-
6g(3)(b))

I.N.2.c During the period of the emergency the permittee took all reasonable steps to
minimize levels of emissions that exceeded the emission standards, or other
requirements in this permit. (R307-415-6g(3)(c))

I.N.2.d The permittee submitted notice of the emergency to the Director within two
working days of the time when emission limitations were exceeded due to the
36
emergency. This notice must contain a description of the emergency, any steps
taken to mitigate emissions, and corrective actions taken. This notice fulfills the
requirement of Provision I.S.2.c below. (R307-415-6g(3)(d))

I.N.3 In any enforcement proceeding, the permittee seeking to establish the occurrence of an
emergency has the burden of proof. (R307-415-6g(4))

I.N.4 This emergency provision is in addition to any emergency or upset provision contained in
any other section of this permit. (R307-415-6g(5))

Status: In Compliance. An emergency as defined above has not occurred in the past year.

I.O Operational Flexibility.

Operational flexibility is governed by R307-415-7d(1).

Status: This is not an inspection item.

I.P Off-permit Changes.

Off-permit changes are governed by R307-415-7d(2).

Status: This is not an inspection item.

I.Q Administrative Permit Amendments.

Administrative permit amendments are governed by R307-415-7e.

Status: This is not an inspection item.

I.R Permit Modifications.

Permit modifications are governed by R307-415-7f.

Status: This is not an inspection item.

I.S Records and Reporting.

I.S.1 Records.

I.S.1.a The records of all required monitoring data and support information shall be
retained by the permittee for a period of at least five years from the date of the
monitoring sample, measurement, report, or application. Support information
includes all calibration and maintenance records, all original strip-charts or
appropriate recordings for continuous monitoring instrumentation, and copies of all
reports required by this permit. (R307-415-6a(3)(b)(ii))

I.S.1.b For all monitoring requirements described in Section II, Special Provisions, the
source shall record the following information, where applicable:
(R307-415-6a(3)(b)(i))

37
I.S.1.b.1 The date, place as defined in this permit, and time of sampling or
measurement.

I.S.1.b.2 The date analyses were performed.

I.S.1.b.3 The company or entity that performed the analyses.

I.S.1.b.4 The analytical techniques or methods used.

I.S.1.b.5 The results of such analyses.

I.S.1.b.6 The operating conditions as existing at the time of sampling or
measurement.

I.S.1.c Additional record keeping requirements, if any, are described in Section II, Special
Provisions.

I.S.2 Reports.

I.S.2.a Monitoring reports shall be submitted to the Director every six months, or more
frequently if specified in Section II. All instances of deviation from permit
requirements shall be clearly identified in the reports. (R307-415-6a(3)(c)(i))

I.S.2.b All reports submitted pursuant to Provision I.S.2.a shall be certified by a
responsible official in accordance with Provision I.K of this permit. (R307-415-
6a(3)(c)(i)

I.S.2.c The Director shall be notified promptly of any deviations from permit requirements
including those attributable to upset conditions as defined in this permit, the
probable cause of such deviations, and any corrective actions or preventative
measures taken. Prompt, as used in this condition, shall be defined as written
notification within the number of days shown under "Enforceable Dates and
Timelines" at the front of this permit. Deviations from permit requirements due to
breakdowns shall be reported in accordance with the provisions of R307-107.
(R307-415-6a(3)(c)(ii))

I.S.3 Notification Addresses.

I.S.3.a All reports, notifications, or other submissions required by this permit to be
submitted to the Director are to be sent to the following address or to such other
address as may be required by the Director:

Utah Division of Air Quality
P.O. Box 144820
Salt Lake City, UT 84114-4820
Phone: [phone]

I.S.3.b All reports, notifications or other submissions required by this permit to be
submitted to the EPA should be sent to one of the following addresses or to such
other address as may be required by the Director:

38
For annual compliance certifications:

Environmental Protection Agency, Region VIII
Office of Enforcement, Compliance and Environmental Justice
(mail code 8ENF)
1595 Wynkoop Street
Denver, CO 80202-1129

For reports, notifications, or other correspondence related to permit modifications,
applications, etc.:

Environmental Protection Agency, Region VIII
Air Permitting and Monitoring Branch (mail code 8ARDP-PM)
1595 Wynkoop Street
Denver, CO 80202-1129
Phone: [phone].

Status: In Compliance. Records were reviewed onsite and appear complete. Semi-annual
monitoring reports have been received. Deviation reports have been submitted when required.

I.T Reopening for Cause.

I.T.1 A permit shall be reopened and revised under any of the following circumstances:

I.T.1.a New applicable requirements become applicable to the permittee and there is a
remaining permit term of three or more years. No such reopening is required if the
effective date of the requirement is later than the date on which this permit is due to
expire, unless the terms and conditions of this permit have been extended pursuant
to R307-415-7c(3), application shield. (R307-415-7g(1)(a))

I.T.1.b The Director or EPA determines that this permit contains a material mistake or that
inaccurate statements were made in establishing the emissions standards or other
terms or conditions of this permit. (R307-415-7g(1)(c))

I.T.1.c EPA or the Director determines that this permit must be revised or revoked to
assure compliance with applicable requirements. (R307-415-7g(1)(d))

I.T.1.d Additional applicable requirements are to become effective before the renewal date
of this permit and are in conflict with existing permit conditions. (R307-415-
7g(1)(e))

I.T.2 Additional requirements, including excess emissions requirements, become applicable to a
Title IV affected source under the Acid Rain Program. Upon approval by EPA, excess
emissions offset plans shall be deemed to be incorporated into this permit. (R307-415-
7g(1)(b))

I.T.3 Proceedings to reopen and issue a permit shall follow the same procedures as apply to initial
permit issuance and shall affect only those parts of this permit for which cause to reopen
exists. (R307-415-7g(2))

Status: Permits are reopened for cause by DAQ’s permitting section.
39
I.U Inventory Requirements.

An emission inventory shall be submitted in accordance with the procedures of R307-150,
Emission Inventories. (R307-150)

Status: In Compliance. Emission inventories have been submitted as required.

I.V Title IV and Other, More Stringent Requirements

Where an applicable requirement is more stringent than an applicable requirement of
regulations promulgated under Title IV of the Act, Acid Deposition Control, both
provisions shall be incorporated into this permit. (R307-415-6a(1)(b))

Status: This is not an inspection item.

SECTION II: SPECIAL PROVISIONS

II.A Emission Unit(s) Permitted to Discharge Air Contaminants.
(R307-415-4(3)(a) and R307-415-4(4))

II.A.1 Permitted Source
Source-Wide

II.A.2 Truck Loading Rack
Refined products loading rack and associated vapor collection and recovery system (VRU A and VRU B):
includes LR11-04, LR11-05, LR11-10.

II.A.3 Storage Vessels
Tanks 41,41T, 42, 401, 402, 405, 411, 412, 413, 414, 421, 422, 423, 424, 431, 432, 502, 503, 504, 505,
506, 510

II.A.4 Piping/Associated Equipment
Includes piping tie-in to the UNEV pipeline.

II.A.5 Waste Water Systems
Wastewater systems subject to NSPS Subpart QQQ includes an individual drain system at the Fire
Training Field in the RTF and an oil-water separator within the TLR.

II.A.6 Equipment Regulated by MACT CC
Truck Loading Rack (as identified in II.A.2), Piping/Associated Equipment (as identified in II.A.4), and
Tanks 401, 402, 405, 411, 412, 413, 414, 421, 422, 423, 424, 431, 432.

II.A.7 Waxy Crude Unloading Facility (WCUF)
Includes 5 paved truck unloading lanes covered by canopy and associated piping, Subject to MACT
Subpart EEEE

Status: In Compliance. No unapproved equipment was observed.

40
II.B Requirements and Limitations

The following emission limitations, standards, and operational limitations apply to the permitted facility
as indicated:

II.B.1 Conditions on Permitted Source (Source-wide)

II.B.1.a Condition:

At all times, including periods of startup, shutdown, and malfunction, the permittee shall, to the extent
practicable, maintain and operate any affected emission units, 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.
[Origin: DAQE-AN156590009-23]. [40 CFR 60.11(d), R307-401-8(2)]

II.B.1.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.1.a.2 Recordkeeping:

Permittee shall document all activities performed on equipment authorized to assure proper
operation and maintenance. Records shall be maintained in accordance with Provision I.S.1 of
this permit.

II.B.1.a.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. The plant appeared to be maintaining and operating the emission units,
including associated air pollution control equipment, in a manner consistent with good air pollution
control practices for minimizing emissions. Maintenance activities are documented using manual
documentation and a computerized tracking program (SAP).

II.B.1.b Condition:

The permittee shall comply with the applicable requirements for servicing of motor vehicle air
conditioners pursuant to 40 CFR 82, Subpart B - Servicing of Motor Vehicle Air Conditioners. [Origin:
40 CFR 82 Subpart B]. [40 CFR 82.30(b)]

II.B.1.b.1 Monitoring:

The permittee shall certify, in the annual compliance statement required in Section I of this
permit, its compliance status with the requirements of 40 CFR 82, Subpart B.

41
II.B.1.b.2 Recordkeeping:

All records required in 40 CFR 82, Subpart B shall be maintained consistent with the
requirements of Provision I.S.1 of this permit.

II.B.1.b.3 Reporting:

All reports required in 40 CFR 82, Subpart B shall be submitted as required. There are no
additional reporting requirements except as outlined in Section I of this permit.

Status: In Compliance. The permittee certified compliance with this condition in the most recent
annual compliance certification.

II.B.1.c Condition:

The permittee shall comply with the applicable requirements for recycling and emission reduction for
class I and class II refrigerants pursuant to 40 CFR 82, Subpart F - Recycling and Emissions Reduction.
[Origin: 40 CFR 82 Subpart F]. [40 CFR 82.150(b)]

II.B.1.c.1 Monitoring:

The permittee shall certify, in the annual compliance statement required in Section I of this
permit, its compliance status with the requirements of 40 CFR 82, Subpart F.

II.B.1.c.2 Recordkeeping:

All records required in 40 CFR 82, Subpart F shall be maintained consistent with the
requirements of Provision I.S.1 in of this permit.

II.B.1.c.3 Reporting:

All reports required in 40 CFR 82, Subpart F shall be submitted as required. There are no
additional reporting requirements except as outlined in Section I of this permit.

Status: In Compliance. The permittee certified compliance with this condition in the most recent
annual compliance certification.

II.B.1.d Condition:

The permittee shall submit documentation of the status of the reconstruction of Tank 424 to the Director
on or before September 12, 2019. This AO may become invalid if construction is not commenced by
September 12, 2019 or if construction is discontinued for 18 months or more. To ensure proper credit
when notifying the Director, send the documentation to the Director, attn.: NSR Section.

The permittee shall notify the Director in writing when the installation of the Oily Water Separator has
been completed and is operational. To ensure proper credit when notifying the Director, send you
correspondence to the Director, attn.: NSR Section.

The permittee shall notify the Director in writing when the installation of the new equipment has been
completed and the equipment is operational. The new equipment includes Tank 502, Tank 510, and the
Diesel Filtration System. To ensure proper credit when notifying the Director, send you correspondence
42
to the Director, attn.: NSR Section. If installation has not been completed by May 29, 2018, the Director
shall be notified in writing on the status of the installation. At that time, the Director shall require
documentation of the continuous construction and/or installation of the operation and may revoke the AO.
[Origin: R307-401-18, DAQE-AN156590008-18]. [R307-401-18, R307-401-8(1)(a)(BACT)]

II.B.1.d.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.1.d.2 Recordkeeping:

The permittee shall maintain a copy of each notification required by this permit condition in
accordance with Provision I.S.1 of this permit.

II.B.1.d.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. The equipment listed in this condition has been installed and notifications
have been made.

II.B.1.e Condition:

A Risk Management Plan (RMP) developed in accordance with 40 CFR 68 shall be submitted to the
United States Environmental Protection Agency not later than the applicable date in 40 CFR 68 when the
source becomes subject to the rule. [Origin: 40 CFR 68]. [40 CFR 68]

II.B.1.e.1 Monitoring:

The RMP required for this permit condition will serve as monitoring.

II.B.1.e.2 Recordkeeping:

A copy of the Risk Management Plan shall be available to the Director upon request along with a
copy of the transmittal letter to EPA.

II.B.1.e.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I.

Status: In Compliance. The RMP was updated in 2020.

II.B.1.f Condition:

Unless otherwise specified in this permit, visible emissions caused by fugitive dust shall not exceed 10%
at the property boundary, and 20% onsite. Opacity shall not apply when the wind speed exceeds 25 miles
per hour if the permittee has implemented, and continues to implement, the accepted fugitive dust control
plan and administers at least one of the following contingency measures:
(1) Pre-event watering;
(2) Hourly watering;
43
(3) Additional chemical stabilization;
(4) Cease or reduce fugitive dust producing operations.
[Origin: R307-309]. [R307-309-5, R307-309-6]

II.B.1.f.1 Monitoring:

In lieu of monitoring via visible emissions observations for fugitive dust, adherence to the current
fugitive dust control plan approved by the Director shall be monitored to demonstrate that
appropriate measures are being taken to control fugitive dust. Wind speed may be measured by a
hand-held anemometer or equivalent device.

II.B.1.f.2 Recordkeeping:

If wind speeds are measured to establish an exception from the above visible emissions limits,
records of the administered contingency measures and the wind speed measurements shall be
maintained. Records required by the most recently approved fugitive dust control plan shall be
maintained in accordance with the plan.

Records that demonstrate compliance with this condition shall be available to the director upon
request. [R307-309-12]

Records shall be maintained as described in Provision I.S.1 of this permit.

II.B.1.f.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. A fugitive dust plan was submitted in 2017. Most of the main plant area is
paved. The company has a water truck on site. The water truck is used in the main plant areas. A
logbook is kept in the truck and filled out by the driver. The book is dated and each day shows
drops made and location, times of watering, and comments to include rain, down days, mag
chloride treatments, or other comments. Semi-annual opacity observations are taken and recorded
at the remote tank farm, waxy crude offload, and garage.

II.B.1.g Condition:

The permittee shall submit a fugitive dust control plan to the Director in accordance with R307-309-6.
Activities regulated by R307-309 shall not commence before the fugitive dust control plan is approved by
the director. If site modifications result in emission changes, the permittee shall submit an updated
fugitive dust control plan. At a minimum, the fugitive dust control plan shall include the requirements in
R307-309-6(4) as applicable. The fugitive dust control plan shall include contact information, site
address, total area of disturbance, expected start and completion dates, identification of dust suppressant
and plan certification by signature of a responsible person.

The permittee shall prevent fugitive dust from construction of paved roads and unpaved roads to the
maximum extent possible. The permittee shall clean roads promptly when deposits are made which could
create fugitive dust. [Origin: R307-309]. [R307-309-5(2), R307-309-6, R307-309-9]

44
II.B.1.g.1 Monitoring:

Adherence to the most recently approved fugitive dust control plan shall be monitored to
demonstrate that appropriate measures are being implemented to control fugitive dust.

II.B.1.g.2 Recordkeeping:

Records that demonstrate compliance with this condition shall be available to the director upon
request. [R307-309-12]

Records required by the most recently approved fugitive dust control plan shall be maintained in
accordance with the plan and section I.S.1 of this permit.

II.B.1.g.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. A fugitive dust plan was submitted in 2017. Most of the main plant area is
paved. The company has a water truck on site. The water truck is used in the main plant areas. A
logbook is kept in the truck and filled out by the driver. The book is dated and each day shows
drops made and location, times of watering, and comments to include rain, down days, mag
chloride treatments, or other comments. Semi-annual opacity observations are taken and recorded
at the remote tank farm, VRU, waxy crude offload, and garage.

II.B.1.h Condition:

Fugitive emissions shall not exceed 15 percent opacity. [Origin: R307-309-4(1)]. [R307-309-4]

II.B.1.h.1 Monitoring:

The permittee shall conduct a monthly 1-minute visible emissions survey of each affected source
by an individual trained on the observation procedures of 40 CFR 60, Appendix A, Method 22.

If no visible emissions are observed in six consecutive monthly surveys for any affected source,
the permittee may decrease the frequency of surveys from monthly to semi-annually for the
affected source. If visible emissions are observed during any semi-annual survey, the permittee
shall resume surveys of that affected source on a monthly basis and maintain that schedule until
no visible emissions are observed for six consecutive monthly surveys.

If no visible emissions are observed during two consecutive semi-annual surveys for any affected
source, the permittee may decrease the frequency of surveys from semi-annually to annually for
the affected source. If visible emissions are observed during any annual survey, the permittee
shall resume surveys of that affected source on a monthly basis and maintain that schedule until
no visible emissions are observed for six consecutive monthly surveys.

If visible emissions are observed during any survey, a current Method 9 certified observer shall
conduct a:
1) six minute test of opacity in accordance with 40 CFR 60, Appendix A Method 9 for point
sources,
2) the Method 9 test shall begin within 24 hours of any observation of visible emission.
45
II.B.1.h.2 Recordkeeping:

A log of the visual opacity survey(s) shall be maintained. If an opacity determination is
indicated, a notation of the determination shall be made in the log. Records of visible emission
tests performed and data required by 40 CFR 60, Appendix A, Method 9 shall be maintained in
accordance with Provision I.S.1 of this permit.

II.B.1.h.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. Semi-annual observations have been performed and recorded. The forms
are signed by the observer. No recorded opacity exceedances were noted.

II.B.1.i Condition:

The permittee shall ensure that the following conditions are met for all cold VOC containing solvent parts
washers:

(1) A cover shall be installed which shall remain closed except during actual loading, unloading or
handling of parts in cleaner. The cover shall be designed so that it can be easily operated with one hand if
(a) the volatility of the solvent is greater than 2 kPa (15 mm Hg or 0.3 psi) measured at 38 degrees C (100
degrees F),
(b) the solvent is agitated, or
(c) the solvent is heated.

(2) An internal draining rack for cleaned parts shall be installed on which parts shall be drained until all
dripping ceases. If the volatility of the solvent is greater than 4.3 kPa (32 mm Hg at 38 degrees C (100
degrees F)), the drainage facility must be internal, so that parts are enclosed under the cover while
draining. The drainage facility may be external for applications where an internal type cannot fit into the
cleaning system.

(3) Waste or used solvent shall be stored in covered containers.

(4) Tanks, containers and all associated equipment shall be maintained in good operating condition and
leaks shall be repaired immediately or the degreaser shall be shutdown.

(5) Written procedures for the operation and maintenance of the degreasing or solvent cleaning equipment
shall be permanently posted in an accessible and conspicuous location near the equipment.

(6) If the solvent volatility is greater than 4.3 kPa (33 mm Hg or 0.6 psi) measured at 38 degrees C (100
degrees F), or if solvent is heated above 50 degrees C (120 degrees F), then one of the following control
devices shall be used: (a) freeboard that gives a freeboard ratio greater than 0.7; (b) water cover if the
solvent is insoluble in and heavier than water; (c) other systems of equivalent control, such as a
refrigerated chiller or carbon absorption.

(7) If used, the solvent spray shall be a solid fluid stream at a pressure which does not cause excessive
splashing and may not be a fine, atomized or shower type spray. [Origin: R307-335-4]. [R307-335-4]

46
II.B.1.i.1 Monitoring:

An inspection shall be conducted monthly for all equipment and applicable work practices.

II.B.1.i.2 Recordkeeping:

Results of monthly inspections and the volatility of the solvent(s) being used shall be recorded
and maintained as described in Provision I.S.1 of this permit.

II.B.1.i.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. Monthly inspections are recorded. The parts washer remains closed when
not in use, and the required sign is posted.

II.B.1.j Condition:

When the source applies or solicits the application of any architectural coating, including tanks, the
requirements of R307-361 shall be met. [Origin: R307-361]. [R307-361]

II.B.1.j.1 Monitoring:

The permittee shall comply with applicable requirements in R307-361-8.

II.B.1.j.2 Recordkeeping:

Documentation to verify compliance shall be maintained.

II.B.1.j.3 Reporting:

Upon request of the Director, all reports required in R307-361-7 shall be submitted as required.
There are no additional reporting requirements except as specified in Section I of this permit.

Status: In Compliance. A list of coatings and associated SDS are maintained. Projects cannot
proceed without environmental approval via Management of Change (MOC) tracking software.
Records were made available.

II.B.1.k Condition:

Visible emissions from abrasive blasting operations shall not exceed 20% opacity except for an aggregate
period of three minutes in any one hour. If the abrasive blasting operation complies with the performance
standards in R307-306-6, visible emissions from the operation shall not exceed 40% opacity, except for
an aggregate period of 3 minutes in any one hour. [Origin: R307-306]. [R307-306-4]

47
II.B.1.k.1 Monitoring:

(a) Visible emissions shall be measured using EPA Method 9 every six months if abrasive
blasting operations are conducted. Visible emissions from intermittent sources shall use
procedures similar to Method 9, but the requirement for observations to be made at 15 second
intervals over a six-minute period shall not apply.
(b) Visible emissions from unconfined blasting shall be measured at the densest point of the
emission after a major portion of the spent abrasive has fallen out, at a point not less than five feet
nor more than twenty-five feet from the impact surface from any single abrasive blasting nozzle.
(c) An unconfined blasting operation that uses multiple nozzles shall be considered a single
source unless it can be demonstrated by the permittee that each nozzle, measured separately,
meets the emission and performance standards provided in R307-206-2 through 4.
(d) Visible emissions from confined blasting shall be measured at the densest point after the air
contaminant leaves the enclosure.

II.B.1.k.2 Recordkeeping:

Results of monitoring shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.1.k.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. Opacity observations taken and recorded when abrasive blasting occurs.

II.B.1.l Condition:

The permittee shall comply with the applicable fenceline monitoring provisions of 40 CFR 63.658.
[Origin: 40 CFR 63, Subpart CC]. [40 CFR 63.658]

II.B.1.l.1 Monitoring:

Monitoring shall be in accordance with the applicable requirements of 40 CFR 63.658.

II.B.1.l.2 Recordkeeping:

The permittee shall comply with the applicable recordkeeping requirements in 40 CFR
63.655(i)(8). Records shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.1.l.3 Reporting:

Permittee shall meet applicable reporting requirements of 40 CFR 63.655(h)(8). Additional
reporting requirements for this provision are specified in Section I of this permit.

Status: In Compliance. Benzene fence line monitoring was implemented on January 30, 2018.
Annual totals are required to be reported to EPA via an online reporting tool. Records were made
available during this inspection.

48
II.B.1.m Condition:

Solvent cleaning operations shall be in accordance with the requirements of R307-304.
[Origin: R307-304]. [R307-304]

II.B.1.m.1 Monitoring:

Records required for this permit will serve as monitoring.

II.B.1.m.2 Recordkeeping:

Records shall be maintained as required in R307-304-8 and Provision I.S.1 of this permit.

II.B.1.m.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. Records were made available.

II.B.1.n Condition:

Adhesive and Sealant usage shall comply with applicable requirements of R307-342.
[Origin: R307-342]. [R307-342-5through 8]

II.B.1.n.1 Monitoring:

The records required for this permit condition will serve as monitoring.

II.B.1.n.2 Recordkeeping:

The permit shall maintain records demonstrating compliance with this condition as required in
R307-342-7(2) and Provision I.S.1 of this permit.

II.B.1.n.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. Adhesive and Sealant usage complies with R307-342.

II.B.1.o Condition:

The permittee shall determine the total annual benzene quantity from facility waste in accord with the
requirements in 40 CFR 61.355(a), (b), and (c) to demonstrate that the total annual benzene quantity from
facility waste is less than 10 megagrams per year (Mg/yr)(11 ton/yr). The total annual benzene quantity
shall include waste from the Tesoro Refinery and from Tesoro Logistics Operations LLC, consisting of
the Remote Tank Farm (RTF) and Truck Loading Rack (TLR). [Origin: 40 CFR 61, Subpart FF]. [40
CFR 61.342(a)]

49
II.B.1.o.1 Monitoring:

The permittee shall determine the flow-weighted annual average benzene concentration following
the requirements of 40 CFR 61.355(c)(1) and the methods in 40 CFR 61.355(c)(2) and (c)(3).

II.B.1.o.2 Recordkeeping:

Records shall be maintained in accordance with the provisions of 40 CFR 61.356 and the
provisions of I.S.1 of this permit.

II.B.1.o.3 Reporting:

All reports required in 40 CFR 61.357 shall be submitted as required. There are no additional
reporting requirements except as outlined in Section I of this permit.

Status: In Compliance. The most recent total annual benzene (TAB) report was received on March
21, 2024. 5.339 Mg of benzene was reported for 2023 and includes the refinery and TLR.

II.B.1.p Condition:

The permittee shall comply with the applicable provisions of 40 CFR 61.145(a) and (c), 40 CFR 61.148,
61.150(a) through (e), and 40 CFR 61.152. [Origin: 40 CFR 61, Subpart M]. [40 CFR 61.145, 40 CFR
61.148, 40 CFR 61.150, 40 CFR 61.152]

II.B.1.p.1 Monitoring:

The recordkeeping and reporting requirements for this permit condition will serve as monitoring
requirement.

II.B.1.p.2 Recordkeeping:

Records shall be maintained in accordance with the provisions of 40 CFR 61.150(d) and (e) if
applicable and the provisions of I.S.1 of this permit.

II.B.1.p.3 Reporting:

All reports required in 40 CFR 61.145(b), 40 CFR 61.153 shall be submitted as required. There
are no additional reporting requirements except as outlined in Section I of this permit.

Status: Not Evaluated. Asbestos requirements are evaluated by DAQ’s ATLAS section. Tesoro
certified compliance with this condition in the most recent annual compliance certification.

II.B.2 Conditions on Truck Loading Rack

II.B.2.a Condition:

The truck loading rack, which delivers liquid product into gasoline tank trucks shall meet the
requirements of 40 CFR 60.502 except for paragraphs (b), (c), and (j). [Origin: 40 CFR 63, Subparts R
and CC, and 40 CFR 60, Subpart XX]. [40 CFR 60.502, 40 CFR 63.422(a), 40 CFR 63.650]

50
II.B.2.a.1 Monitoring:

The permittee shall determine compliance with the standard in 40 CFR 60.502(h) as required in
40 CFR 60.503 (a), (b), and (d). Records required for this permit condition will serve as
monitoring.

II.B.2.a.2 Recordkeeping:

Permittee shall meet recordkeeping requirements of 40 CFR 60.505(a) and 60.505(f). Records
shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.2.a.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. The loading rack is equipped with a vapor collection system as per 40 CFR
60.502. Trucks are loaded through submerged bottom filling and only into certified trucks. Tesoro
complies with a 10 mg/L emissions limit, which is more stringent than 0.640 lbs/1,000 gallons (76.7
mg/L). Tesoro maintains a plant-wide computerized preventative and as-needed maintenance
database. All maintenance is recorded through a work order system. VOC and drip leak checks are
performed. No excess leaking was observed upon disconnect at the TLR bays during this
inspection. Monthly visible leak checks have been performed and recorded. Quarterly LDAR
checks are also performed. Loading arms and vapor recovery lines are equipped with vapor tight
fittings. A spring-loaded plate with a rubber seal automatically closes upon disconnection.
Connections are visually checked for leak tightness monthly. Pressure monitors are installed and
automatically shut off loading if pressure drops are detected. All trucks are grounded through a
program called Scully, which verifies tanker certifications and monitors pressure during loading.
The system is set to automatically stop loading if pressure drops are detected and will not load if a
hatch is open. The vapor collection system is designed to prevent gauge pressure in the gasoline
cargo tank from exceeding 18 inches of water and prevent the vacuum from exceeding 6 inches of
water.

II.B.2.b Condition:

Emissions to the atmosphere from the carbon adsorption vapor collection and processing systems due to
the loading of gasoline cargo tanks shall not exceed an average of 10 milligrams of total organic
compounds per liter of gasoline loaded over a six-hour period. [Origin: 40 CFR 63, Subpart R; 40 CFR
63, Subpart CC; & DAQE-AN156590009-23]. [40 CFR 63.422(b), 40 CFR 63.427(a & b), 40 CFR
63.650, R307-401-8]

II.B.2.b.1 Monitoring:

The applicable test methods and procedures in 40 CFR 63.425(a) through (c) and (e) through (h)
shall be followed.

The permittee shall comply with the requirements for a continuous emission monitoring system at
63.427(a) and (a)(1). The concentration of volatile organic compounds in the exhaust of the
vapor collection system shall be measured by a monitoring device approved by the Director.

The permittee shall comply with the requirements for a continuous emission monitoring system in
51
accordance with R307-170. Other records required for this permit condition will serve as
monitoring.

II.B.2.b.2 Recordkeeping:

Permittee shall meet the applicable recordkeeping requirements of 40 CFR 63.428(b), (c), (g)(1),
(h)(1) through (3), and (k). Records shall be maintained in accordance with Provision I.S.1 of
this permit.

II.B.2.b.3 Reporting:

Permittee shall meet the applicable reporting requirements of 40 CFR 63.428(b), (c), (g)(1),
(h)(1) through (3), and (k) and the provisions specified in Section I of this permit.

The reports required in this paragraph are considered prompt notification of permit deviations
required in provision I.S.2.c of this permit if all information required by provision I.S.2.c is
included int the report.

Status: Not Evaluated. CEM requirements are evaluated by DAQ’s CEM specialist. Two VRU’s
with CEMs are installed. Quarterly reports are submitted to DAQ. Semi-annual Subpart CC
reports have been submitted.

II.B.2.c Condition:

The permittee shall comply with the provisions of 40 CFR 60.502(e) by the methods required in 40 CFR
63.422(c) or alternatively in 40 CFR 63.422(e). [Origin: 40 CFR 63, Subparts R and CC, 40 CFR 60,
Subpart XX]. [40 CFR 60.502(e), 40 CFR 63.422(c), 40 CFR 63.650]

II.B.2.c.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.2.c.2 Recordkeeping:

Permittee shall meet the applicable recordkeeping requirements of 40 CFR 60.428(b), (c), (g)(1),
(h)(1) through (3), and (k)

Records shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.2.c.3 Reporting:

Permittee shall meet the applicable reporting requirements of 40 CFR 63.428(b), (c), (g)(1),
(h)(1) through (3), and (k) and the provisions specified in Section I of this permit.

Status: In Compliance. Only tankers with compatible recovery systems and electronic identification
chips are allowed to load at the bays. Tesoro uses electronic chips installed on approved tanker
trucks to verify compliance with this regulation. Unapproved trailers are locked out electronically
if any information is outdated or other problems are detected. Records are kept and were made
available.

52
II.B.2.d Condition:

The permittee shall install, calibrate, maintain, and operate a monitoring device for the concentration of
organic compounds in the exhaust air stream of the vapor collection system. The monitoring device must
be located such that an inspector or operator can safely and easily read the output at any time. The
accuracy, calibration method and calibration frequency of the monitoring device shall be approved by the
Director.

The permittee shall install an alarm system to indicate malfunctions of vapor collection system. The alarm
system shall be installed simultaneously with the monitoring device for the concentration of organic
compounds in the exhaust air stream of the vapor collection system. The alarm system will notify the
permittee prior to exceedance of the standard. [DAQE-AN156590009-23]. [R307-401-8]

II.B.2.d.1 Monitoring:

The permittee shall comply with the requirements for a continuous emission monitoring system in
accordance with R307-170.

II.B.2.d.2 Recordkeeping:

Records to document compliance shall be maintained in accordance with Provision I.S.1 of this
permit. If the alarm system indicates an exceedance of the standard, the permittee shall maintain
records of the corrective action taken and duration of event.

II.B.2.d.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: Not Evaluated. CEM requirements are evaluated by DAQ’s CEM specialist. Two VRU’s
with CEMs are installed. Quarterly reports are submitted to DAQ.

II.B.2.e Condition:

The source shall maintain records to demonstrate that the gasoline cargo tanks loaded at the facility are in
compliance with annual certification test requirements of 40 CFR 63.425(e). [Origin: 40 CFR 63,
Subparts R and CC]. [40 CFR 63.425(e), 40 CFR 63.650(a)]

II.B.2.e.1 Monitoring:

Records required for this permit condition will serve as monitoring. Tests shall be conducted in
accordance with 40 CFR 63.425(e)(1) and (2).

II.B.2.e.2 Recordkeeping:

Documentation shall be kept up-to-date for each gasoline cargo tank loading at the facility. The
documentation shall meet the requirements of 40 CFR 63.428(b)(3). As an alternative to keeping
records at the terminal of each gasoline cargo tank test result as required in section 63.428(b), the
source may comply with the requirements in either section 63.428(k)(1) or (2). Records shall be
maintained as described in Provision I.S.1 of this permit.

53
II.B.2.e.3 Reporting:

The source shall submit a semiannual report to the Director listing each loading of a gasoline
cargo tank for which vapor tightness documentation had not been previously obtained by the
facility, (40 CFR 63.428(g)(1), and reports specified in Section I of this permit.

Status: In Compliance. Only tankers with compatible recovery systems and electronic identification
chips are allowed to load at the bays. Tesoro uses electronic chips installed on approved tanker
trucks to verify compliance with this regulation. Unapproved trailers are locked out electronically
if any information is outdated or other problems are detected. Trucks are loaded through
submerged bottom filling and only into certified trucks. Tesoro complies with a 10 mg/L emissions
limit, which is more stringent than 0.640 lbs/1,000 gallons (76.7 mg/L).

Tesoro maintains a plant-wide computerized preventative and as-needed maintenance database. All
maintenance is recorded through a work order system. VOC and drip leak checks are performed.
No excess leaking was observed upon disconnect at the TLR bays during this inspection. Monthly
visible leak checks have been performed and recorded. Quarterly LDAR checks are also
performed. Loading arms and vapor recovery lines are equipped with vapor tight fittings. A
spring-loaded plate with a rubber seal automatically closes upon disconnection. Connections are
visually checked for leak tightness monthly. Pressure monitors are installed and automatically shut
off loading if pressure drops are detected. All trucks are grounded through a program called
Scully, which verifies tanker certifications and monitors pressure during loading. The system is set
to automatically stop loading if pressure drops are detected and will not load if a hatch is open.

II.B.2.f Condition:

The source shall comply with the requirements of R307-328. [Origin: R307-328]. [R307-328]

II.B.2.f.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.2.f.2 Recordkeeping:

The permittee shall maintain records to document compliance with R307-328 and in accordance
with Provision I.S.1 of this permit.

II.B.2.f.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. Trucks are loaded through submerged bottom filling and only into certified
trucks. Tesoro complies with a 10mg/L emissions limit, which is more stringent than 0.640lbs/1,000
gallons (76.6mg/L). Tesoro maintains a plant-wide computerized preventative and as-needed
maintenance database. All maintenance is recorded through a work order system. VOC and drip
leak checks are performed. No excess leaking was observed upon disconnect at the TLR bays
during this inspection. Monthly visible leak checks have been performed and recorded. Quarterly
LDAR checks are also performed. Loading arms and vapor recovery lines are equipped with vapor
tight fittings. A spring-loaded plate with a rubber seal automatically closes upon disconnection.
Connections are visually checked for leak tightness monthly. Pressure monitors are installed and
54
automatically shut off loading if pressure drops are detected. All trucks are grounded through a
program called Scully, which verifies tanker certifications and monitors pressure during loading.
The system is set to automatically stop loading if pressure drops are detected and will not load if a
hatch is open. Semi-annual pressure checks have been performed and recorded.

II.B.3 Conditions on Storage Vessels

II.B.3.a Condition:

The additive tank #502 shall be limited to thirty (30) turnovers per year.

The additives tank #505 shall be limited to twelve (12) turnovers per year.

The additives tank #506 shall be limited to seven (7) turnovers per year.

The additives tank #510 shall be limited to thirty (30) turnovers per year. [DAQE-AN156590009-23].
[R307-401-8]

II.B.3.a.1 Monitoring:

The turnovers for each tank shall be determined on a rolling 12-month total. Within 20 days of
the beginning of each calendar month, the permittee shall calculate a new monthly total turnover.
The monthly total turnovers shall be added to the data from the previous 11 months.

II.B.3.a.2 Recordkeeping:

Results of monitoring shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.3.a.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. For the 12-month period ending July 31, 2024, the following were
recorded:

The additive tank #502 – 2.2 turnovers

The additives tank #505 – 3.4 turnovers

The additives tank #506 – 3.0 turnovers

The additives tank #510 – 0.4 turnovers

II.B.3.b Condition:

The following production limits shall not be exceeded:

A. 120,000 gallons of additives throughput for storage tank #502 per rolling 12-month period
B. 72,000 gallons of additives throughput for storage tank #505 per rolling 12-month period
C. 42,000 gallons of additives throughput for storage tank #506 per rolling 12-month period
55
D. 240,000 gallons of additives throughput for storage tank #510 per rolling 12-month period
[DAQE-AN156590009-23]. [R307-401-8]

II.B.3.b.1 Monitoring:

The throughputs shall be determined on a rolling 12-month total. Within 20 days of the
beginning of each calendar month, the permittee shall calculate a new monthly throughput total.
The monthly throughput total shall be added to the data from the previous 11 months.

II.B.3.b.2 Recordkeeping:

The amount of additives added to each storage tank shall be recorded on a log. Records of the
throughput shall be kept for all periods when the plant is in operation and shall be made available
to the Director or the Director's representative upon request. Records shall be maintained in
accordance with Provision I.S.1 of this permit.

II.B.3.b.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. For the 12-month period ending July 31, 2024, the following were recorded:

The additive tank #502 – 8,756 gallons of additives

The additives tank #505 – 20,507 gallons of additives

The additives tank #506 – 18,022 gallons of additives

The additives tank #510 – 3,125 gallons of additives

II.B.3.c Condition:

In accordance with 40 CFR 63.640(n)(2), Internal Floating Roof Tanks 503 and 504 shall be designed and
operated in accord with 40 CFR 60.112b(a)(1), except as provided in 40 CFR 63.640(n)(8). [Origin: 40
CFR 60, Subpart Kb & 40 CFR 63, Subpart CC]. [40 CFR 60.112b(a)(1), 40 CFR 63.640(n)]

II.B.3.c.1 Monitoring:

The permittee shall meet the requirements of 40 CFR 60.113(a). The permittee shall comply with
the applicable provisions in 40 CFR 63.640(n)(8).

II.B.3.c.2 Recordkeeping:

Records required in 40 CFR 60.115b(a)(2) and 40 CFR 60.116b, except as required by 40 CFR
63.640(n)(8), and the requirements of Provision I.S.1 of this permit shall be maintained by the
permittee.

II.B.3.c.3 Reporting:

Reports required in 40 CFR 60.115b(a)(1), (3), and (4) shall be submitted as required, except as
56
required by 40 CFR 63.640(n)(8). There are no additional reporting requirements except as
outlined in Section I of this permit.

Status: In Compliance. Tank #503 and tank #504 are fixed roof in combination with IFR. These
tanks have a mechanical shoe primary seal and a secondary wiper seal. The tanks are inspected
semi-annually. Records indicated all repairs have been made within the 45-day time limit. Tesoro
maintains records of roof types, liquid contents, and maximum true vapor pressure of petroleum
liquids stored inside tanks.

II.B.3.d Condition:

In accordance with 40 CFR 63.640(n)(2), External Floating Roof Tanks 424 and 431 shall be designed
and operated in accord with 40 CFR 60.112b(a)(2), except as provided in 40 CFR 63.640(n)(8). [Origin:
40 CFR 60, Subpart Kb & 40 CFR 63, Subpart CC]. [40 CFR 60.112b(a)(2), 40 CFR 63.64640(n)]

II.B.3.d.1 Monitoring:

The permittee shall meet the requirements of 40 CFR 60.113b(b). The permittee shall comply
with the applicable provisions in 40 CFR 63.640(n)(8).

II.B.3.d.2 Recordkeeping:

Records required in 40 CFR 60.115b(b)(3) and 40 CFR 60.116b, except as required by 40 CFR
63.640(n)(8), and the requirements of Provision I.S.1 of this permit shall be maintained by the
permittee.

II.B.3.d.3 Reporting:

Reports required in 40 CFR 60.113b(b)(5); 40 CFR 60.115b(b)(1), (2), and (4) shall be submitted
as required, except as required by 40 CFR 63.640(n)(8). There are no additional reporting
requirements except as outlined in Section I of this permit.

Status: These tanks are Subpart Kb compliant EFR tanks and are equipped with primary and
secondary seals. Secondary seals are inspected semi-annually for gaps, tears, and holes. Primary
seals are inspected every five years or whenever tanks are emptied and refilled.

II.B.3.e Condition:

Group 1 storage vessels equipped with floating roofs: T402, T405, T412, T413, T414, T421, T422,
T423, and T432 shall comply with 40 CFR 63, Subpart WW. Requirements for rim seals (40 CFR
63.1063(a)(1) and deck fittings (40 CFR 63.1063(a)(2) shall become applicable completed the next time
each applicable vessel is emptied and degassed, but not later than January 30, 2026. Group 1 storage
vessels equipped with a ladder having at least one slotted leg and group 1 storage vessels with slotted
guidepoles may install controls described in 40 CFR 63.660(b) instead of 40 CFR 63, Subpart WW.
[Origin: 40 CFR 63, Subpart CC]. [40 CFR 63.1062, 40 CFR 63.1063, 40 CFR 63.660]

II.B.3.e.1 Monitoring:

Inspections shall be conducted in accordance with 40 CFR 63.1063.

57
II.B.3.e.2 Recordkeeping:

Record of the seal configuration shall be listed for each vessel. The permittee shall record the
date each vessel is emptied and degassed and the date installation of the deck fittings are
complete. Records shall be maintained in accordance with Provision I.S.1 of this permit, 40 CFR
63.1065, and 40 CFR 63.655(i).

II.B.3.e.3 Reporting:

Applicable reporting requirements of 40 CFR 63.1066 and 40 CFR 63.655 (g), and (h) shall be
completed. Additional reporting requirements for this provision are specified in Section I of this
permit.

Status: In Compliance. Unless previously equipped, all applicable tanks have been fitted with the
rim seal and deck fitting requirements of 40 CFR 63.1063(a)(1)-(2) when emptied and degassed.

II.B.3.f Condition:

For external floating roof tanks 405, 421, 422, 423, 424, 431, and 432 the primary seals, the accumulated
area of gaps between the tank wall and the metallic shoe seal or the liquid-mounted seal shall not exceed
ten (10) square inches per foot of tank diameter. The width of any portion of any gap shall not exceed
one and a half (1.5) inches.

For the secondary seals, the accumulated area of gaps between the tank wall and the secondary seal shall
not exceed one (1) square inch per foot of tank diameter and the width of any portion of any gap shall not
exceed one-half (0.5) inch. The secondary seals shall be properly installed and maintained according to
the manufacturer's recommendations.

The permittee shall comply with all applicable parts of R307-327. [Origin: DAQE-AN156590009-23].
[R307-327, R307-401-8]

II.B.3.f.1 Monitoring:

Records required for this permit condition shall serve as monitoring.

II.B.3.f.2 Recordkeeping:

Records to document compliance shall be maintained in accordance with R307-327 and Provision
I.S.1 of this permit.

II.B.3.f.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. Records of inspections were made available. Notifications of planned
inspections have been made.

58
II.B.3.g Condition:

The permittee shall comply with the applicable requirement in R307-327-4. [Origin: R307-327].
[R307-327-4]

II.B.3.g.1 Monitoring:

The permittee shall comply with the applicable monitoring requirements in R307-327-4(2) and
R307-327-5 through 7.

II.B.3.g.2 Recordkeeping:

The results of monitoring shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.3.g.3 Reporting:

In accordance with R307-327-5, the Permittee shall notify the Director 7 days prior to the
refilling of a tank that has been emptied, degassed for maintenance, an emergency or any other
similar purpose. Any non-compliance with this rule shall be corrected before the tank is refilled.

Additional reporting requirements for this provision are specified in Section I of this permit.

Status: In Compliance. See evaluation under R307 requirements above.

II.B.3.h Condition:

The permittee of 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 shall not allow it 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.
[Origin: SIP Subsection IX.H.11.g.vi]. [SIP Section IX.H.11.g.vi]

II.B.3.h.1 Monitoring:

The permittee shall monitor organic vapor concentration during tank degassing.

II.B.3.h.2 Recordkeeping:

The results of monitoring shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.3.h.3 Reporting:

The permittee shall notify the intent to degas any tanks to the Director. Except in an emergency
situation, the 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;
59
(c) Degassing operator's name, contact person, telephone number;

(d) Tank capacity, volume of space to be degassed, and materials stored;

(e) Description of vapor control device.

Status: In Compliance. See evaluation under R307 requirements above.

II.B.4 Conditions on Piping and Associated Equipment

II.B.4.a Condition:

The permittee shall comply with the applicable requirements of General Standards in 40 CFR 60, Subpart
VVa, specifically, 60.482-1a for equipment leaks of VOC for equipment within process units regulated by
NSPS GGGa. [Origin: 40 CFR 60, Subpart GGGa, SIP Subsection IX.H.11.g.iv ]. [40 CFR 60.592a(a)]

II.B.4.a.1 Monitoring:

Testing shall comply with the applicable requirements of 60.485a except as provided in Section
60.593a.

II.B.4.a.2 Recordkeeping:

Records shall comply with the applicable requirements of 60.486a. Records shall also be
maintained in accordance with Provision I.S.1 of this permit.

II.B.4.a.3 Reporting:

Reporting shall comply with the applicable requirements of 60.487a and requirements specified
in Section I of this permit.

Status: In Compliance. Tesoro follows the monitoring methods described in these sections for the
affected components. NSPS Subpart GGG applies to equipment at petroleum refineries that
commence construction or modification after January 4, 1983, but before November 7, 2006, while
NSPS Subpart GGGa applies to equipment at petroleum refineries that commence construction or
modification after November 7, 2006. However, in 2015, Tesoro voluntarily elected to comply with
NSPS GGGa for all components, and often uses more stringent leak definitions as required by a
consent decree with the USEPA. The company maintains a LEAK DAS database, which tracks all
components and records all required information as the components are monitored. Portable
monitors are calibrated using methane and hexane gas according to Method 21. First attempt at
repair is made on the spot or within a maximum of five days. All repaired components are
monitored for leaks immediately following repair. Pressure relief valves are monitored for no
detectable emissions within 24 hours of each release. All sampling connection systems are either
closed-vent or closed-purge. All open-ended valves or lines are equipped with a plug or double
valve. Pumps and valves in heavy liquid service, pressure relief devices in light liquid or heavy
liquid service, and flanges/other connectors are monitored within five days when a leak is detected
and repaired within fifteen days as required. Delays of repair are reported in the quarterly reports.
Closed vent systems and control devices include two NSPS flare systems that are operated in
accordance with the requirements of 60.18, and the Vapor Recovery Unit which is designed to
recover VOC emissions at a rate of 95 percent or greater. Tesoro complies with Subpart VVa which
satisfies Subpart VV requirements. Periodic VOC monitoring reports have been submitted.
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II.B.4.b Condition:

The permittee shall comply with the applicable requirements for pumps in light liquid service in 40 CFR
60, Subpart VVa, specifically, 60.482-2a for equipment leaks of VOC. This applies to pumps in light
liquid service within process units regulated by NSPS GGGa. [Origin: 40 CFR 60, Subpart GGGa, SIP
Subsection IX.H.11.g.iv ]. [40 CFR 60.592a(a)]

II.B.4.b.1 Monitoring:

Testing shall comply with the applicable requirements of 60.485a except as provided in Section
60.593a.

II.B.4.b.2 Recordkeeping:

Records shall comply with the applicable requirements of 60.486a. Records shall also be
maintained in accordance with Provision I.S.1 of this permit.

II.B.4.b.3 Reporting:

Reporting shall comply with the applicable requirements of 60.487a and requirements specified
in Section I of this permit.

Status: In Compliance. The indicators of compliance described in condition II.B.4.a.3 also indicate
compliance with this condition.

II.B.4.c Condition:

The permittee shall comply with the applicable requirements for pressure relief devices in gas/vapor
service in 40 CFR 60, Subpart VVa, specifically, 60.482-4a for equipment leaks of VOC. This applies to
pressure relief devices in gas/vapor service within process units regulated by NSPS GGGa. [Origin: 40
CFR 60, Subpart GGGa, SIP Subsection IX.H.11.g.iv ]. [40 CFR 60.592a(a)]

II.B.4.c.1 Monitoring:

Testing shall comply with the applicable requirements of 60.485a except as provided in Section
60.593a.

II.B.4.c.2 Recordkeeping:

Records shall comply with the applicable requirements of 60.486a. Records shall also be
maintained in accordance with Provision I.S.1 of this permit.

II.B.4.c.3 Reporting:

Reporting shall comply with the applicable requirements of 60.487a and requirements specified
in Section I of this permit.

Status: In Compliance. The indicators of compliance described in condition II.B.4.a.3 also indicate
compliance with this condition.

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II.B.4.d Condition:

The permittee shall comply with the applicable requirements for sampling connection systems in 40 CFR
60, Subpart VVa, specifically, 60.482-5a for equipment leaks of VOC. This applies to sampling
connection systems within process units regulated by NSPS GGGa. [Origin: 40 CFR 60, Subpart GGGa,
SIP Subsection IX.H.11.g.iv ]. [40 CFR 60.592a(a)]

II.B.4.d.1 Monitoring:

Testing shall comply with the applicable requirements of 60.485a except as provided in Section
60.593a.

II.B.4.d.2 Recordkeeping:

Records shall comply with the applicable requirements of 60.486a. Records shall also be
maintained in accordance with Provision I.S.1 of this permit.

II.B.4.d.3 Reporting:

Reporting shall comply with the applicable requirements of 60.487a and requirements specified
in Section I of this permit.

Status: In Compliance. The indicators of compliance described in condition II.B.4.a.3 also indicate
compliance with this condition.

II.B.4.e Condition:

The permittee shall comply with the applicable requirements for open-ended valves or lines in 40 CFR
60, Subpart VVa, specifically, 60.482-6a for equipment leaks of VOC. This applies to open-ended valves
or lines within process units regulated by NSPS GGGa. The permittee shall also comply with
R307-326-9(8). [Origin: 40 CFR 60, Subpart GGGa, SIP Subsection IX.H.11.g.iv ]. [40 CFR
60.592a(a), R307-3269(8)]

II.B.4.e.1 Monitoring:

The permittee shall complete surveys to demonstrate compliance with these equipment standards
in the condition above. The survey shall be completed in conjunction with the required
monitoring in 60.482-1a through 60.482-11a.

II.B.4.e.2 Recordkeeping:

Records shall comply with the applicable requirements of 60.486a. Records shall also be
maintained in accordance with Provision I.S.1 of this permit.

II.B.4.e.3 Reporting:

Reporting shall comply with the requirements specified in Section I of this permit.

Status: In Compliance. The indicators of compliance described in condition II.B.4.a.3 also indicate
compliance with this condition.

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II.B.4.f Condition:

The permittee shall comply with the applicable requirements for valves in gas/vapor service and in light
liquid service in 40 CFR 60, Subpart VVa, specifically, 60.482-7a for equipment leaks of VOC. This
applies to valves in gas/vapor service and light liquid service within process units regulated by NSPS
GGGa. [Origin: 40 CFR 60, Subpart GGGa, SIP Subsection IX.H.11.g.iv]. [40 CFR 60.592a(a)]

II.B.4.f.1 Monitoring:

Testing shall comply with the applicable requirements of 60.485a except as provided in Section
60.593a.

II.B.4.f.2 Recordkeeping:

Records shall comply with the applicable requirements of 60.486a. Records shall also be
maintained in accordance with Provision I.S.1 of this permit.

II.B.4.f.3 Reporting:

Reporting shall comply with the applicable requirements of 60.487a and requirements specified
in Section I of this permit.

Status: In Compliance. The indicators of compliance described in condition II.B.4.a.3 also indicate
compliance with this condition.

II.B.4.g Condition:

The permittee shall comply with the applicable requirements for pumps, valves, and connectors in heavy
liquid service and pressure relief devices in light liquid or heavy liquid service in 40 CFR 60, Subpart
VVa, specifically, 60.482-8a for equipment leaks of VOC. This applies to pumps, valves, and connectors
in heavy liquid service and pressure relief devices in light liquid or heavy liquid service within process
units regulated by NSPS GGGa. This also applies to connectors in gas/vapor light-liquid service in
accordance with 40 CFR 60.593a(g). [Origin: 40 CFR 60, Subpart GGGa, SIP Subsection IX.H.11.g.iv].
[40 CFR 60.592a(a), 40 CFR 60.592a(g)]

II.B.4.g.1 Monitoring:

Testing shall comply with the applicable requirements of 60.485a except as provided in Section
60.593a.

II.B.4.g.2 Recordkeeping:

Records shall comply with the applicable requirements of 60.486a. Records shall also be
maintained in accordance with Provision I.S.1 of this permit.

II.B.4.g.3 Reporting:

Reporting shall comply with the applicable requirements of 60.487a and requirements specified
in Section I of this permit.

Status: In Compliance. The indicators of compliance described in condition II.B.4.a.3 also indicate
compliance with this condition.
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II.B.4.h Condition:

The permittee shall comply with the applicable requirements for delay of repair in 40 CFR 60, Subpart
VVa, specifically, 60.482-9a for equipment leaks of VOC. This applies to applicable equipment within
process units regulated by NSPS GGGa. [Origin: 40 CFR 60, Subpart GGGa, SIP Subsection
IX.H.11.G.IV]. [40 CFR 60.592a(a)]

II.B.4.h.1 Monitoring:

Testing shall comply with the applicable requirements of 60.485a except as provided in Section
60.593a.

II.B.4.h.2 Recordkeeping:

Records shall comply with the applicable requirements of 60.486a. Records shall also be
maintained in accordance with Provision I.S.1 of this permit.

II.B.4.h.3 Reporting:

Reporting shall comply with the applicable requirements of 60.487a and requirements specified
in Section I of this permit.

Status: In Compliance. The indicators of compliance described in condition II.B.4.a.3 also indicate
compliance with this condition.

II.B.4.i Condition:

The permittee shall comply with the applicable requirements for closed vent systems and control devices
in 40 CFR 60, Subpart VVa, specifically, 60.482-10a for equipment leaks of VOC. This applies to closed
vent systems and control devices within process units regulated by NSPS GGGa. [Origin: 40 CFR 60,
Subpart GGGa, SIP Subsection IX.H.11.g.iv]. [40 CFR 60.592a(a)]

II.B.4.i.1 Monitoring:

Testing shall comply with the applicable requirements of 60.485a except as provided in Section
60.593a.

II.B.4.i.2 Recordkeeping:

Records shall comply with the applicable requirements of 60.486a. Records shall also be
maintained in accordance with Provision I.S.1 of this permit.

II.B.4.i.3 Reporting:

Reporting shall comply with the applicable requirements of 60.487a and requirements specified
in Section I of this permit.

Status: In Compliance. The indicators of compliance described in condition II.B.4.a.3 also indicate
compliance with this condition.

64
II.B.4.j Condition:

The permittee shall conduct a VOC monitoring program consistent with R307-326-9 and may elect to
continue using the May 2, 1995 Variance (DAQC-599-95) for skip monitoring.

All safety pressure relief valves handling organic material shall be vented to a flare, firebox, or vapor
recovery system, or controlled by the inspection, monitoring, and repair requirements described in R307-
326-9.

The permittee may also elect to comply with R307-326-10 upon approval. [Origin: R307-326].
[R307-326-8, 9, 10]

II.B.4.j.1 Monitoring:

Monitoring shall be completed in accordance with R307-326-9(3) through (5) and the May 2,
1995 variance.

II.B.4.j.2 Recordkeeping:

Records shall be maintained in accordance with R307-326-9(6) and Provision I.S.1 of this permit.

II.B.4.j.3 Reporting:

Reporting shall be maintained in accordance with R307-326-9(7) and Section I of this permit.

Status: In Compliance. Tesoro utilizes a computerized VOC monitoring program called LEAK
DAS. This system is used to track and record all of the monitoring conducted at the site. Tesoro has
hired Alliance to manage the program and also employs an LDAR coordinator. Portable monitors
are calibrated using methane and hexane gas at 0, 100, 200, 500, 2000, and 10,000 ppm. These
monitors record leak readings right into the LEAK DAS system. Tesoro uses tighter leak
definitions based on a Consent Decree with USEPA and has also voluntarily changed all
components to the more stringent Subpart GGGa requirements. First attempt at repair on leaking
valves is made by the Alliance technician who is qualified to do so. If not qualified, unable to repair
a leak, or on components other than valves, a work order is generated by the LEAK DAS system.
Tesoro follows the Subpart GGGa policy of attempting to repair all leaks no later than 15 days. A
technician reads repaired components immediately after each repair is made. Portable monitors
are calibrated using methane and hexane gas according to Method 21. NSPS Subpart GGG applies
to equipment at petroleum refineries that commence construction or modification after January 4,
1983, but before November 7, 2006, while NSPS Subpart GGGa applies to equipment at petroleum
refineries that commence construction or modification after November 7, 2006. Tesoro voluntarily
elected to comply with NSPS GGGa in 2015. All equipment is monitored for leaks in accordance
with the requirements of 40 CFR 60 Subpart GGGa. Components are monitored by Method 21 at
least quarterly. All components, whether required or voluntarily, are being monitored according to
Subpart GGGa requirements which is the most stringent of all current requirements. Components
are monitored at least two consecutive months until the associated unit’s components are observed
leaking at a rate of less than 2%. At this point, the unit is switched to a quarterly monitoring
requirement. In the event a unit has more than 2% of components found leaking above the GGGa
leak definitions, it is switched back to the monthly leak monitoring requirements. Pumps are
visually inspected weekly and by Method 21 monthly. Leaking pump seals are repaired within 15
days and monitored immediately following repair. Inaccessible and unsafe-to-monitor valves have
been reported to the Utah Division of Air Quality (UDAQ). Inaccessible valves are monitored at
65
least once per year. Some unsafe-to-monitor valves are not monitored regularly. No alternative
monitoring methods are being used by Tesoro. Leaking components are noted by affixing a
weatherproof tag. Leak logs are kept as required. Leak monitoring reports have been submitted
quarterly. These reports are reviewed for accuracy and then kept in UDAQ’s source files. Valves at
the end of a pipe or line containing VOCs are sealed with a plug, cap, or a second valve.

II.B.5 Conditions on Waste Water System

II.B.5.a Condition:

The permittee shall demonstrate compliance with the exclusions in paragraphs 40 CFR 60.692-1(d) as
required in 40 CFR 60.697 (h). [Origin: 40 CFR 60, Subpart QQQ]. [40 CFR 60.692-1(d), 40 CFR
60.697(h)]

II.B.5.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.5.a.2 Recordkeeping:

Records required shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.5.a.3 Reporting:

Reporting in accordance with 40 CFR 60.698 and those specified in Section I of this permit shall
be completed.

Status: In Compliance. Design diagrams are available upon request.

II.B.5.b Condition:

The following individual drain systems shall meet the applicable requirements of 40 CFR 60.692-2(a):

RTF Fire Training Field: J-979 Sump Pump to Fire/Oily Water Storage Tanks (433 & 434) [Origin 40
CFR 60, Subpart QQQ]. [40 CFR 60.692-2(a)]

II.B.5.b.1 Monitoring:

Monitoring shall be conducted in accordance with the applicable requirements of 40 CFR
60.692-2(a).

II.B.5.b.2 Recordkeeping:

Records required shall be maintained in accordance with the applicable requirements of 40 CFR
60.697 and Provision I.S.1 of this permit.

II.B.5.b.3 Reporting:

Reporting in accordance with the applicable requirements of 40 CFR 60.698 and those specified
in Section I of this permit shall be completed.

Status: In Compliance. Records are kept for at least two years. Inspections and corrective actions
are recorded as required. Inspections have been performed and recorded monthly during training.
66
The system is decommissioned when no training is taking place. No delay of repair events have
occurred. Design specifications and diagrams are available. The most recent semi-annual Subpart
QQQ report was received on July 22, 2024. All drains checked during this inspection had water
inside.

II.B.5.c Condition:

The following equipment shall meet the applicable requirements of 40 CFR 60, Subpart QQQ):

Fire Training Field:
Sump - Junction box: 40 CFR 60.692-2(b)
Tanks 433 and 434. 40 CFR 60.692-3(a)(1) through (3) & (b). [Origin: 40 CFR 60, Subpart QQQ]. [40
CFR 60.692-2(b), 40 CFR 60.692-3(a & f)]

II.B.5.c.1 Monitoring:

Monitoring shall be conducted in accordance with the applicable requirements of 40 CFR
60.692-2(b) and 40 CFR 60.692-3(a)(4) & (5).

II.B.5.c.2 Recordkeeping:

Records required shall be maintained in accordance with the applicable requirements of 40 CFR
60.697 and Provision I.S.1 of this permit.

II.B.5.c.3 Reporting:

Reporting in accordance with the applicable requirements of 40 CFR 60.698 and those specified
in Section I of this permit shall be completed.

Status: In Compliance. Records are kept for at least two years. Inspections and corrective actions
are recorded as required. Records of semi-annual system inspections have been kept. There have
not been any delay of repair events. Design specifications and diagrams are available. The most
recent semi-annual Subpart QQQ report was received on July 22, 2024. All junction boxes
observed during this inspection appeared to be properly covered and sealed.

II.B.5.d Condition:

Sewer lines shall not be open to the atmosphere and shall be covered or enclosed in a manner so as to
have no visual gaps or cracks in joints, seals, or other emission interfaces and shall be maintained in
accordance with the applicable requirements of 40 CFR 60.692-2(c)(3). This specifically includes the fire
training field drain system. [Origin: 40 CFR 60, Subpart QQQ]. [40 CFR 60.692-2(c)]

II.B.5.d.1 Monitoring:

The portion of each unburied sewer line shall be visually inspected in accordance with the
applicable requirements of 40 CFR 60.692-2(c).

II.B.5.d.2 Recordkeeping:

Records required shall be maintained in accordance with the applicable requirements of 40 CFR
60.697 and Provision I.S.1 of this permit.
67
II.B.5.d.3 Reporting:

Reporting in accordance with the applicable requirements of 40 CFR 60.698 and those specified
in Section I of this permit shall be completed.

Status: In Compliance. Records are kept for at least two years. Inspections and corrective actions
are recorded as required. Records of semi-annual system inspections have been kept. There have
not been any delay of repair events. Design specifications and diagrams are available. The most
recent semi-annual Subpart QQQ report was received on January 9, 2023.

II.B.5.e Condition:

Materials discharged through drains and junction boxes installed on or after May, 1987 shall meet the
requirements of 40 CFR 60.692-2(e). This specifically includes the fire training field system. [Origin:
40 CFR 60, Subpart QQQ]. [40 CFR 60.692-2(a)]

II.B.5.e.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.5.e.2 Recordkeeping:

Records to document compliance shall be maintained in accordance with the applicable
requirements of 40 CFR 60.697 and Provision I.S.1 of this permit.

II.B.5.e.3 Reporting:

Reporting in accordance with the applicable requirements of 40 CFR 60.698 and those specified
in Section I of this permit shall be completed.

Status: In Compliance. Records are kept for at least two years. Inspections and corrective actions
are recorded as required. Records of semi-annual system inspections have been kept. There have
not been any delay of repair events. Design specifications and diagrams are available. The most
recent semi-annual Subpart QQQ report was received on July 22, 2024.

II.B.5.f Condition:

The truck loading rack oil-water separator shall comply with the applicable requirements of 40 CFR
60.692-3. [Origin: 40 CFR 60, Subpart QQQ]. [40 CFR 60.692-3(e)]

II.B.5.f.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.5.f.2 Recordkeeping:

Records to document compliance shall be maintained in accordance with the applicable
requirements of 40 CFR 60.697 and Provision I.S.1 of this permit.

II.B.5.f.3 Reporting:

68
Reporting in accordance with the applicable requirements of 40 CFR 60.698 and those specified
in Section I of this permit shall be completed.

Status: In Compliance. Records are kept for at least two years. Inspections and corrective actions
are recorded as required. Records of semi-annual system inspections have been kept. There have
not been any delay of repair events. Design specifications and diagrams are available. The most
recent semi-annual Subpart QQQ report was received on July 22, 2024.

II.B.5.g Condition:

The permittee shall ensure that any wastewater (oil/water) separator handling VOCs is equipped with lids
or seals on all openings in covers, separators, and forebays. Such lids or seals shall be in the closed
position at all times except when in actual use. [Origin: R307-326]. [R307-326-5(2)]

II.B.5.g.1 Monitoring:

A monthly survey shall be performed to document compliance with this condition.

II.B.5.g.2 Recordkeeping:

Results of the monthly survey shall be maintained in accordance with Provision I.S.1 of this
permit.

II.B.5.g.3 Reporting:

Reporting in accordance with Section I of this permit shall be completed.

Status: In Compliance. Seals were in place during this inspection. Records are kept for at least two
years. Inspections and corrective actions are recorded as required. Records of monthly surveys
have been kept. There have not been any delay of repair events. Design specifications and diagrams
are available. The most recent semi-annual Subpart QQQ report was received on July 22, 2024.

II.B.6 Conditions on Equipment Regulated by MACT CC

II.B.6.a Condition:

When required by the Director, the permittee shall conduct performance tests in accordance with the
requirements of 40 CFR 63.642(d). [Origin: 40 CFR 63, Subpart CC]. [40 CFR 63.642(d)]

II.B.6.a.1 Monitoring:

Performance testing shall comply with 40 CFR 63.642(d)(3).

II.B.6.a.2 Recordkeeping:

Records shall be maintained in accordance with Provision I.S.1 of this permit and 40 CFR
63.655(i).

II.B.6.a.3 Reporting:

Applicable reporting requirements of 40 CFR 63.655(e), (f), (g), and (h) shall be completed.
69
Additional reporting requirements for this provision are specified in Section I of this permit.

Status: See Subpart R evaluation below.

II.B.6.b Condition:

All emission points listed as Equipment Regulated by MACT CC shall be operated and maintained as
required in 40 CFR 63.642(n). [Origin: 40 CFR 63, Subpart CC]. [40 CFR 63.642(n)]

II.B.6.b.1 Monitoring:

Records required for this permit condition shall serve as monitoring.

II.B.6.b.2 Recordkeeping:

Records shall be maintained in accordance with Provision I.S.1 of this permit and 40 CFR
63.655(i).

II.B.6.b.3 Reporting:

Applicable reporting requirements of 40 CFR 63.655(e), (f), (g), and (h) shall be completed.
Additional reporting requirements for this provision are specified in Section I of this permit.

Status: CEMs are installed on two VRUs. RATAs are conducted and reviewed. Quarterly reports
are submitted. Quarterly reports are reviewed by DAQ’s CEM specialist. Semi-annual Subpart CC
reports have been received. The plant appeared to be maintaining and operating the emission units,
including associated air pollution control equipment, in a manner consistent with good air pollution
control practices for minimizing emissions. Maintenance activities are documented using manual
documentation and a computerized tracking program.

II.B.6.c Condition:

Per the approved extension request approved on June 2, 2017 by the Director and revised in 83 FR 60696
on November 26, 2018, vents that the permittee designates as maintenance vents shall meet the
requirements of 40 CFR 63.643 (c). The permittee shall also comply with the requirements of 40 CFR
63.643(d). [Origin: 40 CFR 63, Subpart CC]. [40 CFR 63.643(a), 40 CFR 63.643(c), 40 CFR 63.643(d)]

II.B.6.c.1 Monitoring:

The permittee shall monitor compliance using the applicable requirements in 40 CFR 63.643(c).

II.B.6.c.2 Recordkeeping:

Records shall be maintained in accordance with Provision I.S.1 of this permit and 40 CFR
63.643(d). Records shall be maintained in accordance with Provision I.S.1 of this permit and 40
CFR 63.655(i)(12).

II.B.6.c.3 Reporting:

Applicable reporting requirements of 40 CFR 63.655(g) shall be completed. Additional reporting
requirements for this provision are specified in Section I of this permit.

Status: In Compliance. The TLO has designated 5 filter vessels and a specific length of a short-haul
70
pipeline as subject to the requirements of 40 CFR 63.643 (c). A nitrogen purge is utilized to ensure
compliance during maintenance operations. Records are kept and were made available.
Semi-annual Subpart CC reports have been submitted.

II.B.6.d Condition:

The permittee shall comply with the requirements specified in 40 CFR 63.648(j)(1) & (2) for pressure
relief devices. [Origin: 40 CFR 63, Subpart CC]. [40 CFR 63.648(j)(1), 40 CFR 63.648(j)(2)]

II.B.6.d.1 Monitoring:

Records required for this permit condition shall serve as monitoring.

II.B.6.d.2 Recordkeeping:

Records shall be maintained in accordance with Provision I.S.1 of this permit and 40 CFR
63.655(d), as applicable.

II.B.6.d.3 Reporting:

Applicable reporting requirements of 40 CFR 63.655(d) shall be completed. Additional reporting
requirements for this provision are specified in Section I of this permit.

Status: In Compliance. Pressure relief valves are monitored within five days of each release for an
instrument reading of less than 500 ppm.

II.B.7 Conditions on Waxy Crude Unloading Facility (WCUF)

II.B.7.a Condition:

The WCUF shall meet the requirements of 40 CFR 63. 2350(a) and (d) [Origin: 40 CFR 63, Subpart
EEEE]. [40 CFR 63.23500]

II.B.7.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.7.a.2 Recordkeeping:

Permittee shall meet recordkeeping requirements of 40 CFR 63.2343(a) and 63.2390(a). Records
shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.7.a.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance. The plant appeared to be maintaining and operating the emission units,
including associated air pollution control equipment, in a manner consistent with good air pollution
control practices for minimizing emissions. Maintenance activities are documented using manual
documentation and a computerized tracking program.
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II.C Emissions Trading
(R307-415-6a(10))

Not applicable to this source.

II.D Alternative Operating Scenarios.
(R307-415-6a(9))

Not applicable to this source.

40 CFR 63, Subpart ZZZZ: K1A and K1B Compressors

Status: Tesoro was required to test the K1 compressors for formaldehyde as specified in
table 2c, Item 11. Subpart ZZZZ gives a limit of 10.3 ppmdv @ 15% O2. Stack testing was
performed on March 18, 2014, and results were submitted to DAQ. DAQ-calculated test
results in DAQC-724-14 were 1.5 ppmdv @ 15% O2 from K1A Compressor, and 0.8 ppmdv
@ 15% O2 K1B Compressor. Four emergency generators demonstrate compliance with this
subpart by proper maintenance and recordkeeping. Maintenance is recorded in the
company’s SAP database.

40 CFR 60, NSPS, Subpart GG STATIONARY GAS TURBINES: Cogeneration system – Only the
sections not included in the AO were evaluated below.

60.330 Applicability and designation of affected facility.
(a) The provisions of this subpart are applicable to the following affected facilities: All
stationary gas turbines with a heat input at peak load equal to or greater than 10.7
gigajoules (10 million Btu) per hour, based on the lower heating value of the fuel fired.
(b) Any facility under paragraph (a) of this section which commences construction,
modification, or reconstruction after October 3, 1977, is subject to the requirements of
this part except as provided in paragraphs (e) and (j) of §60.332.
Status: These gas turbines are subject to Subpart GG. See status of each applicable section
for details.

60.332 Standard for nitrogen oxides.

(a) On and after the date on which the performance test required by §60.8 is completed,
every owner or operator subject to the provisions of this subpart as specified in
paragraphs (b), (c), and (d) of this section shall comply with one of the following, except
as provided in paragraphs (e), (f), (g), (h), (i), (j), (k), and (l) of this section.
(d) Stationary gas turbines with a manufacturer's rated base load at ISO conditions of 30
megawatts or less except as provided in §60.332(b) shall comply with paragraph (a)(2) of
this section.
Status: In Compliance. This is a 23.4 Mw max potential site. Limits on NOx from the
turbines at this site are calculated as 197 ppmdv per the equations in the standard. Tesoro
has a 32 ppm guarantee from manufacturer Solar. CEMs are installed. Quarterly reports
are submitted and reviewed by the DAQ CEM specialist.
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60.333 Standard for Sulfur Dioxide.
On and after the date on which the performance test required to be conducted by §60.8 is
completed, every owner or operator subject to the provision of this subpart shall comply
with one or the other of the following conditions:
(a) No owner or operator subject to the provisions of this subpart shall cause to be
discharged into the atmosphere from any stationary gas turbine any gases which contain
sulfur dioxide in excess of 0.015 percent by volume at 15 percent oxygen and on a dry
basis.
(b) No owner or operator subject to the provisions of this subpart shall burn in any
stationary gas turbine any fuel, which contains total sulfur in excess of 0.8 percent by
weight (8000 ppmv).
Status: In Compliance. The initial performance test was conducted October 26, 2004. A
CEM is maintained in accordance with Subpart J, which is more stringent.
60.334 Monitoring of operations.
(a) Except as provided in paragraph (b) of this section, the owner or operator of any
stationary gas turbine subject to the provisions of this subpart and using water or steam
injection to control NOX emissions shall install, calibrate, maintain and operate a
continuous monitoring system to monitor and record the fuel consumption and the ratio
of water or steam to fuel being fired in the turbine.
(f) The owner or operator of a new turbine, who elects not to install a CEMS under
paragraph (e) of this section, may instead perform continuous parameter monitoring as
follows:
(2) For any lean premix stationary combustion turbine, the owner or operator shall
continuously monitor the appropriate parameters to determine whether the unit is
operating in the lean premixed (low-NOX) combustion mode.
Status: In Compliance. This is a lean premix stationary combustion turbine system. EPA
approval for fuel monitoring program was submitted by Tesoro on January 12, 2004, and
EPA approval was issued on April 12, 2004. The fuel-monitoring plan is followed in lieu of a
CEM as approved by EPA.
40 CFR 60, NSPS, SUBPART J - FLUID CATALYTIC CRACKING UNIT CATALYST
REGENERATOR (Ultraformer unit F-15 and Co-gen unit is included in this evaluation): The only
sections evaluated below are those applicable and not included as AO conditions above.

60.100 Applicability

(c)- FCCU modified or constructed after January 17, 1984 is subject to this Subpart.

Status: In Compliance. The FCCU regenerator was modified after January 17, 1984, and is
subject to this Subpart. Start-up occurred on April 23, 1996.

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60.103 Standard for Carbon Monoxide

60.103(a) - limit CO to no greater than 500 ppm by volume.

Status: An exemption to CO monitoring was granted in a letter dated November 26, 1996
(DAQC-2004-96). No further compliance determination could be made based on this
subpart.

60.105 Monitoring

(a)(1) continuously monitor and record the opacity of emissions to the atmosphere.
(a)(2)(ii) - A continuous CO monitor need not be installed if source can demonstrate
compliance with the 50-ppmv limit.
(a)(3) continuously monitor SO2 and/or H2S.
(c)-record the average coke burn off rate and hours of operation on a daily basis.
(e) report periods of excess emissions quarterly.

Status: In Compliance. This condition is not applicable since the installation of the WGS on
January 1, 2019. CEMs for both SO2 and H2S are installed. Quarterly reports are
submitted as required for all CEM/COM systems.

60.107 Reporting and recordkeeping

(a) notify administrator of compliance option chosen for 60.104(b)
(b)(2) record and maintain records of daily measurements
(c)-submit quarterly reports
(e) unavailable data periods. Source must submit a signed statement indicating if any
changes were made during the period of unavailability.
(f) signed statement of accuracy and completeness

Status: In Compliance. Tesoro notified EPA of the compliance option on May 7, 1996.
Tesoro uses option 104(b)(2). Daily measurements are recorded in the company’s database.
Quarterly reports are submitted by the company and evaluated by DAQ’s CEM specialist.

40 CFR 63 Subpart CC - The only sections evaluated below are those applicable and not included as AO
conditions above.

a. Applicability

Status: This is a petroleum refinery subpart – Tesoro is subject.

d. Exempted sources

Status: The cat cracker, cat reformer regeneration vents, sulfur plant vents, and points
routed to the fuel gas system are subject to Subpart UUU and evaluated in the related
section of this memo.

63. 643 Misc process vents

a: Reduce HAPs using flare
a2: Reduce HAPs with control device by 98% wt or 20ppmdv
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b: If boiler used vent to flare zone

Status: In Compliance. Tesoro has miscellaneous process vents routed to the flare.

63.644 – Process vent monitoring

Status: Tesoro uses the flare option above and monitors the flare by use of an IR scanner
with redundant sensors to ensure a pilot light.

NSPS Subpart G Requirements:

63.119 Storage Vessel Provisions – Reference Control Technology

Status: In Compliance. Control technology used for the storage tanks complies with the
provisions of 63.119 for the Group I and II storage vessels, minimizing VOC emissions by
avoiding vapor space between the roof of the vessel and the liquid contained in it. Each
vessel has been equipped with the proper emissions reductions device within the timelines
specified in this provision of the CFR. Operation of the tanks is subject to this provision.

63.120 Storage Vessel Provisions – Procedures to Determine Compliance.

Status: In Compliance. Semi-annual visual inspections are conducted. Inspection and
repair are done in accordance with this provision and are recorded. Records of inspections
and repairs are available at the refinery. Results are reported to DAQ. Records were
reviewed at the time of this inspection.

63.122 Storage Vessel Provisions – Reporting

Status: In Compliance. Tesoro has submitted Subpart CC reports for storage vessels semi-
annually. These reports are reviewed for accuracy and kept in DAQ’s source files.

63.123 Storage Vessel Provisions – Recordkeeping

Status: In Compliance. Records are kept in accordance with the provisions of 63.123,
where applicable, including storage vessel dimensions and vessel contents.

NSPS, Subpart K - applies to Tank 321

60.112(a)(1) The storage vessel shall be equipped with a floating roof.

Status: In Compliance. The tank is equipped with an internal floating roof.

60.113(a) The owner or operator shall maintain records of petroleum liquid stored, period of
storage, and the maximum true vapor pressure of that liquid during storage.

Status: In Compliance. Records are maintained on-site. This requirement is captured by
MACT CC requirements evaluated in the related section of this memo.

NSPS, Subpart Ka - applies to tanks 402, 412, 414

60.112a(a)(2) The owner or operator shall equip each applicable storage vessel with a fixed roof with
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an internal floating type cover. Each opening in the cover is to provide a projection below
the liquid surface and shall be equipped with a cover, seal, or lid, which is to be closed at
all times except when the device is in use.

Status: In Compliance. All the tanks listed under this subpart are internal floating roof
tanks. All openings are covered with a seal or lid and all projections go below the liquid
surface. This requirement is captured by MACT CC requirements evaluated in the related
section of this memo.

60.115a The owner or operator shall maintain records of petroleum liquid stored, period of
storage, and the maximum true vapor pressure of that liquid during storage.

Status: In Compliance. Records are maintained on-site. This requirement is captured by
MACT CC requirements evaluated in the related section of this memo.

NSPS, Subpart Kb - applies to tanks 103, 186, 188, 241, 298, 327, 331, 424, 503 and 504

60.112b(a)(1) Storage vessels shall be equipped with a fixed roof in combination with an internal
floating roof. The floating roof shall rest on the liquid surface at all times except when
floating off. Each storage vessel shall be equipped with a closure device between the wall
of the storage vessel and the edge of the internal floating roof. Each opening in the cover
shall be equipped with a cover, seal or lid, which shall be maintained in a closed position
at all times except when the device is in actual use.

Status: In Compliance. Tanks 140, 186, 188, 244, 245, 248, 297, 331, 503, and 504 are
internal floating roof tanks. Records show the tanks meet the specifications required under
this section. Tank 103 is a fixed roof tank vented to a control device (FGR System).

60.112b(a)(2) Storage vessels shall be equipped with an external floating roof. Each storage vessel shall
be equipped with a closure device that consists of 2 seals between the wall of the storage
vessel and the edge of the external floating roof. Each opening in the cover shall be
equipped with a cover, seal or lid, which shall be maintained in a closed position at all
times except when the device is in actual use.

Status: In Compliance. Tanks 424 and 327 are equipped with external floating roofs that
meet the requirements of this subpart.

60.113 The owner or operator shall visually inspect the internal floating roof, the primary seal
and the secondary seal before filling. Any repairs needed shall be completed prior to
filling the tank. Seals shall be visually inspected at least once every 12 months after
initial fill. Repairs shall be made within 45 days. Additional visual inspections shall

occur each time the vessel is emptied and degassed. Notify the administrator at least 30
days prior to filling each vessel.

Status: In Compliance. This section applies to Tanks 140, 186, 188, 244, 245, 248, 297, 331,
503, and 504. These tanks have a mechanical shoe primary seal and a secondary wiper seal.
The tanks are inspected semi-annually. Records indicated all repairs have been made within
the 45-day time limit. Notices have been received.

60.113b(b) - Measure gaps in primary seal during hydrostatic testing within 60 days of initial fill and
76
at least once every five years thereafter. Measure gaps in secondary seal during initial fill
and once per year thereafter. Notify Administrator 30 days prior to any gap
measurements.

Status: In Compliance. This only applies to Tank 327. The initial fill occurred on April 13,
1992. Initial measurement of the primary seal was on March 13, 1992, and each year
thereafter. Tesoro charts gap measurements and submits these for repairs when
measurements exceed required maximums. Tesoro has notified the DAQ prior to measuring
seal gaps. Notifications are in the source file.

60.115b The owner or operator shall keep records and furnish reports as required. Copies of all
reports and records shall be maintained for at least 2 years. Records of all inspections
shall be maintained. If tears/gaps exceeding the allowed size are discovered during
inspection, a report shall be submitted within 30 days of discovery.

Status: In Compliance. All reports have been submitted and records are kept according to
tank number. All records are maintained for a 2-year period. Tesoro maintains all records
pertaining to the tanks, including vapor pressures of liquids.

60.116b Copies of all records required must be kept for at least two years. Records containing
dimensions and contents shall be maintained.

Status: In Compliance. Records were made available.

NSPS Subpart R – Gasoline Distribution Facilities (TLO)

63.422 (a) Each owner or operator of loading racks at a bulk gasoline terminal subject to the
provisions of this subpart shall comply with the requirements in §60.502 of this chapter
except for paragraphs (b), (c), and (j) of that section. For purposes of this section, the
term "affected facility" used in §60.502 of this chapter means the loading racks that load
gasoline cargo tanks at the bulk gasoline terminals subject to the provisions of this
subpart.

Status: See compliance determination for 60-502 below.

63.422(b) Emissions to the atmosphere from the vapor collection and processing systems due to the
loading of gasoline cargo tanks shall not exceed 10 milligrams of total organic
compounds per liter of gasoline loaded.

Status: CEMs are installed on two VRUs. Quarterly reports are submitted and reviewed by
DAQ’s CEM specialist. Semi-annual reports are submitted and reviewed by DAQ.

63.422(c) Each owner or operator of a bulk gasoline terminal subject to the provisions of this
subpart shall comply with §60.502(e) of this chapter as follows:

(1) For the purposes of this section, the term "tank truck" as used in §60.502(e) of
this chapter means cargo tank."

(2) Section 60.502(e)(5) of this chapter is changed to read: The terminal owner or
operator shall take steps assuring that the nonvapor-tight gasoline cargo tank will
not be reloaded at the facility until vapor tightness documentation for that
77
gasoline cargo tank is obtained which documents that:

(i) The tank truck or railcar gasoline cargo tank meets the test
requirements in §63.425(e), or the railcar gasoline cargo tank meets
applicable test requirements in §63.425(i);

(ii) For each gasoline cargo tank failing the test in §63.425(f) or (g) at the
facility, the cargo tank either:

(A) Before repair work is performed on the cargo tank, meets the test requirements in
§63.425(g) or (h), or

(B) After repair work is performed on the cargo tank before or during the tests in
§63.425(g) or (h), subsequently passes the annual certification test described in
§63.425(e).

Status: In Compliance. Only tankers with compatible recovery systems and electronic
identification chips are allowed to load at the bays. Tesoro uses the new electronic chips
installed on approved tanker trucks to verify compliance with this regulation. Unapproved
trailers are locked out electronically if any information is outdated or other problems are
detected.
63.422(d) Each owner or operator shall meet the requirements in all paragraphs of this section as
expeditiously as practicable, but no later than December 15, 1997 at existing facilities
and upon startup for new facilities.
Status: In Compliance. The newer loading racks approved in 2008 met these requirements
upon startup.
63.422(e) As an alternative to 40 CFR 60.502(h) and (1) as specified in paragraph (a) of this
section, the owner or operator may comply with paragraphs (e)(1) and (2) of this section.
Status: In Compliance. Tesoro is not using this alternative.

63.424 Equipment leak standards:
a- Monthly leak inspections of all equipment in gasoline service shall be conducted.
b- A log book shall be used and signed by owner/operator at the completion of each
monthly inspection.
c- Detected leaks shall be recorded and repaired within 15 calendar days.
d- Delay of repair beyond 15 days can be allowed by administrator if necessary.
e- Source must comply by 12/15/97.
f- Alternative monitoring strategies defined.
g- Owner/operator shall not allow gasoline to be handled in a way that allows extended
periods of vapor release to the atmosphere.

Status: In Compliance. Tesoro has implemented a monthly inspection schedule that covers
all of the above requirements. Records of inspections are maintained on site and
maintenance activities are recorded. These requirements are also listed in 40 CFR 60.502(j).

63.425 Test methods and procedures: Tesoro complies with state continuous emission
monitoring requirements which are more stringent.

78
63.427 Continuous Monitoring: Requirements have been incorporated into state rules and the
Approval Orders discussed above.

63.428 Reporting and record keeping
(a) Initial notifications.
(b) Records of each annual certification test for cargo tanks and railcar bubble leak
tests.
(c) Keep up to date record of the CEMS data.
(e) Leak detection logbook requirements.
(f) Maintain report of all equipment and ID #s for equipment in gasoline service.
(g) Submit a semi-annual report (# leaks not repaired w/i 5 days).
(h) Submit excess emission reports after breakdowns.
(i) Applicability determination.
(j) Applicability determination.

Status: In Compliance. Records are maintained on-site and were made available. Quarterly
reports for the CEM system are completed and submitted to DAQ.

40 CFR 63 Subpart UUU – For Cat Cracker, Reformer and Sulfur Recovery Unit
40 CFR 63.1562 What parts of my plant are covered by this subpart?

(a) This subpart applies to each new, reconstructed, or existing affected source at a petroleum
refinery.
(b) The affected sources are:
(1) The process vent or group of process vents on fluidized catalytic cracking units that
are associated with regeneration of the catalyst used in the unit (i.e., the catalyst
regeneration flue gas vent).
(2) The process vent or group of process vents on catalytic reforming units (including
but not limited to semi-regenerative, cyclic, or continuous processes) that are associated
with regeneration of the catalyst used in the unit. This affected source includes vents that
are used during the unit depressurization, purging, coke burn, and catalyst rejuvenation.
(3) The process vent or group of process vents on Claus or other types of sulfur recovery
plant units or the tail gas treatment units serving sulfur recovery plants, that are
associated with sulfur recovery.
(4) Each bypass line serving a new, existing, or reconstructed catalytic cracking unit,
catalytic reforming unit, or sulfur recovery unit. This means each vent system that
contains a bypass line (e.g., ductwork) that could divert an affected vent stream away
from a control device used to comply with the requirements of this subpart.
(c) An affected source is a new affected source if you commence construction of the affected
source after September 11, 1998, and you meet the applicability criteria in §63.1561 at the time
you commenced construction.
(f) This subpart does not apply to:
(1) A thermal catalytic cracking unit.
(2) A sulfur recovery unit that does not recover elemental sulfur or where the modified reaction
79
is carried out in a water solution which contains a metal ion capable of oxidizing the sulfide ion to sulfur
(e.g., the LO–CAT II process).

(3) A redundant sulfur recovery unit not located at a petroleum refinery and used by the
refinery only for emergency or maintenance backup.
(4) Equipment associated with bypass lines such as low leg drains, high point bleed,
analyzer vents, open-ended valves or lines, or pressure relief valves needed for safety
reasons.
(5) Gaseous streams routed to a fuel gas system.

Status: In Compliance. The affected sources include Fluid Catalytic Unit with catalyst
regenerator, Sulfur Recovery Unit, and Catalytic Reformer Unit with catalyst regenerator
(Ultraformer). Tesoro checks draeger tubes weekly for color change and changes HCl
absorption material when this indicator signals need. Records were made available. The
most recent Subpart UUU report was received by DAQ on January 31, 2023.

40 CFR 63.1563 When do I have to comply with this subpart?
Status: In Compliance. The compliance date was in 2004.
40 CFR 63.1564 What are my requirements for metal HAP emissions from catalytic cracking units?

(a) What emission limitations and work practice standards must I meet? You must:
(1) Meet each emission limitation in Table 1 of this subpart that applies to you. If your catalytic
racking unit is subject to the NSPS for PM in §60.102 of this chapter, you must meet the emission
limitations for NSPS units. If your catalytic cracking unit isn't subject to the NSPS for PM, you can
choose from the four options in paragraphs (a)(1)(i) through (iv) of this section:
(i) You can elect to comply with the NSPS requirements (Option 1);
(ii) You can elect to comply with the PM emission limit (Option 2);
(iii) You can elect to comply with the Nickel (Ni) lb/hr emission limit (Option 3); or
(iv) You can elect to comply with the Ni lb/1,000 lbs of coke burn-off emission limit (Option 4).
(2) Comply with each operating limit in Table 2 of this subpart that applies to you.
(3) Prepare an operation, maintenance, and monitoring plan according to the requirements in
§63.1574(f) and operate at all times according to the procedures in the plan.

(4) The emission limitations and operating limits for metal HAP emissions from catalytic cracking
units required in paragraphs (a)(1) and (2) of this section do not apply during periods of planned
maintenance preapproved by the applicable permitting authority according to the requirements in
§63.1575(j).

(b) How do I demonstrate initial compliance with the emission limitations and work practice standard?
You must:
(1) Install, operate, and maintain a continuous monitoring system(s) according to the
requirements in §63.1572 and Table 3 of this subpart.
80
(2) Conduct a performance test for each catalytic cracking unit not subject to the NSPS for PM
according to the requirements in §63.1571 and under the conditions specified in Table 4 of this subpart.
(3) Establish each site-specific operating limit in Table 2 of this subpart that applies to you
according to the procedures in Table 4 of this subpart.
(4) Use the procedures in paragraphs (b)(4)(i) through (iv) of this section to determine initial
compliance with the emission limitations.
(i) If you elect Option 1 in paragraph (a)(1)(i) of this section, the NSPS requirements, compute
the PM emission rate (lb/1,000 lbs of coke burn-off) for each run using Equations 1, 2, and 3 (if
applicable) of this section as follows:

(5) Demonstrate initial compliance with each emission limitation that applies to you according to
Table 5 of this subpart.

(6) Demonstrate initial compliance with the work practice standard in paragraph (a)(3) of this
section by submitting your operation, maintenance, and monitoring plan to your permitting authority as
part of your Notification of Compliance Status.

(7) Submit the Notification of Compliance Status containing the results of the initial compliance
demonstration according to the requirements in §63.1574.
(c) How do I demonstrate continuous compliance with the emission limitations and work practice
standards? You must:
(1) Demonstrate continuous compliance with each emission limitation in Tables 1 and 2 of this
subpart that applies to you according to the methods specified in Tables 6 and 7 of this subpart.
(2) Demonstrate continuous compliance with the work practice standard in paragraph (a)(3) of
this section by maintaining records to document conformance with the procedures in your operation,
maintenance, and monitoring plan.
Status: In Compliance. Tesoro elected to comply with option one with a PM limit of 1
lb/1000 lb coke burned (this is based on an AMR/approved alternate under NSPS). CO is
based on CEM data to show compliance with 500 ppm standard. An OMP has been
completed and is in the main file. The monitoring parameters used are regen blower flow
rate, pressure drop, liquid to gas ratio, and CO/O2 CEMs.
Stack testing is conducted annually. The latest test was performed May 1, 2024. Test results
were submitted to DAQ and evaluated in DAQC-775-24. DAQ calculated results for PM
were 0.364 lb/1000 lb coke burned.
40 CFR 63.1565 What are my requirements for organic HAP emissions from catalytic cracking units?

(a) What emission limitations and work practice standards must I meet? You must:
(1) Meet each emission limitation in Table 8 of this subpart that applies to you. If your catalytic
cracking unit is subject to the NSPS for carbon monoxide (CO) in §60.103 of this chapter, you must meet
the emission limitations for NSPS units. If your catalytic cracking unit isn't subject to the NSPS for CO,
you can choose from the two options in paragraphs (a)(1)(i) through (ii) of this section:
(i) You can elect to comply with the NSPS requirements (Option 1); or

(b) How do I demonstrate initial compliance with the emission limitations and work practice standards?
81
You must:

(1) Install, operate, and maintain a continuous monitoring system according to the requirements
in §63.1572 and Table 10 of this subpart. Except:
(i) Whether or not your catalytic cracking unit is subject to the NSPS for CO in §60.103 of this
chapter, you don't have to install and operate a continuous emission monitoring system if you show that
CO emissions from your vent average less than 50 parts per million (ppm), dry basis. You must get an
exemption from your permitting authority, based on your written request. To show that the emissions
average is less than 50 ppm (dry basis), you must continuously monitor CO emissions for 30 days using
a CO continuous emission monitoring system that meets the requirements in §63.1572.

(2) Conduct each performance test for a catalytic cracking unit not subject to the NSPS for CO
according to the requirements in §63.1571 and under the conditions specified in Table 11 of this subpart.
(3) Establish each site-specific operating limit in Table 9 of this subpart that applies to you
according to the procedures in Table 11 of this subpart.
(4) Demonstrate initial compliance with each emission limitation that applies to you according to
Table 12 of this subpart.
(5) Demonstrate initial compliance with the work practice standard in paragraph (a)(3) of this
section by submitting the operation, maintenance, and monitoring plan to your permitting authority as
part of your Notification of Compliance Status according to §63.1574.
(6) Submit the Notification of Compliance Status containing the results of the initial compliance
demonstration according to the requirements in §63.1574.

(c) How do I demonstrate continuous compliance with the emission limitations and work practice
standards? You must:

(1) Demonstrate continuous compliance with each emission limitation in Tables 8 and 9 of this
subpart that applies to you according to the methods specified in Tables 13 and 14 of this subpart.
(2) Demonstrate continuous compliance with the work practice standard in paragraph (a)(3) of
this section by complying with the procedures in your operation, maintenance, and monitoring plan.
Status: In Compliance. Tesoro elected to comply with option one with a PM limit of
1lb/1000lb coke burned (this is based on an AMR/approved alternate under NSPS). CO is
based on CEM data to show compliance with 500 ppm standard. An OMP has been
completed and is in the main file. The monitoring parameters used are regen blower flow
rate, pressure drop, liquid to gas ratio, and CO/O2 CEMs.
40 CFR 63.1566 What are my requirements for organic HAP emissions from catalytic reforming units?

(a) What emission limitations and work practice standards must I meet? You must:
(1) Meet each emission limitation in Table 15 of this subpart that applies to you. You can choose
from the two options in paragraphs (a)(1)(i) through (ii) of this section:
(i) You can elect to vent emissions of total organic compounds (TOC) to a flare that meets the
control device requirements in §63.11(b) (Option 1); or
(ii) You can elect to meet a TOC or nonmethane TOC percent reduction standard or
concentration limit, whichever is less stringent (Option 2).
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(2) Comply with each site-specific operating limit in Table 16 of this subpart that applies to you.

(3) Except as provided in paragraph (a)(4) of this section, the emission limitations in Tables 15
and 16 of this subpart apply to emissions from catalytic reforming unit process vents associated with
initial catalyst depressuring and catalyst purging operations that occur prior to the coke burn- off cycle.
The emission limitations in Tables 15 and 16 of this subpart do not apply to the coke burn-off, catalyst
rejuvenation, reduction or activation vents, or to the control systems used for these vents.

(4) The emission limitations in Tables 15 and 16 of this subpart do not apply to emissions from
process vents during depressuring and purging operations when the reactor vent pressure is 5 pounds per
square inch gauge (psig) or less.

(5) Prepare an operation, maintenance, and monitoring plan according to the requirements in
§63.1574(f) and operate at all times according to the procedures in the plan.

(b) How do I demonstrate initial compliance with the emission limitations and work practice
standard? You must:

(1) Install, operate, and maintain a continuous monitoring system(s) according to the
requirements in §63.1572 and Table 17 of this subpart.

(2) Conduct each performance test for a catalytic reforming unit according to the requirements in
§63.1571 and under the conditions specified in Table 18 of this subpart.

(3) Establish each site-specific operating limit in Table 16 of this subpart that applies to you
according to the procedures in Table 18 of this subpart.

(4) Use the procedures in paragraph (b)(4)(i) or (ii) of this section to determine initial compliance
with the emission limitations.

(i) If you elect the percent reduction standard under Option 2, calculate the emission rate of
nonmethane TOC using Equation 1 of this section (if you use Method 25) or Equation 2 of this section (if
you use Method 25A or Methods 25A and 18), then calculate the mass emission reduction using Equation
3 of this section as follows:

(5) You are not required to do a TOC performance test if:

(i) You elect to vent emissions to a flare as provided in paragraph (a)(1)(i) of this section (Option
1); or

(ii) You elect the TOC percent reduction or concentration limit in paragraph (a)(1)(ii) of this
section (Option 2), and you use a boiler or process heater with a design heat input capacity of 44 MW or
greater or a boiler or process heater in which all vent streams are introduced into the flame zone.

(6) Demonstrate initial compliance with each emission limitation that applies to you according to
Table 19 of this subpart.

(7) Demonstrate initial compliance with the work practice standard in paragraph (a)(5) of this
section by submitting the operation, maintenance, and monitoring plan to your permitting authority as
part of your Notification of Compliance Status.

83
(8) Submit the Notification of Compliance Status containing the results of the initial compliance
demonstration according to the requirements in §63.1574.

(c) How do I demonstrate continuous compliance with the emission limitations and work practice
standards? You must:

(1) Demonstrate continuous compliance with each emission limitation in Tables 15 and 16 of this
subpart that applies to you according to the methods specified in Tables 20 and 21 of this subpart.

(2) Demonstrate continuous compliance with the work practice standards in paragraph (a)(3) of
this section by complying with the procedures in your operation, maintenance, and monitoring plan.
Status: In compliance. Tesoro elected to comply with option one and vents all organic
HAPS to the flare system (South Flare) and the Flare Gas Recovery System (with the
exception of the SRU which only vents to the flare). This flare meets subpart A
requirements. No testing is required under this part. The OMP and NOC have been
submitted and are in the source files.
40 CFR 63.1567 What are my requirements for inorganic HAP emissions from catalytic reforming units?

(a) What emission limitations and work practice standards must I meet? You must:

(1) Meet each emission limitation in Table 22 to this subpart that applies to you. If you operate a
catalytic reforming unit in which different reactors in the catalytic reforming unit are regenerated in
separate regeneration systems, then these emission limitations apply to each separate regeneration system.
These emission limitations apply to emissions from catalytic reforming unit process vents associated with
the coke burn-off and catalyst rejuvenation operations during coke burn-off and catalyst regeneration.
You can choose from the two options in paragraphs (a)(1)(i) through (ii) of this section:
(i) You can elect to meet a percent reduction standard for hydrogen chloride (HCl) emissions
(Option 1); or
(ii) You can elect to meet an HCl concentration limit (Option 2).
(2) Meet each site-specific operating limit in Table 23 of this subpart that applies to you. These
operating limits apply during coke burn-off and catalyst rejuvenation.
(3) Prepare an operation, maintenance, and monitoring plan according to the requirements in
§63.1574(f) and operate at all times according to the procedures in the plan.
(b) How do I demonstrate initial compliance with the emission limitations and work practice
standard? You must:
(1) Install, operate, and maintain a continuous monitoring system(s) according to the
requirements in §63.1572 and Table 24 of this subpart.
(2) Conduct each performance test for a catalytic reforming unit according to the requirements in
§63.1571 and the conditions specified in Table 25 of this subpart.
(3) Establish each site-specific operating limit in Table 23 of this subpart that applies to you
according to the procedures in Table 25 of this subpart.
(4) Use the equations in paragraphs (b)(4)(i) through (iv) of this section to determine initial
compliance with the emission limitations.
84
(i) Correct the measured HCl concentration for oxygen (O2 ) content in the gas stream using
Equation 1 of this section as follows:
(5) Demonstrate initial compliance with each emission limitation that applies to you according to
Table 26 of this subpart.
(6) Demonstrate initial compliance with the work practice standard in paragraph (a)(3) of this
section by submitting the operation, maintenance, and monitoring plan to your permitting
authority as part of your Notification of Compliance Status.
(7) Submit the Notification of Compliance Status containing the results of the initial compliance
demonstration according to the requirements in §63.1574.
(c) How do I demonstrate continuous compliance with the emission limitations and work practice
standard? You must:

(1) Demonstrate continuous compliance with each emission limitation in Tables 22 and 23 of this
subpart that applies to you according to the methods specified in Tables 27 and 28 of this subpart.

(2) Demonstrate continuous compliance with the work practice standard in paragraph (a)(3) of
this section by maintaining records to document conformance with the procedures in your operation,
maintenance and monitoring plan.

Status: In Compliance. Tesoro has elected option two and maintains the HCl concentration
at the fixed bed absorber to 10 ppmdv or lower at 3% O2. HCL is measured weekly using
calorimetric tubes that change colors to indicate HCL levels. The OMP and NOCs have
been submitted and are in the source files. Records were made available.

40 CFR 63.1568 What are my requirements for HAP emissions from sulfur recovery units?

(a) What emission limitations and work practice standard must I meet? You must:
(1) Meet each emission limitation in Table 29 of this subpart that applies to you. If your sulfur
recovery unit is subject to the NSPS for sulfur oxides in §60.104 of this chapter, you must meet the
emission limitations for NSPS units. If your sulfur recovery unit isn't subject to the NSPS for sulfur
oxides, you can choose from the options in paragraphs (a)(1)(i) through (ii) of this section:
(i) You can elect to meet the NSPS requirements (Option 1); or
(ii) You can elect to meet the total reduced sulfur (TRS) emission limitation (Option 2).
(2) Meet each operating limit in Table 30 of this subpart that applies to you.
(3) Prepare an operation, maintenance, and monitoring plan according to the requirements in
§63.1574(f) and operate at all times according to the procedures in the plan.
(b) How do I demonstrate initial compliance with the emission limitations and work practice standards?
You must:
(1) Install, operate, and maintain a continuous monitoring system according to the requirements
in §63.1572 and Table 31 of this subpart.
(2) Conduct each performance test for a sulfur recovery unit not subject to the NSPS for sulfur
oxides according to the requirements in §63.1571 and under the conditions specified in Table 32 of this
subpart.
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(3) Establish each site-specific operating limit in Table 30 of this subpart that applies to you
according to the procedures in Table 32 of this subpart.
(4) Correct the reduced sulfur samples to zero percent excess air using Equation 1 of this section
as follows:
(5) Demonstrate initial compliance with each emission limitation that applies to you according to
Table 33 of this subpart.
(6) Demonstrate initial compliance with the work practice standard in paragraph (a)(3) of this
section by submitting the operation, maintenance, and monitoring plan to your permitting authority as
part of your notification of compliance status.
(7) Submit the notification of compliance status containing the results of the initial compliance
demonstration according to the requirements in §63.1574.

(c) How do I demonstrate continuous compliance with the emission limitations and work practice
standards? You must:
(1) Demonstrate continuous compliance with each emission limitation in Tables 29 and 30 of this
subpart that applies to you according to the methods specified in Tables 34 and 35 of this subpart.
(2) Demonstrate continuous compliance with the work practice standard in paragraph (a)(3) of
this section by complying with the procedures in your operation, maintenance, and monitoring plan.
Status: In Compliance. Tesoro has a sulfur unit which is rated at <20 LT/D of elemental
sulfur. They have elected to meet the 300 ppm TRS standard. Minimum incinerator
temperature and O2 levels in exhaust gases have been established through stack testing.
During this inspection, temperature was 1,170 degrees F and O2 was 8.06%. The OMP and
NOCs have been submitted and are contained in the source files.
40 CFR 63.1569 What are my requirements for HAP emissions from bypass lines?

(a) What work practice standards must I meet?
(1) You must meet each work practice standard in Table 36 of this subpart that applies to you.
You can choose from the four options in paragraphs (a)(1)(i) through (iv) of this section:
(i) You can elect to install an automated system (Option 1);
(ii) You can elect to use a manual lock system (Option 2);
(iii) You can elect to seal the line (Option 3); or
(iv) You can elect to vent to a control device (Option 4).
(2) As provided in §63.6(g), we, the EPA, may choose to grant you permission to use an
alternative to the work practice standard in paragraph (a)(1) of this section.
(3) You must prepare an operation, maintenance, and monitoring plan according to the
requirements in §63.1574(f) and operate at all times according to the procedures in the plan.

(b) How do I demonstrate initial compliance with the work practice standards? You must:
(1) If you elect the option in paragraph (a)(1)(i) of this section, conduct each performance test for
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a bypass line according to the requirements in §63.1571 and under the conditions specified in Table 37 of
this subpart.
(2) Demonstrate initial compliance with each work practice standard in Table 36 of this subpart
that applies to you according to Table 38 of this subpart.
(3) Demonstrate initial compliance with the work practice standard in paragraph (a)(3) of this
section by submitting the operation, maintenance, and monitoring plan to your permitting authority as
part of your notification of compliance status.
(4) Submit the notification of compliance status containing the results of the initial compliance
demonstration according to the requirements in §63.1574.

(c) How do I demonstrate continuous compliance with the work practice standards? You must:
(1) Demonstrate continuous compliance with each work practice standard in Table 36 of this
subpart that applies to you according to the requirements in Table 39 of this subpart.
(2) Demonstrate continuous compliance with the work practice standard in paragraph (a)(2) of
this section by complying with the procedures in your operation, maintenance, and monitoring plan.
Status: In Compliance. The UFU has one manual bypass in the catalyst regeneration system
for bypass of the HCl absorber. Tesoro has chosen option 2 and has implemented a car-seal
lockout program. Weekly inspections are performed and recorded.
General Compliance Requirements

40 CFR 63.1570 What are my general requirements for complying with this subpart?
(a) You must be in compliance with all of the non-opacity standards in this subpart during the
times specified in §63.6(f)(1).
(b) You must be in compliance with the opacity and visible emission limits in this subpart during
the times specified in §63.6(h)(1).
(c) You must always operate and maintain your affected source, including air pollution control
and monitoring equipment, according to the provisions in §63.6(e)(1)(i). During the period between the
compliance date specified for your affected source and the date upon which continuous monitoring
systems have been installed and validated and any applicable operating limits have been set, you must
maintain a log detailing the operation and maintenance of the process and emissions control equipment.
(d) You must develop a written startup, shutdown, and malfunction plan (SSMP) according to
the provisions in §63.6(e)(3).
(e) [Reserved]
(f) You must report each instance in which you did not meet each emission limitation and each
operating limit in this subpart that applies to you. This includes periods of startup, shutdown, and
malfunction. You also must report each instance in which you did not meet the work practice standards in
this subpart that apply to you. These instances are deviations from the emission limitations and work
practice standards in this subpart. These deviations must be reported according to the requirements in
§63.1575.
(g) Consistent with §§63.6(e) and 63.7(e)(1), deviations that occur during a period of startup,
shutdown, or malfunction are not violations if you demonstrate to the Administrator's satisfaction that you
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were operating in accordance with §63.6(e)(1). The SSMP must include elements designed to minimize
the frequency of such periods (i.e., root cause analysis). The Administrator will determine whether
deviations that occur during a period of startup, shutdown, or malfunction are violations, according to the
provisions in §63.6(e).
Status: In Compliance. The company has a SSMP and all required monitoring is
completed. No changes have been made to the plan. See specific conditions above.
63.1571 How and when do I conduct a performance test or other initial compliance demonstration?

(a) When must I conduct a performance test? You must conduct performance tests and report the
results by no later than 150 days after the compliance date specified for your source in §63.1563 and
according to the provisions in §63.7(a)(2). If you are required to do a performance evaluation or test for a
semi-regenerative catalytic reforming unit catalyst regenerator vent, you may do them at the first
regeneration cycle after your compliance date and report the results in a follow-up Notification of
Compliance Status report due no later than 150 days after the test.
(1) For each emission limitation or work practice standard where initial compliance is not
demonstrated using a performance test, opacity observation, or visible emission observation, you must
conduct the initial compliance demonstration within 30 calendar days after the compliance date that is
specified for your source in §63.1563.
(2) For each emission limitation where the averaging period is 30 days, the 30-day period for
demonstrating initial compliance begins at 12:00 a.m. on the compliance date that is specified for your
source in §63.1563 and ends at 11:59 p.m., 30 calendar days after the compliance date that is specified
for your source in §63.1563.
(3) If you commenced construction or reconstruction between September 11, 1998 and April 11,
2002, you must demonstrate initial compliance with either the proposed emission limitation or the
promulgated emission limitation no later than October 8, 2002 or within 180 calendar days after startup of
the source, whichever is later, according to §63.7(a)(2)(ix).
(4) If you commenced construction or reconstruction between September 11, 1998 and April 11,
2002, and you chose to comply with the proposed emission limitation when demonstrating initial
compliance, you must conduct a second compliance demonstration for the promulgated emission
limitation by October 10, 2005, or after startup of the source, whichever is later, according to
§63.7(a)(2)(ix).
(b) What are the general requirements for performance test and performance evaluations? You
must:
(1) Conduct each performance test according to the requirements in §63.7(e)(1).
(2) Except for opacity and visible emission observations, conduct three separate test runs for
each performance test as specified in §63.7(e)(3). Each test run must last at least 1 hour.
(3) Conduct each performance evaluation according to the requirements in §63.8(e).
(4) Not conduct performance tests during periods of startup, shutdown, or malfunction, as
specified in §63.7(e)(1).
(5) Calculate the average emission rate for the performance test by calculating the emission rate
for each individual test run in the units of the applicable emission limitation using Equation 2, 5, or 8 of
§63.1564, and determining the arithmetic average of the calculated emission rates.

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(c) What procedures must I use for an engineering assessment? You may choose to use an
engineering assessment to calculate the process vent flow rate, net heating value, TOC emission rate, and
total organic HAP emission rate expected to yield the highest daily emission rate when determining the
emission reduction or outlet concentration for the organic HAP standard for catalytic reforming units. If
you use an engineering assessment, you must document all data, assumptions, and procedures to the
satisfaction of the applicable permitting authority. An engineering assessment may include the approaches
listed in paragraphs (c)(1) through (c)(4) of this section. Other engineering assessments may be used but
are subject to review and approval by the applicable permitting authority.

(1) You may use previous test results provided the tests are representative of current operating
practices at the process unit, and provided EPA methods or approved alternatives were used;
(2) You may use bench-scale or pilot- scale test data representative of the process under
representative operating conditions;
(3) You may use maximum flow rate, TOC emission rate, organic HAP emission rate, or organic
HAP or TOC concentration specified or implied within a permit limit applicable to the process
vent; or
(4) You may use design analysis based on engineering principles, measurable process
parameters, or physical or chemical laws or properties. Examples of analytical methods include,
but are not limited to:
(i) Use of material balances based on process stoichiometry to estimate maximum TOC
concentrations;
(ii) Calculation of hourly average maximum flow rate based on physical equipment design such
as pump or blower capacities; and
(iii) Calculation of TOC concentrations based on saturation conditions.
(d) Can I adjust the process or control device measured values when establishing an operating
limit? If you do a performance test to demonstrate compliance, you must base the process or control
device operating limits for continuous parameter monitoring systems on the results measured during the
performance test. You may adjust the values measured during the performance test according to the
criteria in paragraphs (d)(1) through (3) of this section.
(1) If you must meet the HAP metal emission limitations in §63.1564, you elect the option in
paragraph (a)(1)(iii) in §63.1564 (Ni lb/hr), and you use continuous parameter monitoring systems, you
must establish an operating limit for the equilibrium catalyst Ni concentration based on the laboratory
analysis of the equilibrium catalyst Ni concentration from the initial performance test. Section
63.1564(b)(2) allows you to adjust the laboratory measurements of the equilibrium catalyst Ni
concentration to the maximum level. You must make this adjustment using Equation 1 of this section as
follows:
(2) If you must meet the HAP metal emission limitations in §63.1564, you elect the option in
paragraph (a)(1)(iv) in §63.1564 (Ni lb/1,000 lb of coke burn-off), and you use continuous parameter
monitoring systems, you must establish an operating limit for the equilibrium catalyst Ni
concentration based on the laboratory analysis of the equilibrium catalyst Ni concentration from the initial
performance test. Section 63.1564(b)(2) allows you to adjust the laboratory measurements of the
equilibrium catalyst Ni concentration to the maximum level. You must make this adjustment using
Equation 2 of this section as follows:
(3) If you choose to adjust the equilibrium catalyst Ni concentration to the maximum level, you
89
can't adjust any other monitored operating parameter (i.e., gas flow rate, voltage, pressure drop, liquid-to-
gas ratio).
(4) Except as specified in paragraph (d)(3) of this section, if you use continuous parameter
monitoring systems, you may adjust one of your monitored operating parameters (flow rate, voltage and
secondary current, pressure drop, liquid-to-gas ratio) from the average of measured values during the
performance test to the maximum value (or minimum value, if applicable) representative of worst-case
operating conditions, if necessary. This adjustment of measured values may be done using control device
design specifications, manufacturer recommendations, or other applicable information. You must provide
supporting documentation and rationale in your Notification of Compliance Status, demonstrating to the
satisfaction of your permitting authority, that your affected source complies with the applicable emission
limit at the operating limit based on adjusted values.
(e) Can I change my operating limit? You may change the established operating limit by meeting
the requirements in paragraphs (e)(1) through (3) of this section.
(1) You may change your established operating limit for a continuous parameter monitoring
system by doing an additional performance test, a performance test in conjunction with an engineering
assessment, or an engineering assessment to verify that, at the new operating limit, you are in compliance
with the applicable emission limitation.
(2) You must establish a revised operating limit for your continuous parameter monitoring
system if you make any change in process or operating conditions that could affect control system
performance or you change designated conditions after the last performance or compliance tests were
done. You can establish the revised operating limit as described in paragraph (e)(1) of this section.
(3) You may change your site-specific opacity operating limit or Ni operating limit only by doing
a new performance test.
Status: In Compliance. Engineering assessments were not required for the sources listed.
All testing was done as discussed in the applicable subpart or method and operating
parameter limits were set during these tests. Subsequent testing has been performed. All
pretest protocols and test reports were submitted to the DAQ and have been evaluated
under separate memos.
40 CFR 63.1572 What are my monitoring installation, operation, and maintenance requirements?
(a) You must install, operate, and maintain each continuous emission monitoring system according to
the requirements in paragraphs (a)(1) through (4) of this section.

(1) You must install, operate, and maintain each continuous emission monitoring system according
to the requirements in Table 40 of this subpart.

(2) If you use a continuous emission monitoring system to meet the NSPS CO or SO2 limit, you
must conduct a performance evaluation of each continuous emission monitoring system according to the
requirements in §63.8 and Table 40 of this subpart. This requirement does not apply to an affected source
subject to the NSPS that has already demonstrated initial compliance with the applicable performance
specification.
(3) As specified in §63.8(c)(4)(ii), each continuous emission monitoring system must complete a
minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-
minute period.
(4) Data must be reduced as specified in §63.8(g)(2).
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(b) You must install, operate, and maintain each continuous opacity monitoring system according
to the requirements in paragraphs (b)(1) through (3) of this section.
(1) Each continuous opacity monitoring system must be installed, operated, and maintained
according to the requirements in Table 40 of this subpart.
(2) If you use a continuous opacity monitoring system to meet the NSPS opacity limit, you must
conduct a performance evaluation of each continuous opacity monitoring system according to the
requirements in §63.8 and Table 40 of this subpart. This requirement does not apply to
an affected source subject to the NSPS that has already demonstrated initial compliance with the
applicable performance specification.
(3) As specified in §63.8(c)(4)(i), each continuous opacity monitoring system must complete a
minimum of one cycle of sampling and analyzing for each successive 10- second period and one cycle of
data recording for each successive 6-minute period.
(c) You must install, operate, and maintain each continuous parameter monitoring system
according to the requirements in paragraphs (c)(1) through (5) of this section.
(1) The owner or operator shall install, operate, and maintain each continuous parameter
monitoring system in a manner consistent with the manufacturer's specifications or other written
procedures that provide adequate assurance that the equipment will monitor accurately. The owner or
operator shall also meet the equipment specifications in Table 41 of this subpart if pH strips or
colormetric tube sampling systems are used.
(2) The continuous parameter monitoring system must complete a minimum of one cycle of
operation for each successive 15-minute period. You must have a minimum of four successive cycles of
operation to have a valid hour of data (or at least two if a calibration check is performed during that hour
or if the continuous parameter monitoring system is out-of-control).
(3) Each continuous parameter monitoring system must have valid hourly average data from at
least 75 percent of the hours during which the process operated.
(4) Each continuous parameter monitoring system must determine and record the hourly average
of all recorded readings and if applicable, the daily average of all recorded readings for each operating
day. The daily average must cover a 24-hour period if operation is continuous or the number of hours of
operation per day if operation is not continuous.
(5) Each continuous parameter monitoring system must record the results of each inspection,
calibration, and validation check.
(d) You must monitor and collect data according to the requirements in paragraphs (d)(1) and (2)
of this section.
(1) Except for monitoring malfunctions, associated repairs, and required quality assurance or
control activities (including as applicable, calibration checks and required zero and span adjustments),
you must conduct all monitoring in continuous operation (or collect data at all required intervals) at all
times the affected source is operating.
(2) You may not use data recorded during monitoring malfunctions, associated repairs, and
required quality assurance or control activities for purposes of this regulation, including data averages and
calculations, for fulfilling a minimum data availability requirement, if applicable. You must use all the
data collected during all other periods in assessing the operation of the control device and associated
91
control system.
Status: In Compliance. Monitors have been installed and are operational. The CEMs are
tracked and reported through the State Electronic Data Report program and reviewed by
DAQ’s CEM specialist. These reports are in the main source file. Continuous parameter
monitoring systems are installed and reported in the semi-annual excess emission reports.
Those reports are reviewed by DAQ staff under separate cover.
40 CFR 63.1573 What are my monitoring alternatives?

Status: In Compliance. The company has submitted one alternative for PM lb/1000 lb coke
burn which was approved by EPA in 2004.

40 CFR 63.1575 What reports must I submit and when?

This section requires submission of semi-annual Reports for CEMS and CMPS. It also requires those
reports due under the Title V program.

Status: In Compliance. Tesoro submits semi-annual excess emission reports as well as the
quarterly SEDRs to DAQ. These reports are reviewed by staff and reported under separate
memos.

40 CFR 63.1576 What records must I keep, in what form, and for how long?

This section requires all records to be kept for a period of five years in a usable format with two years on-
site and the remaining off-site or on-site.
Status: In Compliance. All records are kept for five-plus years and are available on-site for
review.

40 CFR 60, Subpart QQQ – Standards of Performance for VOC Emissions From Petroleum Refinery
Wastewater Systems

60.690 - Applicability and designation of affected facility

(a)(1) The provisions of this subpart apply to affected facilities located in petroleum
refineries for which construction, modification, or reconstruction is commenced after
May 4, 1987.

Status: Subpart QQQ is applicable to the Benzene Saturation Unit, GHT, and DDU.
60.692-2 Standards: Individual drain systems.
(a)(1) Each drain shall be equipped with water seal controls.
(2) Each drain in active service shall be checked by visual or physical inspection initially
and monthly thereafter for indications of low water levels or other conditions that would
reduce the effectiveness of the water seal controls.
92
(3) Except as provided in paragraph (a)(4) of this section, each drain out of active service
shall be checked by visual or physical inspection initially and weekly thereafter for
indications of low water levels or other problems that could result in VOC emissions.
(4) As an alternative to the requirements in paragraph (a)(3) of this section, if an owner or
operator elects to install a tightly sealed cap or plug over a drain that is out of service,
inspections shall be conducted initially and semiannually to ensure caps or plugs are in
place and properly installed.
(5) Whenever low water levels or missing or improperly installed caps or plugs are
identified, water shall be added or first efforts at repair shall be made as soon as
practicable, but not later than 24 hours after detection, except as provided in §60.692–6.
(b)(1) Junction boxes shall be equipped with a cover and may have an open vent pipe.
The vent pipe shall be at least 90 cm (3 ft) in length and shall not exceed 10.2 cm (4 in) in
diameter.
(2) Junction box covers shall have a tight seal around the edge and shall be kept in place
at all times, except during inspection and maintenance.
(3) Junction boxes shall be visually inspected initially and semiannually thereafter to
ensure that the cover is in place and to ensure that the cover has a tight seal around the
edge.
(4) If a broken seal or gap is identified, first effort at repair shall be made as soon as
practicable, but not later than 15 calendar days after the broken seal or gap is identified,
except as provided in §60.692–6.
(c)(1) Sewer lines shall not be open to the atmosphere and shall be covered or enclosed in
a manner so as to have no visual gaps or cracks in joints, seals, or other emission
interfaces.
(2) The portion of each unburied sewer line shall be visually inspected initially and
semiannually thereafter for indication of cracks, gaps, or other problems that could result
in VOC emissions.
(3) Whenever cracks, gaps, or other problems are detected, repairs shall be made as soon
as practicable, but not later than 15 calendar days after identification, except as provided
in §60.692–6.
(d) Except as provided in paragraph (e) of this section, each modified or reconstructed
individual drain system that has a catch basin in the existing configuration prior to May 4,
1987 shall be exempt from the provisions of this section.
(e) Refinery wastewater routed through new process drains and a new first common
downstream junction box, either as part of a new individual drain system or an existing
individual drain system, shall not be routed through a downstream catch basin.
Status: In Compliance. The Benzene Saturation Unit is equipped with a closed drain system
93
that vents to a flare. Drains in the GHT and DDU are checked monthly for low water levels
or that caps are securely in place. Affected junction boxes are inspected semiannually.
Sewer lines are not open to the atmosphere. Records were made available. Drains and
junction boxes were spot checked during this inspection. The most recent semi-annual
Subpart QQQ report was received on July 22, 2024.
60.692-3 Standards: Oil-water separators.
(a) Each oil-water separator tank, slop oil tank, storage vessel, or other auxiliary
equipment subject to the requirements of this subpart shall be equipped and operated with
a fixed roof, which meets the following specifications, except as provided in paragraph
(d) of this section or in §60.693–2.
Status: A letter of voluntary disclosure pursuant to the Utah Environmental Self-
Evaluation Act was received on August 6, 2019. This disclosure identified two units that are
potentially subject to 40 CFR Part 60, Subpart QQQ. Specifically, the API Oil Water
Separator and Tank 241 located at the refinery. Tesoro has committed to achieve
compliance as soon as possible and provide updated schedules and progress reports.
Floating roof tank 241 has been constructed and now used for stormwater and surge. A
Subpart Kb startup notification for Tank 241 was received on November 10, 2022.
60.692-5 Standards: Closed vent systems and control devices.
(a) Enclosed combustion devices shall be designed and operated to reduce the VOC
emissions vented to them with an efficiency of 95 percent or greater or to provide a
minimum residence time of 0.75 seconds at a minimum temperature of 816 °C (1,500
°F).
(b) Vapor recovery systems (for example, condensers and adsorbers) shall be designed
and operated to recover the VOC emissions vented to them with an efficiency of 95
percent or greater.
(c) Flares used to comply with this subpart shall comply with the requirements of 40 CFR
60.18.
(d) Closed vent systems and control devices used to comply with provisions of this
subpart shall be operated at all times when emissions may be vented to them.
(e)(1) Closed vent systems shall be designed and operated with no detectable emissions,
as indicated by an instrument reading of less than 500 ppm above background, as
determined during the initial and semiannual inspections by the methods specified in
§60.696.
(2) Closed vent systems shall be purged to direct vapor to the control device.
(3) A flow indicator shall be installed on a vent stream to a control device to ensure that
the vapors are being routed to the device.
(4) All gauging and sampling devices shall be gas-tight except when gauging or sampling
is taking place.
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(5) When emissions from a closed system are detected, first efforts at repair to eliminate
the emissions shall be made as soon as practicable, but not later than 30 calendar days
from the date the emissions are detected, except as provided in §60.692–6.

Status: In Compliance. The Benzene Saturation Unit is equipped with a closed drain system
that vents to a flare which complies with 40 CFR 60.18. Inspections have been performed at
least semi-annually. The initial inspection was performed and reported to UDAQ in 2012.

60.692-6 Standards: Delay of repair.
(a) Delay of repair of facilities that are subject to the provisions of this subpart will be
allowed if the repair is technically impossible without a complete or partial refinery or
process unit shutdown.
(b) Repair of such equipment shall occur before the end of the next refinery or process
unit shutdown.

Status: In Compliance. There were no delays of repair in the Benzene Saturation Unit since
the previous inspection.

60.693-1 Alternative standards for individual drain systems.

Status: In Compliance. Tesoro is using this alternative and built the Benzene Saturation
Unit with a closed drain system that vents to a flare.

60.695 Monitoring of operations.

(4) Where a flare is used for VOC emission reduction, the owner or operator shall comply
with the monitoring requirements of 40 CFR 60.18(f)(2).

Status: In Compliance. The Benzene Saturation Unit is equipped with a closed drain system
that vents to a flare which complies with 40 CFR 60.18.
60.696 Performance test methods and procedures and compliance provisions.
(a) Before using any equipment installed in compliance with the requirements of
§60.692–2, §60.692–3, §60.692–4, §60.692–5, or §60.693, the owner or operator shall
inspect such equipment for indications of potential emissions, defects, or other problems
that may cause the requirements of this subpart not to be met. Points of inspection shall
include, but are not limited to, seals, flanges, joints, gaskets, hatches, caps, and plugs.
(b) The owner or operator of each source that is equipped with a closed vent system and
control device as required in §60.692–5 (other than a flare) is exempt from §60.8 of the
General Provisions and shall use Method 21 to measure the emission concentrations,
using 500 ppm as the no detectable emission limit. The instrument shall be calibrated
each day before using. The calibration gases shall be:
(1) Zero air (less than 10 ppm of hydrocarbon in air), and
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(2) A mixture of either methane or n-hexane and air at a concentration of approximately,
but less than, 10,000 ppm methane or n-hexane.

Status: In Compliance. An initial inspection of the Benzene Saturation Unit was performed
and reported to UDAQ in 2012. Records of semi-annual inspections were made available.
60.697 Recordkeeping requirements.
(a) Each owner or operator of a facility subject to the provisions of this subpart shall
comply with the recordkeeping requirements of this section. All records shall be retained
for a period of 2 years after being recorded unless otherwise noted.
(b)(1) For individual drain systems subject to §60.692–2, the location, date, and
corrective action shall be recorded for each drain when the water seal is dry or otherwise
breached, when a drain cap or plug is missing or improperly installed, or other problem is
identified that could result in VOC emissions, as determined during the initial and
periodic visual or physical inspection.
(2) For junction boxes subject to §60.692–2, the location, date, and corrective action shall
be recorded for inspections required by §60.692–2(b) when a broken seal, gap, or other
problem is identified that could result in VOC emissions.
(c) For oil-water separators subject to §60.692–3, the location, date, and corrective action
shall be recorded for inspections required by by §60.692–3(a) when a problem is
identified that could result in VOC emissions.
(d) For closed vent systems subject to §60.692–5 and completely closed drain systems
subject to §60.693–1, the location, date, and corrective action shall be recorded for
inspections required by §60.692–5(e) during which detectable emissions are measured or
a problem is identified that could result in VOC emissions.
(e)(1) If an emission point cannot be repaired or corrected without a process unit
shutdown, the expected date of a successful repair shall be recorded.
(2) The reason for the delay as specified in §60.692–6 shall be recorded if an emission
point or equipment problem is not repaired or corrected in the specified amount of time.
(f)(1) A copy of the design specifications for all equipment used to comply with the
provisions of this subpart shall be kept for the life of the source in a readily accessible
location.
(2) The following information pertaining to the design specifications shall be kept.
(i) Detailed schematics, and piping and instrumentation diagrams.
(ii) The dates and descriptions of any changes in the design specifications.
(3) The following information pertaining to the operation and maintenance of closed
drain systems and closed vent systems shall be kept in a readily accessible location.
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(iii) Periods when the closed vent systems and control devices required in §60.692 are not
operated as designed, including periods when a flare pilot does not have a flame shall be
recorded and kept for 2 years after the information is recorded.
(iv) Dates of startup and shutdown of the closed vent system and control devices required
in §60.692 shall be recorded and kept for 2 years after the information is recorded.
(v) The dates of each measurement of detectable emissions required in §§60.692, 60.693,
or 60.692–5 shall be recorded and kept for 2 years after the information is recorded.

Status: In Compliance. Records are kept for at least two years. Drain and junction box
inspections and corrective actions are recorded as required. Records of semi-annual closed
vent system inspections have been kept. There has not been any delay of repair events.
Design specifications and diagrams are available. The most recent semi-annual Subpart
QQQ report was received on July 22, 2024.
60.698 Reporting requirements.
(a) An owner or operator electing to comply with the provisions of §60.693 shall notify
the Administrator of the alternative standard selected in the report required in §60.7.
(b)(1) Each owner or operator of a facility subject to this subpart shall submit to the
Administrator within 60 days after initial startup a certification that the equipment
necessary to comply with these standards has been installed and that the required initial
inspections or tests of process drains, sewer lines, junction boxes, oil-water separators,
and closed vent systems and control devices have been carried out in accordance with
these standards. Thereafter, the owner or operator shall submit to the Administrator
semiannually a certification that all of the required inspections have been carried out in
accordance with these standards.
(2) Each owner or operator of an affected facility that uses a flare shall submit to the
Administrator within 60 days after initial startup, as required under §60.8(a), a report of
the results of the performance test required in §60.696(c).
(c) A report that summarizes all inspections when a water seal was dry or otherwise
breached, when a drain cap or plug was missing or improperly installed, or when cracks,
gaps, or other problems were identified that could result in VOC emissions, including
information about the repairs or corrective action taken, shall be submitted initially and
semiannually thereafter to the Administrator.
Status: In Compliance. An initial inspection of the Benzene Saturation Unit has been
recorded and reported to UDAQ. UDAQ has also received notification of using the
alternative described in 60.693-1 by constructing a completely closed drain system venting
to a flare. The most recent semi-annual Subpart QQQ report was received on July 22, 2024.

40 CFR 60, Subpart GGG - Standards of Performance for Equipment Leaks of VOC in Petroleum
Refineries

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60.590 - Applicability and designation of affected facility

Status: Subpart GGG is applicable to components in the Ultraformer, Number 2 Crude
Unit, Vapor Recovery Unit, Tank 331, Fluid Catalytic Cracking Unit, Sulfur Recovery Unit,
Alkylation Unit, DDU, and Cogeneration Unit. Tesoro complies with Subpart GGGa which
satisfies Subpart GGG. NSPS Subpart GGG applies to equipment at petroleum refineries
that commence construction or modification after January 4, 1983, but before November 7,
2006, while NSPS Subpart GGGa applies to equipment at petroleum refineries that
commence construction or modification after November 7, 2006. Tesoro voluntarily elected
to comply with NSPS GGGa in 2015. All equipment is monitored for leaks in accordance
with the requirements of 40 CFR 60 Subpart GGGa.

40 CFR 60, Subpart VV - Standards of Performance for Equipment Leaks of VOC in Synthetic Organic
Chemicals Manufacturing Industry

60.482-1 Standards: General.

(b) Compliance with '' 60.482-1 to 60.482-10 will be determined by review of records
and reports, review of performance test results, and inspection using the methods and
procedures specified in ' 60.485.

Status: In Compliance. Quarterly monitoring reports have been submitted to UDAQ and
reviewed. Records were evaluated during this inspection and found in compliance. Tesoro
complies with Subpart VVa which satisfies Subpart VV requirements.

60.482-2 Standards: Pumps in light liquid service.
60.482-3 Compressors.
60.482-4 Standards: Pressure relief devices in gas/vapor service.
60.482-5 Standards: Sampling connection systems.
60.482-6 Standards: Open-ended valves or lines.
60.482-7 Standards: Valves in gas/vapor service in light liquid service.
60.482-8 Standards: Pumps and valves in heavy liquid service, pressure relief devices in light liquid or
heavy liquid service, and flanges, and other connectors.
60.482-9 Standards: Delay of repair.
60.482-10 Standards: Closed vent systems and control devices.

Status: In Compliance. Tesoro follows the monitoring methods described in these sections
for the affected components. The company maintains a LEAK DAS database, which tracks
all components and records all required information as the components are monitored.
First attempt at repair is made on the spot or within a maximum of fifteen days. All
repaired components are monitored for leaks immediately following repair. Pressure relief
valves are monitored for no detectable emissions within five days of each release. All
sampling connection systems are either closed-vent or closed-purge. All open-ended valves
or lines are equipped with a plug or double valve. Pumps and valves in heavy liquid service,
pressure relief devices in light liquid or heavy liquid service, and flanges/other connectors
are monitored within five days when a leak is detected and repaired within fifteen days as
required. Delays of repair are explained in the quarterly reports. Closed vent systems and
control devices include two NSPS flare systems that are operated in accordance with the
requirements of 60.18, and the Vapor Recovery Unit which is designed to recover VOC
emissions at a rate of 95 percent or greater. Tesoro complies with Subpart VVa which
satisfies Subpart VV requirements.
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60.483-1 Alternative standards for valves-allowable percentage of valves leaking.
60.483-2 Alternative standards for valves-skip period leak detection and repair.
60.484 Equivalence of means of emission limitation.

Status: No longer applicable per the consent decree.

60.485 Test methods and procedures.

Status: In Compliance. Method 21 is used to determine compliance. Tesoro has contracted
out the VOC monitoring program to Alliance, a company that specializes in petroleum
refinery monitoring systems.

60.486 Record keeping requirements.

Status: In Compliance. Records of all monitoring are maintained in LEAK DAS.
Weatherproof tags are placed on all leaking components and remain in place for a period of
time following repair. Components on the delay of repair list were properly tagged. Unsafe
and difficult to monitor valves are recorded and have been reported to UDAQ.

60.487 Reporting requirements.

Status: In Compliance. Quarterly reports are submitted and reviewed for completeness by
UDAQ. Each report includes information on all units monitored, number of components
monitored, detectable leaks, repairs, and leaks on the delay of repair list. The most recent
VOC monitoring report was received on January 11, 2024.

NSPS (Part 60), GGGa - Standards of Performance for Equipment Leaks of VOC in Petroleum Refineries

Status: In Compliance. Tesoro submits a Subpart GGGa report quarterly for affected units.
The most recent VOC monitoring report was received on January 11, 2024.

NSPS (Part 60), XX - Standards of Performance for Bulk Terminals
60.502(d) Vapors shall be prevented from passing between loading racks.

Status: In Compliance. Vapors are prevented from passing between loading racks at the
TLR bays through the use of check valves. Each bay has check valves installed on the vapor
recovery line.

60.502(g) Terminal and tank vapor collection systems shall be connected during each load.

Status: In Compliance. A reminder sign is posted for drivers. A computerized “Scully”
system locks out trucks from loading without a vapor-tight connection meeting pressure
requirements.

R307-326. UACR:
R307-326-4. Vacuum Producing Systems.
The emission of noncondensable VOCs from the condensers, hot wells, or accumulators
of vacuum producing systems shall be controlled by:
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(1) Piping the noncondensable vapors to a firebox or incinerator, or
(2) Compressing the vapors and adding them to the refinery fuel gas, or
(3) Other equally effective means provided the design and effectiveness of such means
are documented and submitted to and approved by the executive secretary.
Status: In Compliance. All collected vapors are sent to the flare or added into plant fuel gas.
R307-326-5. Wastewater (Oil/Water) Systems.
Any wastewater separator handling VOCs shall be equipped with:
(1) Covers and seals approved by the executive secretary on all separators and forebays,
(2) Lids or seals on all openings in covers, separators, and forebays. Such lids or seals
shall be in the closed position at all times except when in actual use.
Status: In Compliance. All wastewater separators are equipped with a lid or are fully
enclosed.

R307-326-6 Process Unit Turnaround.
The owner or operator of a petroleum refinery shall insure that a minimum of VOCs are
emitted to the atmosphere during process unit turnarounds. The owner or operator shall
develop and submit to the executive secretary for approval a procedure for minimizing
VOC emissions during turnarounds. At a minimum the procedure shall provide for:
(1) Venting of the process unit or vessel during depressurization and purging to a vapor
recovery system, flare or firebox, and
(2) Preventing discharge to the atmosphere of emissions of VOCs from a process unit or
vessel until its internal pressure is 136 kPa (19.7 psia) or less; or
(3) An equally effective system provided the design and effectiveness of such system are
documented and submitted to and approved by the executive secretary.
(4) Keeping records of the following items:
(a) Every date that each process unit or vessel is shut down;
(b) The approximate vessel VOC concentration when the VOCs were first discharged to
the atmosphere; and
(c) The approximate total quantity of VOCs emitted to the atmosphere.
(5) Maintaining records. The records required in (4) above shall be kept for at least two
years and shall be made available for review by the executive secretary or the executive
secretary's representative.
Status: In Compliance. Process units and vessels are first vented to a fuel gas recovery
system. After, vessels are steamed while being vented to the flare.
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R307-326-7 Catalytic Cracking Units.

Flue gas produced by catalytic cracker catalyst regeneration units shall be vented to a
waste heat boiler or a process heater firebox, or incinerated, or controlled by other
methods, provided the design and effectiveness of such methods are documented,
submitted to, and approved by the executive secretary.

Status: In Compliance. Flue gas from the Catalytic Cracker Catalyst Regeneration Unit is
vented to the CO boiler and then an electrostatic precipitator and wet gas scrubber.

R307-326-8 Safety Pressure Relief Valves.

All safety pressure relief valves handling organic material shall be vented to a flare,
firebox, or vapor recovery system, or controlled by the inspection, monitoring, and repair
requirements described in R307-326-9.

Status: In Compliance. Most safety pressure relief valves are vented to the flare gas
recovery system. Any release valve vented to atmosphere triggers process changes to bring
the pressure back down. The valve is monitored within 24 hours of release and repaired
within fifteen days. All identified safety pressure relief valves are included in the VOC
monitoring program and records of releases and monitoring are maintained on-site.

R307-326-9 Monitoring of Leaks from Petroleum Refinery Equipment
(1) The owner or operator of a petroleum refinery complex shall develop and conduct a
VOC monitoring program and shall follow the recording, reporting, and operating
requirements consistent with R307-326-9. The monitoring program shall be submitted 30
days prior to start-up of the petroleum refinery complex or as determined necessary by
the executive secretary.
Status: In Compliance. Tesoro utilizes a computerized VOC monitoring program called
LEAK DAS. This system is used to track and record all of the monitoring conducted at the
site. Tesoro has contracted Alliance Source Testing to manage the program and also
employs an LDAR coordinator. Portable monitors are calibrated using methane and hexane
gas. These monitors record leak readings right into the LEAK DAS system.
(2) Any affected component within a petroleum refinery complex found to be leaking
shall be repaired and retested as soon as practicable, but not later than fifteen (15) days
after the leak is detected. A leaking component is defined as one that has a concentration
of VOCs exceeding 10,000 parts per million by volume (ppmv) when tested by a VOC
detection instrument at the leak source in the manner described in 40 CFR 60, Appendix
A, Reference Method 21, using methane or hexane as the calibration gas. Components
not subject to New Source Performance Standards Subpart GGG shall use methane or
hexane as calibration gas, provided a relative response factor for each individual
instrument is determined for the calibration gas used. Those leaks that cannot be repaired
until the unit is shut down for turnaround shall be identified with a tag and recorded as
per (6) below and shall be reported as per (7) below.
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The executive secretary, in coordination with the refinery owner or operator, may require
early unit turnaround based on the number and severity of tagged leaks awaiting
turnaround.
Status: In Compliance. Tesoro uses tighter leak definitions based on a Consent Decree with
USEPA and has also voluntarily changed all components to the more stringent Subpart
GGGa requirements. First attempt at repair on leaking valves is made by the Alliance
Source Testing technician if qualified to do so. If not qualified, unable to repair a leak, or on
components other than valves, a work order is generated by the LEAK DAS system. Tesoro
follows the Subpart GGGa policy of attempting to repair all leaks no later than 15 days. A
technician reads repaired components immediately after each repair is made. Portable
monitors are calibrated using methane and hexane gas according to Method 21. NSPS
Subpart GGG applies to equipment at petroleum refineries that commence construction or
modification after January 4, 1983, but before November 7, 2006, while NSPS Subpart
GGGa applies to equipment at petroleum refineries that commence construction or
modification after November 7, 2006. Tesoro voluntarily elected to comply with NSPS
GGGa in 2015. All equipment is monitored for leaks in accordance with the requirements of
40 CFR 60 Subpart GGGa.
(3) Monitoring Requirements.
(a) In order to ensure that all existing VOC leaks are identified and that new VOC leaks
are located as soon as practicable, the refinery owner or operator shall perform necessary
monitoring using visual observations when specified or the method described in 40 CFR
60, Appendix A, Reference Method 21, as follows:
(i) Monitor at least one time per year (annually) all pump seals, valves in liquid service,
and process drains;
(ii) Monitor four times per year (quarterly) all compressor seals, valves in gaseous
service, and pressure relief valves in gaseous service;
(iii) Monitor visually 52 times per year (weekly) all pump seals;
(iv) Monitor within 24 hours (with a portable VOC detection device) or repair within 15
days any pump seal from which liquids are observed dripping;
(v) Monitor any relief valve within 24 hours after it has been vented to the atmosphere;
(vi) Monitor immediately after repair any component that was found leaking;
(vii) For all other valves considered "unsafe-to-monitor" or inaccessible during an annual
inspection, the owner or operator shall document to the executive secretary the number of
valves considered "unsafe-to- monitor" or inaccessible, the dangers involved or reasons
for inaccessibility, the location of these valves, and the procedures that the owner or
operator shall follow to ensure that the valves do not leak. The documentation for each
calendar year shall be submitted for approval to the executive secretary 15 days after the
last day of each calendar year. At a minimum, the inaccessible valves shall be monitored
at least once per year (annually).
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(b) For the purpose of R307-326, gaseous service for pipeline valves and pressure relief
valves is defined as the VOCs being gaseous at conditions that prevail in the components
during normal operations. Pipeline valves and pressure relief valves in gaseous service
and other components subject to leaks shall be noted or marked so that their location
within the refinery complex is obvious to the refinery operator performing the monitoring
and to the State of Utah, Division of Air Quality.
Status: In Compliance. Components are monitored by Method 21 monthly. All components,
whether required or voluntarily, are being monitored according to Subpart GGGa
requirements which is the most stringent of all current requirements. Pumps are visually
inspected weekly and by Method 21 monthly. Leaking pump seals are repaired within 15
days and monitored immediately following repair. Inaccessible and unsafe-to-monitor
valves have been reported to the Utah Division of Air Quality (UDAQ). Inaccessible valves
are monitored at least once per year. Some unsafe-to-monitor valves are not monitored
regularly.
(5) Alternate Monitoring Methods and Requirements.
Status: In Compliance. No alternative monitoring methods are being used by Tesoro.
(6) Recording Requirements. Identified leaks shall be noted and affixed with a readily
visible and weatherproof tag bearing the identification of the leak and the date the leak
was detected. The tag shall remain in place until the leaking component is repaired. The
presence of the leak shall also be noted in a log maintained by the operator or owner of
the refinery. The log shall contain, at a minimum, the name of the process unit where the
component is located, the type of component, the tag number, the date the leak is
detected, the date repaired, and the date and instrument reading when the recheck of the
component is made. The log should also indicate those leaks that cannot be repaired until
turnaround, and summarize the total number of components found leaking. The operator
or owner of the refinery complex shall retain the leak detection log for two years after the
leak has been repaired and shall make the log available to the executive secretary upon
request.
Status: In Compliance. Leaking components are noted by affixing a weatherproof tag. Leak
logs are kept as required.
(7) Reporting Requirements. The operator or owner of a petroleum refinery complex
shall submit a report to the executive secretary by the 15th day of January, April, July,
and October of each year listing the total number of components inspected, all leaks that
have been located during the previous 3 calendar months but not repaired within 15 days,
all leaking components awaiting unit turnaround and the total number of components
found leaking. In addition, the refinery operator or owner shall submit a signed statement
with each report that all monitoring has been performed as stipulated in R307-326-9.
Status: In Compliance. Leak monitoring reports have been submitted quarterly. These
reports are reviewed for accuracy and then kept in UDAQ’s source files.
(8) Additional Requirements. Any time a valve, with the exception of safety pressure
relief valves, is located at the end of a pipe or line containing VOCs, the end of the line
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shall be sealed with one of the following: a second valve, a blind flange, a plug or a cap.
This sealing device shall only be removed when the line is in use for sampling.
Status: In Compliance. Valves at the end of a pipe or line containing VOCs are sealed with
a plug, cap, or a second valve.

UAC R307-327
R307-327-4. General Requirements.
(1) Any existing stationary storage tank, reservoir or other container with a capacity
greater than 40,000 gallons (150,000 liters) that is used to store volatile petroleum liquids
with a true vapor pressure greater than 10.5 kilo pascals (kPa) (1.52 psia) at storage
temperature shall be fitted with control equipment that will minimize vapor loss to the
atmosphere. Storage tanks, except those erected before January 1, 1979, which are
equipped with external floating roofs, shall be fitted with an internal floating roof that
shall rest on the surface of the liquid contents and shall be equipped with a closure seal or
seals to close the space between the roof edge and the tank wall, or alternative equivalent
controls, provided the design and effectiveness of such equipment is documented and
submitted to and approved by the executive secretary. The owner or operator shall
maintain a record of the type and maximum true vapor pressure of stored liquid.
Status: In Compliance. Tesoro maintains records of roof types, liquid contents, and
maximum true vapor pressure of petroleum liquids stored inside tanks. Internal floating
roofs with seals have been installed in tanks 140, 186, 188, 190, 244, 245, 248, 297, 321, 331,
402, 412, 413, 414, 503, and 504.
(2) The owner or operator of a petroleum liquid storage tank not subject to (1) above, but
containing a petroleum liquid with a true vapor pressure greater than 7.0 kPa (1.0 psia),
shall maintain records of the average monthly storage temperature, the type of liquid,
throughput quantities, and the maximum true vapor pressure.
Status: In Compliance. Tesoro maintains records of the storage temperature, the type of
liquid, throughput quantities, and the maximum true vapor pressure for all tanks.
R307-327-5. Installation and Maintenance.
(1) The owner or operator shall ensure that all control equipment on storage vessels is
properly installed and maintained.
(a) There shall be no visible holes, tears or other openings in any seal or seal fabric and
all openings, except stub drains, shall be equipped with covers, lids, or seals.
(b) All openings in floating roof tanks, except for automatic bleeder vents, rim space
vents, and leg sleeves, shall provide a projection below the liquid surface.
(c) The openings shall be equipped with a cover, seal, or lid.
(d) The cover, seal, or lid is to be in a closed position at all times except when the device
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is in actual use.
(e) Automatic bleeder vents shall be closed at all times except when the roof is floated off
or landed on the roof leg supports. Rim vents shall be set to open when the roof is being
floated off the leg supports or at the manufacturer's recommended setting.
(f) Any emergency roof drain shall be provided with a slotted membrane fabric cover or
equivalent cover that covers at least 90 percent of the area of the opening.
(2) The owner or operator shall conduct routine inspections from the top of the tank for
external floating roofs or through roof hatches for internal floating roofs at six month or
shorter intervals to insure there are no holes, tears, or other openings in the seal or seal
fabric.
(a) The cover must be uniformly floating on or above the liquid and there must be no
visible defects in the surface of the cover or petroleum liquid accumulated on the cover.
(b) The seal(s) must be intact and uniformly in place around the circumference of the
cover between the cover and tank wall.
(3) A close visible inspection of the primary seal of an external floating roof is to be
conducted at least once per year from the roof top unless such inspection requires
detaching the secondary seal, which would result in damage to the seal system.
(4) Whenever a tank is emptied and degassed for maintenance, an emergency, or any
other similar purpose, a close visible inspection of the cover and seals shall be made.
(5) The executive secretary must be notified 7 days prior to the refilling of a tank that has
been emptied, degassed for maintenance, an emergency, or any other similar purpose.
Any non-compliance with this rule must be corrected before the tank is refilled.
Status: In Compliance. Tesoro conducts and records semi-annual rooftop seal inspections
for holes, tears, and gaps, and the presence of liquids on top of floating roofs. Close visible
inspections of primary seals on external floating roofs are conducted annually and
whenever tanks are emptied. Tesoro has sent notifications to DAQ when emptied tanks are
being refilled. Openings in the floating roofs provide projections below the liquid surface.
Roof openings are fixed with a cover, seal, or lid, and company policy is to keep these in a
closed position when not in use. Some covers are fitted with gaskets or seals to meet NSPS
requirements. A spot check of inspection records was conducted at the time of this
inspection.
R307-327-6. Retrofits for Floating Roof Tanks.
(1) Except where specifically exempted in (3) below, all existing external floating roof
tanks with capacities greater than 950 barrels (40,000 gals) shall be retrofitted with a
continuous secondary seal extending from the floating roof to the tank wall (a rim-
mounted secondary seal) if:
(a) The tank is a welded tank, the true vapor pressure of the contained liquid is 27.6 kPa
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(4.0 psia) or greater and the primary seal is one of the following:
(i) A metallic type shoe seal, a liquid-mounted foam seal, a liquid-mounted liquid-filled
seal, or
(ii) Any other primary seals that can be demonstrated equivalent to the above primary
seals.
(b) The tank is a riveted tank, the true vapor pressure of the contained liquid is 10.5 kPa
(1.5 psia) or greater, and the primary seal is as described in (a) above.
(c) The tank is a welded or riveted tank, the true vapor pressure of the contained liquid is
10.5 kPa (1.5 psia) or greater and the primary seal is vapor-mounted. When such primary
seal closure device can be demonstrated equivalent to the primary seals described in (a)
above, these processes apply.
(2) The owner or operator of a storage tank subject to this rule shall ensure that all the
seal closure devices meet the following requirements:
(a) There shall be no visible holes, tears, or other openings in the seals or seal fabric.
(b) The seals must be intact and uniformly in place around the circumference of the
floating roof between the floating roof and the tank wall.
(c) For vapor mounted primary seals, the accumulated area of gaps between the
secondary seal and the tank wall shall not exceed 21.2 cm2 per meter of tank diameter
(1.0 in2 per ft. of tank diameter) and the width of any gap shall not exceed 1.27 cm (1/2
in.). The owner or operator shall measure the secondary seal gap annually and make a
record of the measurement.
(3) The following are specifically exempted from the requirements of (1) above:
(a) External floating roof tanks having capacities less than 10,000 barrels (420,000 gals)
used to store produced crude oil and condensate prior to custody transfer.
(b) A metallic type shoe seal in a welded tank that has a secondary seal from the top of
the shoe seal to the tank wall (a shoe mounted secondary seal).
(c) External floating roof tanks storing waxy, heavy pour crudes.
(d) External floating roof tanks with a closure seal device or other devices installed that
will control volatile organic compounds (VOC) emissions with an effectiveness equal to
or greater than the seals required in (1) above. It shall be the responsibility of the owner
or operator of the source to demonstrate the effectiveness of the alternative seals or
devices to the executive secretary. No exemption under (3) shall be granted until the
alternative seals or devices are approved by the executive secretary.
Status: In Compliance. The following tanks are equipped with external floating roofs: 144,
241, 242, 243, 246, 247, 252, 298, 307, 308, 324, 325, 326, 327, 328, 330, 405, 421, 422, 423,
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424, 431, and 432. These tanks are all equipped with primary and secondary seals.
Secondary seals are inspected semi-annually for gaps, tears, and holes. Primary seals are
inspected every ten years or whenever tanks are emptied and refilled.

UAC R307-328-4
(1) No person shall load or permit the loading of gasoline into any gasoline cargo tank unless the
emissions from such vehicle are controlled by use of a vapor collection and control system and
submerged or bottom filling. RACT shall be required and in no case shall vapor emissions to the
atmosphere exceed 0.640 pounds per 1,000 gallons transferred.
Status: In Compliance. Trucks are loaded through submerged bottom filling and only into
certified trucks. Tesoro complies with a 10 mg/L emissions limit, which is more stringent
than 0.640 lbs/1,000 gallons (76.7 mg/L).
(2) Such vapor collection and control system shall be properly installed and maintained.
Status: In Compliance. Tesoro maintains a plant-wide computerized preventative and as
needed maintenance database. All maintenance is recorded through a work order system.
VOC and drip leak checks are performed as discussed below.
(3) The loading device shall not leak.
(4) The loading device shall utilize the dry-break loading design couplings and shall be
maintained and operated to allow no more than an average of 15 cc drainage per disconnect for 5
consecutive disconnects.
Status: In Compliance. No excess leaking was observed upon disconnect at the TLR bays
during this inspection. Monthly visible leak checks have been performed and recorded.
Quarterly LDAR checks are also performed.
(5) All loading and vapor lines shall be equipped with fittings which make a vapor tight
connection and shall automatically close upon disconnection to prevent release of the organic
material.
Status: In Compliance. Loading arms and vapor recovery lines are equipped with vapor
tight fittings. A spring-loaded plate with a rubber seal automatically closes upon
disconnection. Connections are visually checked for leak tightness monthly. Pressure
monitors are installed and automatically shut off-loading if pressure drops are detected.
(6) Not Applicable.
(7) Hatches of gasoline cargo tanks shall not be opened at any time during loading operations
except to avoid emergency situations or during emergency situations. Pressure relief valves on
storage tanks and gasoline cargo tanks shall be set to release at the highest possible pressure, in
accordance with State or local fire codes and National Fire Prevention Association guidelines.
Pressure in the vapor collection system shall not exceed the gasoline cargo tank pressure relief
setting.

Status: In Compliance. All trucks are grounded through a program called Scully, which
verifies tanker certifications and monitors pressure during loading. The system is set to
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automatically stop loading if pressure drops are detected and will not load if a hatch is
open. UAC R307-328-4(10) specifies a pressure limit of 18 inches of water and a vacuum
limit of 6 inches of water on the vapor collection system.
(8) Each owner or operator of a gasoline storage or dispensing installation shall conduct testing of
vapor collection systems used at such installation and shall maintain records of all tests for no less
than two years. Testing procedures of vapor collection systems shall be approved by the
executive secretary and shall be consistent with the procedures described in the EPA document,
"Control of Volatile Organic Compound Leaks from Gasoline Tank Trucks and Vapor Collection
Systems," EPA-450/2-78-051.
(9) Semi-annual testing shall be conducted and records maintained of such test. The frequency of
tests may be altered by the executive secretary upon submittal of documentation which would
justify a change.
(10) The vapor collection and vapor processing equipment shall be designed and operated to
prevent gauge pressure in the gasoline cargo tank from exceeding 18 inches of water and prevent
vacuum from exceeding 6 inches of water. During testing and monitoring, there shall be no
reading greater than or equal to 100 percent of the lower explosive limit measured at 1.04 inches
around the perimeter of a potential leak source as detected by a combustible gas detector.
Potential leak sources include, but are not limited to, piping, seals, hoses, connections, pressure or
vacuum vents, and vapor hoods. In addition, no visible liquid leaks are permitted during testing or
monitoring.
Status: In Compliance. The vapor collection system is designed to prevent gauge pressure in
the gasoline cargo tank from exceeding 18 inches of water and prevent vacuum from
exceeding 6 inches of water. Semi-annual pressure checks have been performed consistent
with EPA-450/2-78-051. Records of these pressure checks were provided. Currently semi-
annual pressure checks are conducted by connecting a manometer coupling between a
loading truck and the vapor collection system. Tesoro has an internal policy of fixing
readings above 10 inches of water, which is more conservative than the 18-inch limit.

EMISSIONS INVENTORY: Taken from DAQ’s 2023 emissions inventory database
(combines both sites):

Pollutant Tons/yr
PM10 80.36
PM 2.5 39.19
SOx 17.60
NOx 232.75
VOC 210.10
CO 322.64
Ammonia 3.27

PREVIOUS ENFORCEMENT
ACTIONS: None within the previous five years.

COMPLIANCE
ASSISTANCE: None

108
COMPLIANCE STATUS &
RECOMMENDATIONS: Tesoro should be found in compliance with the conditions of the
Title V and Approval orders, NSPS, MACT, and NESHAP
requirements evaluated during this inspection.

HPV STATUS: Not Applicable.

RECOMMENDATION FOR
NEXT INSPECTION: None.

ATTACHMENT: VEO forms