DAQ-2025-000496

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DAQC-055-25
Site ID 10123 (B1)

MEMORANDUM

TO: FILE – HF SINCLAIR WOODS CROSS REFINING, LLC (HF SINCLAIR)

THROUGH: Harold Burge, Major Source Compliance Section Manager

FROM: Joe Rockwell, Environmental Scientist

DATE: January 16, 2025

SUBJECT: FULL COMPLIANCE EVALUATION (FCE), Major, Davis County,
FRS # UT0000004901100013

INSPECTION DATE: July 22, 23, and 25, 2024 - Additional information received on
January 16, 2025.

SOURCE LOCATION: 393 South 800 West, Woods Cross, 84087

Take Exit 316 from I-15 and go West. Go about one mile on 500
South. The refinery administration building is on the north (Right)
side of the street.

MAILING ADDRESS: 1070 West 500 South, West Bountiful, Utah 84087

SOURCE CONTACTS: Eric Benson – Environmental Manager,
Office: [phone]
Mobile: [phone]
[e-mail]

F. Travis Smith – Environmental Specialist,
Office: [phone]
Mobile: [phone]
[e-mail]

Richmond Thornley – Environmental Engineer,
Office: [phone]
Mobile: [phone]
[e-mail]

Al Vargas – Environmental Specialist,
Office: [phone]
Mobile: [phone]
[e-mail]

Matt Howes – Environmental Engineer,
Office: [phone]
Mobile: [phone]
[e-mail]

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OPERATING STATUS: Refinery was operating at time of the inspection.

PROCESS DESCRIPTION:

HF – Sinclair Woods Cross Refining LLC:

The HF Sinclair Woods Cross Refinery (Refinery) is located in Davis County. The source is a 60,000 barrel
(bbl) per day refinery that uses a verity of process units to produce products such as gasoline, natural gas
liquids (NGL), propane, butanes, jet fuels, fuel oils, and kerosene. Different types of tanks are used to store
products that are received by tanker truck, rail car and pipeline. Gasoline, diesel, and jet fuel are sent to the
Holly Energy Partners (HEP) Woods Cross Terminal (Terminal) via pipeline for distribution. The refinery is
divided into the East Tank Farm (ETF), West Tank Farm (WTF), refinery process area, and Crude Oil
Unloading (COL). All facility areas are interconnected with product, charge, and feed lines for handling
petroleum products. The Light Oil Docks are also part of HF Sinclair. Finally, Flares are used to control
emergency and other captured emissions from the process units

The HF Sinclair Woods Cross Refinery is located near the eastern shores of the Great Salt Lake with the
Wasatch Range to the East. The refinery encompasses approximately 110 acres of fenced area with a greenbelt
(safety barrier) surrounding the facility. The Standard Industrial Code (SIC) for the refinery is 2911
(Petroleum Refining). The Refinery (10123) and Terminal (16015) are considered a single source for the
purposes of Title V. However, the Refinery and Terminal have separate Approval Orders, Title V permits, and
Responsible Officials.

Waste Water Treatment Plant:

The Waste Water Treatment Plant (WWTP), (Unit 56) treats plant wastewater and storm water runoff from
process areas. Wastewater is collected by process drains and junction boxes and routed through a grit collector
then to a main process lift station. The main process lift station supplies process waste water to two American
Petroleum Institute (API) separators. Oil is skimmed off the separators and gravity fed to an API oil collection
drum then to Tank 118. The sludge from the API separators is collected and dewatered in a sludge thickening
vessel and later sent for reuse.

The effluent water from the API separators is pumped to two equalization tanks (Tanks 155 and 158). From
the equalization tanks, waste water is pumped into two dissolved gas floatation units (DGF). The DGFs works
to remove emulsified oil from the waste water by adding a polymer and inducing small air bubbles into the
water to bring oil to the surface. This skimmed oil, or float, is gravity fed to a storage tank before being
pumped to the sludge thickening vessel.

Finally, the waste water is sent to a series of moving bio-film reactors (MBBR) for biological polishing before
being discharged to the Davis County Public Owned Treatment Works (POTW). All process tanks and
equipment at the WWTP are covered to control fugitive emissions.

Surface rain water flows to a retention pond that is located on the west side of the refinery.

West Tank Farm:

The West Tank Farm (WTF) consists of the storage tanks located west of the refinery. Light petroleum
products, including crude oil, gasolines, jet fuel, gas oil, NGL, propane, and butanes are stored at the WTF.
Gasoline intermediates and products are stored in floating roof tanks. Compressed propane and butane gas,
also known as Liquefied Petroleum Gas (LPG), are stored in horizontal, pressurized tanks, commonly referred
to as “bullet” tanks because of their shape. The tank farm blends gasoline for shipment via truck and pipeline.
There are truck loading spots for propane, butane, and spent caustics.

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East Tank Farm:

East Tank Farm (ETF) consists of the tanks located east of 800 West and north of 500 South. Mainly heavy
products such as diesel and fuel oil are stored at in the ETF. There are 10 plant gas fired stab-in furnaces that
are used to heat asphalt. Loading operations to rail tankers are also located in this area. The loading racks are
located adjacent to 800 West.

APPLICABLE REGULATIONS:

Title V Operating Permit #1100013001, dated May 3, 2024, and Revised May 3, 2024.

40 CFR 60 40 CFR 60 Subpart A–General Provisions
40 CFR 60 Subpart Dc–Standards of Performance for Small Industrial-Commercial-Institutional Steam
Generating Units
40 CFR 60 Subpart J–Standards of Performance for Petroleum Refineries
40 CFR 60 Subpart Ja–Standards of Performance for Petroleum Refineries for Which Construction,
Reconstruction, or Modification Commenced After May 14, 2007
40 CFR 60 Subpart K–Standards of Performance for Storage Vessels for Petroleum Liquids for Which
Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978
40 CFR 60 Subpart Kb–Standards of Performance for Volatile Organic Liquid Storage Vessels (Including
Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced
After July 23, 1984
40 CFR 60 Subpart UU–Standards of Performance for Asphalt Processing and Asphalt Roofing Manufacture
40 CFR 60 Subpart GGGa–Standards of Performance for Equipment Leaks of VOC in Petroleum Refineries
for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006
40 CFR 60 Subpart QQQ–Standards of Performance for VOC Emissions From Petroleum Refinery
Wastewater Systems
40 CFR 60 Subpart IIII–Standards of Performance for Stationary Compression Ignition Internal Combustion
Engines
40 CFR 60 Subpart JJJJ–Standards of Performance for Stationary Spark Ignition Internal Combustion Engines

40 CFR 61 Subpart A–General Provisions
40 CFR 61 Subpart FF-National Emission Standard for Benzene Waste Operations
40 CFR 61 Subpart M-National Emission Standard for Asbestos

40 CFR 63 Subpart A-General Provisions
40 CFR 63 Subpart CC-National Emission Standards for Hazardous Air Pollutants from Petroleum Refineries
40 CFR 63 Subpart WW-National Emission Standards for Storage Vessels (Tanks) - Control Level 2
40 CFR 63 Subpart UUU-National Emission Standards for Hazardous Air Pollutants for Petroleum Refineries:
Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units
40 CFR 63 Subpart EEEE-National Emission Standards for Hazardous Air Pollutants: Organic Liquids
Distribution (Non-Gasoline)
40 CFR 63 Subpart ZZZZ-National Emissions Standards for Hazardous Air Pollutants for Stationary
Reciprocating Internal Combustion Engines
40 CFR 63 Subpart DDDDD-National Emission Standards for Hazardous Air Pollutants for Major Sources:
Industrial, Commercial, and Institutional Boilers and Process Heaters
40 CFR 63 Subpart GGGGG-National Emission Standards for Hazardous Air Pollutants: Site Remediation

40 CFR 68–Chemical Accident Prevention Provisions
40 CFR 82–Protection of Stratospheric Ozone

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

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

I.D Permit Expiration and Renewal.

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))

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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: The permit expires May 3, 2029. Application for renewal is due November 3, 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: Application for renewal is due November 3, 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 a statement of fact and 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 – The 2022, annual emission fee invoice payment was made on August 16,
2023, before the due date of October 2, 2023. Also, the 2023, annual emission fee invoice
payment was made on September 5, 2024, before the due date of October 3, 2024.

I.H No Property Rights.

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

Status: This is a statement of fact and not an inspection item.
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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 a statement of fact and 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 – Required records were made available and no claims of confidentiality were
made at time of the inspection.

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 reports and certifications submitted, had certification statements, and
were signed by responsible officials.

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
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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: Not Evaluated – The Title V Permit was issued on May 3, 2024. The Schedule for Submission
of Title V annual compliance certification and semi-annual letter, dated May 28, 2024, was
submitted on May 31, 2024. The letter proposed a plan to submit the annual compliance
certification and other reports regarding the new Title V Permit. Revision of the letter was
discussed at time of the inspection. The revised letter will be submitted at a later date.

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:

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))
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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))

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: Not Applicable – See section III of this permit.

I.N Reserved.

I.O Operational Flexibility.

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

I.P Off-permit Changes.

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

I.Q Administrative Permit Amendments.

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

I.R Permit Modifications.

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

Status: These are statements of fact and not inspection items (I.O through I.R).

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))
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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.

Status: In Compliance – Required records were provided at time of the inspection.

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:
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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 8ARD-PM)
1595 Wynkoop Street
Denver, CO 80202-1129
Phone: [phone]

Status: Not Evaluated – The Title V Permit was issued on May 3, 2024. Semi-annual monitoring and
deviation reports were not required to be submitted at time of the inspection. See status of
condition I.L.

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: This is a statement of fact and not an inspection item.
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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 – The 2023 annual emissions inventory was received on April 15, 2024. The
2024 annual emission inventory has a due date of April 15, 2025. The refinery is aware of the
due date. See Emission Inventory below. Also, SLEIS database.

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 a statement of fact and 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 Fluid Catalytic Cracking (FCC) Units and Associated Scrubbers
Unit includes two FCC Units. FCC unit 4 is controlled by a wet gas scrubber (4V82) and is
subject to 40 CFR 60 Subpart J. FCC unit 25 is controlled by a wet gas scrubber (25FCC) and is
subject to 40 CFR 60 Subpart Ja. The 4V82 scrubber and the 25FCC scrubber are each equipped
with LoTOx control technology.

II.A.3 Catalytic Reforming Unit (Reformer) (Unit 6)
A catalytic process that converts low octane naphthas into higher octane reformate products for
gasoline blending and aromatic rich reformate for aromatic production.

II.A.4 Sulfur Recovery (SRU)/Tail Gas Incinerator (Unit 17)
The SRU is controlled by either the 4V82 or 25FCC scrubber. The tail gas incinerator, for SRU
under 20 long tons per day (LTPD), controls the SRU during emergency operations or during
plant shutdown when both scrubbers are off line.

II.A.5 SRU Backup Scrubber (Unit 29)
The SRU backup scrubber operates during periods of SRU downtime.

II.A.6 Compression Ignition (CI) and Spark Ignition (SI) RICE
CI RICE: Non-emergency diesel-fired engine: 135 kW portable east tank farm (ETF); emergency
diesel-fired engines: 224 hp water well No. 3, 393 hp fire pump No. 1, 393 hp fire pump No. 2,
180 hp fire pump, three (220 hp each) plant air backup compressors, 470 hp standby at Boiler
House, 380 hp standby at Central Control Room, and 540 hp standby.
SI RICE: Emergency natural gas-fired engines: two (170 kW each) standby at Administration
Bldg.

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II.A.7 Steam Systems (Unit 51)
Unit includes six boilers, all fired on plant gas. Boiler #4 (1963): 35.6 MMBtu/hr, boiler #5
(1997): 70.0 MMBtu/hr equipped with SCR, boiler #8 (2013): 92.7 MMBtu/hr equipped with
LNB and SCR, boiler #9 (2011): 89.3 MMBtu/hr equipped with SCR, boiler #10 (2012): 89.3
MMBtu/hr equipped with SCR, boiler #11 (2019): 89.3 MMBtu/hr equipped with LNB and SCR.
These boilers are a subset of the Boiler NESHAP Combustion Unit below.

II.A.8 Flares (Unit 66) and Flare Gas Recovery
Unit includes process flare north (66-2), process flare south (66-1), both controlled by a flare gas
recovery system. The flares are subject to 40 CFR 60 Subpart Ja and are a subset of NESHAP
CC Equipment.

II.A.9 Storage Tanks (Unit 68)
Tank Numbers: 11, 12, 14, 15, 19-21, 23, 24, 28, 29, 31, 35, 37, 42A, 47, 48, 50–59, 61, 63, 65,
70-79, 86, 90, 92, 99-109, 117, 118, 121-123, 126-129, 131-136, 138-141, 143, 145-153, 155,
158, 159, 169-172, 323, 324. Specific tank details and characteristics are listed in a reviewer
comment.

II.A.10 NESHAP CC Equipment
Unit includes Group 1 storage vessels (12, 71, 72, 90, 92, 100-102, 104-109, 121, 126, 128, 129,
132, 135, 138, 145, 146), Group 2 storage vessels (remaining tanks listed in Unit 68-Storage
Tanks), Group 1 miscellaneous process vents (MPV), Group 2 MPV's and maintenance vents,
north (66-2) and south (66-1) flares, equipment leaks from petroleum refining process units,
Refinery fenceline, wastewater, and heat exchange systems for cooling towers 4, 6, 7, 8, 10, and
11. Some 40 CFR 63 Subpart CC requirements for specific units are included under other
emission unit groups.

II.A.11 Boiler NESHAP Combustion Units
Process heaters and boilers subject to 40 CFR 63 Subpart DDDDD. All are fired on plant gas
except 68H2 and 68H3 which are fired on natural gas. All units are in the gas 1 subcategory as
defined in the subpart. Unit includes: 4H1, 6H1, 6H2, 6H3, 7H1, 7H3, 8H2, 9H1, 9H2, 10H1,
11H1, 12H1, 13H1, 19H1, 20H2, 20H3, 24H1, 25H1, 68H2, 68H3, Boilers #4, #5, #8, #9, #10,
#11. Maximum ratings, and specific characteristics for each unit are either listed in Unit 51-Steam
Systems or in a reviewer comment.

II.A.12 NESHAP UUU Equipment
Unit includes process vents and bypass lines associated with: FCC Units 4 and 25, Catalytic
Reforming Unit 6, and SRU Unit 17, as described in 40 CFR 63.1562(b).

II.A.13 Equipment Leaks
Unit includes equipment in VOC or organic HAP service as defined in 40 CFR 60.481a or 40
CFR 63.641: pumps, compressors, pressure relief devices, sampling connection systems, open-
ended valves or lines, valves, flanges or other connectors, or instrumentation systems. This unit is
also a subset of NESHAP CC Equipment.

II.A.14 Wastewater Treatment (Unit 56)
Oil/water separator, dissolved gas flotation unit, moving bed bioreactors, process drainage
system, Tanks 117, 118, 155, 158, and junction boxes.

II.A.15 Fuel Gas Combustion Devices
Fuel gas combustion devices located throughout the source. The following fuel gas combustion
devices are subject to 40 CFR 60 Subpart J: 4H1, 11H1, 12H1, 13H1, 19H1, 68H2, 68H3, Boiler
13

#5. The following fuel gas combustion devices are subject to 40 CFR 60 Subpart Ja: 6H2, 8H2,
20H2, 20H3, 24H1, 25H1, Boilers #8, #9, #10, and #11. Specific details and characteristics for
each unit are either listed in Unit 51-Steam Systems or in a reviewer comment.

II.A.16 Cooling Towers (Unit 54)
Unit includes tower #4, 6, 7, 8, 10, and 11. All cooling towers implement the Modified El Paso
Method utilizing a FID analyzer. Tower #10 and #11 have capacities of 10,700 gallons per
minute (gpm), each. Tower #10 is induced draft multi-cell flow and Tower #11 is induced draft
flow Tower #8, #10 and #11 are each equipped with high efficiency drift eliminators. Tower #4,
#6, and #8 were built pre-1975. Tower #7 was rebuilt in 2006. This unit is a subset of NESHAP
CC Equipment.

II.A.17 Specific Heaters and Boilers
Specific process heaters and boilers grouped according to applicable requirements that originate
in the underlying approval order. All are fired on plant gas. Unit includes: 8H2, 12H1, 19H1,
20H2, 20H3, 24H1, 25H1, boilers #5, #8, #9, #10, #11. Specific details and characteristics for
each unit are either listed in Unit 51-Steam Systems or in a reviewer comment.

II.A.18 Miscellaneous Permitted Plant Processes
The following units may be included in some of the emission unit groups above. No unit specific
applicable requirements.
Unit 7-alkylation, Unit 8-crude ,Unit 9-distillate hydrodesulfurization (DHDS), Unit 10-solvent
deasphalting (SDA), Unit 11-straight run gas plant (SRGP), Unit 12-naphtha hydrodesulfurization
(NHDS), Unit 13-isomerization, Unit 16-amine treatment, Unit 18-sour water stripping (SWS),
Unit 19-distillate hydrodesulfurization treatment (DHT), Unit 20-gas oil hydrocracking (GHC),
Unit 21-NaHS sour gas treatment, Unit 22-sour water stripper/ammonia stripping, Unit 23-
benzene saturation, Unit 24-crude, Unit 26-poly gasoline, Unit 45-asphalt storage,
Unit 87-Loading/Unloading:
Truck loading for: NaHS (1 spot), sulfur (2 loading arms), fuel oil (1 spot), asphalt (1 spot),
propane (2 spots), kerosene (1 spot), fuel oil or asphalt (14 spots), lube oil (24 spots).
Truck unloading for: crude/gas oil/NGL (16 bays), caustic (3 spots), fuel oil (1 spot), diesel (1
spot), light cycle oil (1 spot), gasoline (1 spot), ethanol (1-250 gpm pump).
Railcar loading/unloading for: NaHS/caustic (2 spots), fuel oil/asphalt (4 spots),
oil/diesel/caustic (4 spots), NGL (4 spots), NGL/olefin (5 spots).
Railcar unloading for: ethanol (3 areas: 1-400 gpm LOD charge pump, 1-250 gpm LOD charge
pump, 4 unloading arms), biodiesel (2 spots).

Status: In Compliance – No unapproved equipment was noted at time of the inspection. Item II.A.4 will be
revised to reflect the new, Subpart JA, SRU Wet Gas Scrubber limits. Also see condition II.B.1.w
regarding items II.A.9 and II.A.10.

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:

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.
14

[Origin: 40 CFR 82 Subpart F]. [40 CFR 82.150(b)]

II.B.1.a.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.a.2 Recordkeeping:

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

II.B.1.a.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 – Pond’s Heating and Air conducts quarterly preventative maintenance (PM) on an
as needed basis. These invoices are kept as hard copies and electronically. HF Sinclair will certify
compliance with this condition in their first annual compliance certification report. See status of
condition I.L.

II.B.1.b 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. [Origin:
40 CFR 68]. [40 CFR 68]

II.B.1.b.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.1.b.2 Recordkeeping:

A copy of the Risk Management Plan shall be available to the Director upon request. Records
shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.1.b.3 Reporting:

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

Status: In Compliance – The Risk Management Plan (RMP) is reviewed annually and is resubmitted to the
DAQ every five years. The RMP was reviewed at time of the inspection.

II.B.1.c Condition:

Unless otherwise specified in this permit, 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
15

include, but is not limited to, monitoring results, opacity observations, review of operating and
maintenance procedures, and inspection of the source. [Origin: DAQE-AN101230057-23]. [40 CFR
60.11(d), R307-401-8]

II.B.1.c.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.1.c.2 Recordkeeping:

The permittee shall document activities performed to assure proper operation and maintenance.
All maintenance performed on permitted plant equipment shall be recorded. Records shall be
maintained in accordance with Provision I.S.1 of this permit.

II.B.1.c.3 Reporting:

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

Status: In Compliance – The refinery appeared to be well maintained and operated at time of the
inspection. The SS & M Log Database is used to track all maintenance. Most maintenance is
conducted in-house.

II.B.1.d Condition:

Unless otherwise specified in this permit, visible emissions shall not exceed the following opacity limits:
All baghouses: 10%
FCC Unit 25/FCC Unit 25 Wet Gas Scrubber: 20%
All other scrubbers: 15%
All other combustion sources: 10%
All fugitive emission points: 15%
All other points: 20%
[Origin: DAQE-AN101230057-23, R307-305-3, R307-309-4]. [R307-305-3, R307-309-4, R307-401-8]

II.B.1.d.1 Monitoring:

The permittee shall conduct visible emissions observations according to the following
requirements for each affected emission unit.
(a) Conduct a monthly 6-minute visible emissions test of each affected emission unit in
accordance with 40 CFR 60, Appendix A, Method 22, or other EPA-approved testing
method, as acceptable to the Director. The performance test shall be conducted while the
unit is operating and performed by an individual trained on the observation procedures of 40
CFR 60, Appendix A, Method 9. The individual is not required to be a certified visible
emissions observer.
(b) If visible emissions are observed during any Method 22 test, a six-minute test of opacity
shall be conducted by a certified observer in accordance with 40 CFR 60, Appendix A,
Method 9, or other EPA-approved testing method, as acceptable to the Director. The
Method 9 test shall begin within 24 hours of the initial survey and shall be conducted while
the unit is operating. For intermittent sources, the requirement for observations to be made
at 15 second intervals over a six-minute period shall not apply. The number of observations
and the time period shall be determined by the length of the intermittent source operation.

16

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

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

II.B.1.d.2 Recordkeeping:

Results of monitoring and records demonstrating compliance with this condition shall be
maintained. Records of visible emission tests performed and all data required by 40 CFR 60,
Appendix A, Method 22, Method 9, or other EPA-approved testing method, as acceptable to the
Director, shall be maintained 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 Monthly Visible Emission Observations (VEOs) Check Sheets indicated, at
time of the inspection, when method 22 is conducted. Cameras are used to monitor (method 22) the
flares under Subparts ja and CC. The videos are archived for regular review. Refinery employees
also conduct VEOs for Holly Energy Partners (HEP) when required.

II.B.1.e Condition:

Unless otherwise specified in this permit, visible emissions caused by fugitive dust shall not exceed 10%
at the property boundary, and 20% on site. 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 one or more of the following contingency measures:
i. Pre-event watering;
ii. Hourly watering;
iii. Additional chemical stabilization;
iv. Cease or reduce fugitive dust producing operations to the extent practicable.
[Origin: R307-309]. [R307-309-5]

II.B.1.e.1 Monitoring:

In lieu of monitoring via visible emissions observations, adherence to the current fugitive dust
control plan approved by the Director shall be monitored to demonstrate that appropriate
measures are being implemented to control fugitive dust. Wind speed shall be measured by an
anemometer to establish an exception from the visible emissions limit.

II.B.1.e.2 Recordkeeping:

Records of measures taken to control fugitive dust shall be maintained to demonstrate adherence
to the most recently approved fugitive dust control plan. If wind speeds are measured to establish
17

an exception from the above visible emissions limits, records of the administered contingency
measures and the wind speed measurements shall be maintained. Records that demonstrate
compliance with this condition shall be available to the director upon request. [R307-309-12]
Records shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.1.e.3 Reporting:

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

Status: Not Evaluated – This is considered to be a new condition. According to HF Sinclair the Fugitive
Dust Control Plan (FDCP) will be submitted to and approved by the DAQ, before the next
inspection.

II.B.1.f 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. [Origin: R307-309]. [R307-309-5(2),
R307-309-6]

II.B.1.f.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.f.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 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: Not Evaluated – This is considered to be a new condition. According to HF Sinclair the FDCP will
be submitted to and approved by the DAQ, before the next inspection. See status of condition
II.B.1e.

II.B.1.g Condition:

The in-plant access road shall be paved and shall be periodically swept, or sprayed clean as dry conditions
warrant or as determined necessary by the Director. The vehicle speed on in-plant roads shall not exceed
15 miles per hour. The permittee shall comply with the fugitive dust requirements and work practices for
roads contained in R307-309-8 and R307-309-9, as applicable, and in accordance with R307-309-6.
[Origin: DAQE-AN101230057-23, R307-309]. [R307-401-8, R307-309]
18

II.B.1.g.1 Monitoring:

The vehicle speed limit on in-plant roads shall be posted and large enough to be read by drivers.
At least once each year, all speed limit signs shall be inspected to ensure they are still posted and
legible. 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. Records
required for this permit condition will also serve as monitoring.

II.B.1.g.2 Recordkeeping:

Records of cleaning paved roads shall be kept. Records of inclement weather that prevent
sweeping/cleaning of in-plant access roads shall also be kept. These records shall include the
relevant dates and conditions that prevented sweeping/cleaning, including temperature and
precipitation records.

Results of speed limit sign inspections shall be maintained. Records that demonstrate compliance
with this condition and records required by the most recently approved fugitive dust control plan
shall be maintained in accordance with the plan and Provision I.S.1 of this permit.

II.B.1.g.3 Reporting:

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

Status: In Compliance – All facility roads are paved and are swept monthly by Jacketta Sweeping.
The vehicle speed limit of 10 mph is also posted throughout the facility. Invoices and inspection
results are maintained as records. See status of conditions II.B.1.e and II.B.1.f regarding FDCP.

II.B.1.h Condition:

This condition applies to degreasing operations that use VOCs. Cold degreasing or solvent cleaning
operations shall not operate unless they meet the following conditions:
i. 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.
ii. 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.
iii. Waste or used solvent shall be stored in covered containers.
iv. 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.
v. 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.
vi. 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
19

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; or
(c) other systems of equivalent control, such as a refrigerated chiller or carbon adsorption.
vii. 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]

II.B.1.h.1 Monitoring:

Visual inspections shall be conducted monthly on all affected emission units to demonstrate
compliance with the applicable work practices.

II.B.1.h.2 Recordkeeping:

Results of monthly inspections, volatility of the solvent(s) being used, and the physical
characteristics that demonstrate compliance with R307-335 shall be recorded and 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: Not Evaluated – This is considered to be a new condition. According to HF Sinclair the above VOC
Degreasing Operation procedures will be implemented before the next inspection.

II.B.1.i Condition:

Except as provided in R307-361-4, the permittee shall not supply, solicit for application, or apply any
architectural coating with a VOC content in excess of the corresponding limit specified in Table 1 of
R307-361-5. The permittee shall comply with the additional standards and work practices contained in
R307-361-5, as applicable. [Origin: R307-361]. [R307-361]

II.B.1.i.1 Monitoring:

Compliance shall be demonstrated as specified in R307-361-8.

II.B.1.i.2 Recordkeeping:

Records demonstrating compliance with this condition shall be maintained in accordance with
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: Not Applicable – HF Sinclair does not supply, solicit for application, or apply any architectural
coating containing VOCs. This condition only applies to contractors.

II.B.1.j Condition:
20

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]

II.B.1.j.1 Monitoring:

(a) Visible emissions shall be measured using EPA Method 9 at least once during each six-
month period in which abrasive blasting operations occur. 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 visible emission standards in R307-306-4.
(d) Visible emissions from confined blasting shall be measured at the densest point after the air
pollutant leaves the enclosure.
Records required for this permit condition will also serve as monitoring.

II.B.1.j.2 Recordkeeping:

Records demonstrating compliance with R307-306-6, as applicable, and results of monitoring
shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.1.j.3 Reporting:

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

Status: Not Evaluated – This is considered to be a new condition. According to HF Sinclair the above
abrasive blasting operation procedures will be implemented before the next inspection.

II.B.1.k Condition:

For solvent cleaning operations:
Solvent products with a VOC content greater than the amounts specified in Table 1 of R307-304-5, shall not
be used unless the permittee uses an add-on control device as specified in R307-304-7 or the alternative
method in R307-304-5(2). The permittee shall store used applicators and shop towels in closed fireproof
containers. [Origin: R307-304]. [R307-304]

II.B.1.k.1 Monitoring:

Records required for this permit will serve as monitoring.

II.B.1.k.2 Recordkeeping:

The permittee shall maintain records demonstrating compliance with this condition. Records
shall include the VOC content or composite vapor pressure of the solvent product applied. If an
add-on control device is used, records of key system parameters shall be maintained in accordance
21

with R307-304-8. Records shall be maintained in accordance with Provision I.S.1 of this permit
and shall be available to the director upon request.

II.B.1.k.3 Reporting:

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

Status: Not Applicable – HF Sinclair has used < 55 gallons of solvent per year, as of September 1, 2018. See
UAC Rule 307-304-2(3).

II.B.1.l Condition:

Total plant wide emissions (excluding emissions covered under 40 CFR 98 Subpart MM - Suppliers of
Petroleum Products) of greenhouse gas (GHG) shall not exceed 1,003,300 short tons of CO2e per rolling
12-month period. GHG emissions shall include combined emissions of CO2, CH4, and N2O. [Origin:
DAQE-AN101230057-23]. [R307-401-8]

II.B.1.l.1 Monitoring:

Compliance with the rolling 12-month period shall be demonstrated as follows:

The permittee shall multiply the actual rolling 12-month heat input for all fuel gas combustion
units by the appropriate emissions factor and global warming potential listed below to calculate
emissions of each GHG. The sum of all GHG emissions from all fuel gas combustion units shall
be used to evaluate compliance with the CO2e limit. Actual heat input values shall be determined
by natural gas purchasing records. Actual heat input values of plant gas shall be determined
through refinery testing and multiplied by monthly flow rates.

GHG Emission Factor Global Warming Potential
CO2 53.02 kg/MMBtu 1
CH4 0.001 kg/MMBtu 25
N2O 0.0001 kg/MMBtu 298

Compliance with each limitation shall be determined on a rolling 12-month total. No later than 20
days after the end of each month, a new 12-month total shall be calculated using data from the
previous 12 months.

Stack testing in accordance with R307-165 shall be conducted at least once every three (3) years
to verify the CO2 emissions from the fuel gas combustion equipment with heat input greater than
or equal to 99.0 MMBtu/hr are no greater than the CO2e emission factors listed above. CO2
emissions shall be determined using the procedures outlined in 40 CFR 60 Appendix A, Method
3, 3A, or other EPA-approved testing method, as acceptable to the Director.

II.B.1.l.2 Recordkeeping:

Results of monitoring, including calculations, fuel purchase records, and stack test results
verifying the CO2e emission factors shall be recorded and maintained in accordance with
Provision I.S.1 of this permit.

22

II.B.1.l.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate compliance
status. There are no additional reporting requirements for this provision except those specified in
Section I of this permit.

Status: In Compliance – According to the GHG spreadsheet, the 12-month rolling total of produced GHG
is 285,924 short tons, as of June 30, 2024.

II.B.1.m Condition:

i. Except for use in emergency and portable equipment, fuel oil shall not be burned in any existing
combustion device at the Refinery except during periods of natural gas curtailment. Except for diesel
fuel, any oil burned in any fuel burning or process installation not covered by New Source
Performance Standards for sulfur emissions shall contain no more than 0.85 pounds sulfur per million
gross BTU heat input for any oil.
ii. The permittee shall only use diesel fuel (e.g. fuel oil #1, #2, or diesel fuel oil additives) as a fuel
source for the diesel fuel-fired emergency generators and ETF portable diesel generator.
iii. The permittee shall only combust diesel fuel that meets the ultra-low sulfur diesel (ULSD) standards
found in 40 CFR 1090.305.
iv. Small (<100 HP) portable fuel oil-powered equipment is exempt from the requirements of the
underlying approval order and related emissions are not to be used for purposes of determining
compliance.
v. Torch oil may be burned in the FCCU (Units 4 and 25) regenerators to assist in starting, restarting,
maintaining hot standby, or maintaining regenerator heat balance.
[Origin: DAQE-AN101230057-23, R307-203, SIP Section IX.H.1.g.iv, SIP Section IX.H.2.f.iv, SIP
Section IX.H.11.g.vii, SIP Section IX.H.12.g.iv]. [R307-401-8, R307-203-1, SIP Section IX.H.1.g.iv, SIP
Section IX.H.2.f.iv, SIP Section IX.H.11.g.vii, SIP Section IX.H.12.g.iv]

II.B.1.m.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.1.m.2 Recordkeeping:

The permittee shall keep fuel usage records demonstrating compliance with this condition
including, but not limited to, documentation of periods of natural gas curtailment when fuel oil is
used and periods when torch oil is used including the reason. The permittee shall keep records of
fuel purchase invoices, fuel supplier certifications, or records of testing that demonstrate
compliance with the ULSD standards.

In the case of fuel oil burned in any fuel burning or process installation not covered by New
Source Performance Standards for sulfur emissions, the permittee shall record the following
specifications either from the Refinery’s own testing or for each purchase of fuel oil from the
vendor: weight percent sulfur, gross heating value (btu per unit volume), and density. These
parameters shall be ascertained in accordance with the methods of the American Society for
Testing and Materials. For determining sulfur content in oil, ASTM Methods D2880-71 or
D4294-89 shall be used. (R307-203-1(1)(a), R307-203-1(4)(b))

Records shall be kept for all periods when the plant is in operation and shall be maintained in
accordance with R307-203-1(1)(d) and Provision I.S.1. of this permit.
23

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 – An invoice from Tom Randall Distribution, dated September 29, 2023, indicated
that only ultra-low sulfur (ULSD) diesel is delivered to the refinery. ULSD diesel, natural gas (NG),
and plant fuel gas are the only primary fuels burned. No Fuel oil is used on-site. Only NG and plant
fuel gas is burned as backup fuels.

Equipment Fuel Burned
Heaters and Boilers Plant Fuel Gas
Emergency Generators, Pilots and SRU Tail Gas Incinerator NG
Emergency Generators and Heavy Equipment ULSD
II.B.1.n Condition:

The amine unit shall reduce the H2S content of the Refinery plant gas to 60 ppm or less as described in 40
CFR 60.102a. As used herein, refinery "plant gas" shall have the meaning of "fuel gas" as defined in 40
CFR 60.101a, and may be used interchangeably. [Origin: DAQE-AN101230057-23, SIP Section
IX.H.1.g.ii, SIP Section IX.H.11.g.ii]. [R307-401-8, SIP Section IX.H.1.g.ii, SIP Section IX.H.11.g.ii]

II.B.1.n.1 Monitoring:

Compliance shall be based on a rolling average of 365 days. The permittee shall comply with the
continuous fuel gas monitoring requirements of 40 CFR 60.107a and R307-170. For natural gas,
compliance is assumed while the fuel comes from a public utility.

II.B.1.n.2 Recordkeeping:

The permittee shall comply with the related recordkeeping requirements of 40 CR 60.108a.
Records shall be maintained in accordance with R307-170 and Provision I.S.1 of this permit.
II.B.1.n.3 Reporting:

The permittee shall comply with the related reporting requirements of 40 CR 60.108a. Reports
shall be submitted quarterly in accordance with R307-170-9. The quarterly reports 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 in the report. There are no additional
reporting requirements for this provision except those specified in Section I of this permit.

Status: In Compliance – HF Sinclair has installed and maintains a CEMs for monitoring the H2S content
of the refinery fuel gas. The DAQ CEM specialist determines compliance with all applicable
sections of R307-170-1, and 40 CFR 60, Appendix B, Specification 7. The monitor is on the exit of
the mixed fuel gas system. Excess emissions are reported in the Quarterly CEMS reports submitted
to the DAQ CEM specialist. These reports are reviewed by the CEM specialist.

The real time H2S readings as of July 21, 2024:

Time Average PPM
1 Hr Average 17
3 Hr Average 16
365 Day Average 18

24

II.B.1.o Condition:

i. The permittee shall determine the total annual benzene quantity from facility waste in accordance with
40 CFR 61.355(a), (b), and (c) to demonstrate the source meets the requirements of 40 CFR 61.342(a).
The total annual benzene quantity shall include waste from the Refinery and from the Terminal.
ii. The permittee shall operate in accordance with 40 CFR 63.647(d).
[Origin: 40 CFR 61 Subpart FF, 40 CFR 63 Subpart CC]. [40 CFR 61.342(a), 40 CFR 61.355, 40 CFR
63.647(d)]

II.B.1.o.1 Monitoring:

The permittee shall determine the total annual benzene quantity from facility waste by the test
methods, procedures, and compliance provisions specified in 40 CFR 61.355. Monitoring shall
be conducted in accordance with 40 CFR 61.355(a)(1), (2), (4), (6), (b) and (c).

II.B.1.o.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 61.356(a), (b),
40 CFR 63.655(a), and Provision I.S.1 of this permit.

II.B.1.o.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 61.357(a), (c), 40 CFR 63.655(a), and as
specified in Section I of this permit.

Status: In Compliance – For wastewater, there are no additional reporting or recordkeeping requirements
under Subpart CC, other than those required under 40 CFR 61 Subpart FF. The Total Annual
Benzene quantity from the refinery waste is reported in the Total Annual Benzene NESHAP (TAB)
report required under Subpart FF. The report was last submitted on October 19, 2023, for calendar
year 2022. The TAB was reported as 4.93 Mega Grams (Mg). The next report for 2023 will be due
in October of 2024. The report is due in October of every year.

Note: The TAB report for year 2023, was received on September 4, 2024.

II.B.1.p Condition:

The permittee shall comply with the applicable requirements specified in 40 CFR 61.145 and 40 CFR
61.150 for demolition and renovation activities that occur where asbestos is present. [Origin: 40 CFR 61
Subpart M]. [40 CFR 61.145, 40 CFR 61.150]

II.B.1.p.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.1.p.2 Recordkeeping:

Results of inspections, a copy of each required notification, and records demonstrating
compliance with the applicable requirements specified in 40 CFR 61.145, 40 CFR 61.150, and 40
CFR 61.152 shall be maintained in accordance with Provision I.S.1 of this permit.

25

II.B.1.p.3 Reporting:

Reports and notifications shall be submitted as required in 40 CFR 61.145, 40 CFR 61.150, and
40 CFR 61.153, as applicable. There are no additional reporting requirements for this provision
except those specified in Section I of this permit.

Status: In Compliance – Asbestos reports are submitted quarterly as required.

II.B.1.q Condition:

The permittee shall comply with the applicable requirements specified in 40 CFR 63.2343 for emission
sources that do not require control under 40 CFR 63 Subpart EEEE. Such emission sources are not
subject to any other notification, recordkeeping, or reporting sections in 40 CFR 63 Subpart EEEE,
including 40 CFR 63.2350(c), except as indicated in 40 CFR 63.2343(a) through (d). [Origin: 40 CFR 63
Subpart EEEE]. [40 CFR 63.2343]

II.B.1.q.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.1.q.2 Recordkeeping:

The permittee shall keep documentation that verifies that each storage tank and transfer rack
identified in 40 CFR 63.2343(a) is not required to be controlled. Records shall be maintained in
accordance with 40 CFR 63.2343(a) and Provision I.S.1 of this permit.

II.B.1.q.3 Reporting:

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

Status: In Compliance – An Internal Subpart EEEE NESHAP Applicability Letter was submitted, to the
DAQ, on June 30, 2016.

II.B.1.r Condition:

PM10 emissions from all sources shall not exceed 0.416 tons per day (tpd). [Origin: DAQE-
AN101230057-23, SIP Section IX.H.2.f.i]. [R307-401-8, SIP Section IX.H.2.f.i]

II.B.1.r.1 Monitoring:

A. Setting of emission factors:
The emission factors derived from the most current performance test shall be applied to the
relevant quantities of fuel combusted. Unless adjusted by performance testing as discussed in
B below, the default emission factors to be used are as follows:

Natural gas or Plant gas:
Combustion equipment not listed in condition II.B.14.a: 7.65 lb PM10 /MMscf
Combustion equipment listed in condition II.B.14.a: 0.52 lb PM10 /MMscf

Fuel oil:
The filterable PM10 emission factor for fuel oil combustion shall be determined based on the
26

sulfur content of the oil as follows:
PM10 (lb/1000 gal) = (10 * wt. % S) + 3.22
The condensable PM10 emission factor for fuel oil combustion shall be determined from the
latest edition of AP-42.

Cooling Towers: The PM10 emission factor shall be determined from the latest edition of AP-
42.

FCC Wet Scrubbers: The PM10 emission factors shall be based on the most recent stack test
and verified by parametric monitoring as outlined in SIP Section IX.H.1.g.i.B.III and
IX.H.2.f.i.A.

B. The default emission factors listed in A above apply until such time as stack testing is
conducted as outlined below. At that time a new flow-weighted average emission factor in
terms of: lb PM10/MMBtu shall be derived. Stack testing shall be performed as outlined in
SIP Section IX.H.1.e, R307-165, and paragraph iv. below.
i. Stack testing on all existing units listed in condition II.B.14.a shall be performed at least
once every three (3) years from the date of the last stack test.
ii. Stack testing on all equipment listed in paragraph A. above shall be performed as outlined
in SIP Section IX.H.1.e, R307-165, paragraph iv. below, and as follows:
The emission factor for PM10 shall be determined through use of CTM-039, or other EPA-
approved testing method, as acceptable to the Director. Both the condensable and
filterable fractions shall be included. The PM10 emission factor from each affected heater
and boiler shall be based on the most recent PM10 stack test at the affected heater or boiler
and its daily fuel consumption (MMBtu/day, HHV). For each day of operation prior to
the initial stack test of a newly-installed boiler or process heater, the BACT emission
factor of 0.0070 lb/MMBtu shall be used.
iii. For combustion equipment not listed in condition II.B.14.a, initial stack testing is not
required.
iv. Stack testing shall be performed in accordance with the following:
(a) Notification: At least 30 days before the test, the source shall notify the Director of
the date, time, and place of testing and provide a copy of the source test protocol in
accordance with R307-165. The source test protocol shall be approved by the
Director prior to performing the test. A pretest conference between the permittee,
the tester, and the Director shall be held if directed by the Director.
(b) Sample location. The emission point shall conform to the requirements of 40 CFR
Part 60, Appendix A, Method 1, or other EPA-approved testing method, as
acceptable to the Director. Occupational Safety and Health Administration (OSHA)-
approved access shall be provided to the test location.
(c) Volumetric Flow Rate: The volumetric flow rate shall be measured using 40 CFR 60,
Appendix A, Method 2, or other EPA approved testing method, as acceptable to the
Director.
(d) Calculations: To determine mass emission rates, 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.
(e) The production rate during all compliance testing shall be no less than 90% of the
maximum production rate achieved in the previous three (3) years. If the desired
production rate is not achieved at the time of the test, the maximum production rate
shall be 110% of the tested achieved rate, but not more than the maximum allowable
production rate. This new allowable maximum production rate shall remain in effect
until successfully tested at a higher rate. The permittee shall request a higher
production rate when necessary. Testing at no less than 90% of the higher rate shall
27

be conducted. A new maximum production rate (110% of the new rate) will then be
allowed if the test is successful. This process may be repeated until the maximum
allowable production rate is achieved.

C. Compliance with the source-wide PM10 Cap shall be demonstrated for each day as follows:

Total 24-hour PM10 emissions for the emission points shall be calculated by adding the daily
results of the PM10 emissions equations listed below for natural gas, plant gas, and fuel oil
combustion. These emissions shall be added to the emissions from the cooling towers and
wet scrubbers to arrive at a combined daily PM10 emission total. For purposes of this
subsection a "day" is defined as a period of 24-hours commencing at midnight and ending at
the following midnight.

Daily natural gas and plant gas consumption shall be determined through the use of flow
meters on all gas-fueled combustion equipment.

Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that
supply fuel oil to combustion sources.

The equations used to determine emissions for the boilers and furnaces shall be as follows:
Emissions (tons/day) = Emission Factor (lb/MMscf) * Natural/Plant Gas Consumption
(MMscf/day)/(2,000 lb/ton)
Emissions (tons/day) = Emission Factor (lb/kgal) * Fuel Oil Consumption
(kgal/day)/(2,000 lb/ton).

II.B.1.r.2 Recordkeeping:

Results shall be tabulated for each day, and records shall be kept which include all meter readings
(in the appropriate units), and the calculated emissions. Results of the stack testing shall be
recorded and maintained in accordance with the associated test method. Records and results of
monitoring shall be maintained in accordance with Provision I.S.1 of this permit and SIP Section
IX.H.1.

II.B.1.r.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate compliance
status. There are no additional reporting requirements for this provision except those specified in
Section I of this permit and SIP Section IX.H.1.

Status: In Compliance – According to the Daily PM10 spreadsheet, the daily PM10 limit has not been
exceeded. The maximum source wide daily PM10 was 0.0433 tons as of the July 17, 2024, Stack
Test. All calculations and emission factors have been reviewed under the stack testing and CEM
program.

II.B.1.s Condition:

NOx emissions into the atmosphere from all emission points shall not exceed 347.1 tons per rolling 12-
month period and 2.09 tons per day (tpd). [Origin: DAQE-AN101230057-23, SIP Section IX.H.2.f.ii, SIP
Section IX.H.12.g.ii]. [R307-401-8, SIP Section IX.H.2.f.ii, SIP Section IX.H.12.g.ii]

II.B.1.s.1 Monitoring:
28

A. Setting of emission factors:
The emission factors derived from the most current performance test shall be applied to the
relevant quantities of fuel combusted. Unless adjusted by performance testing as discussed
in B below, the default emission factors to be used are as follows:

Natural gas/refinery fuel gas combustion using:

Equipment marked as Low NOx: 41 lbs/MMscf (0.04 lbs/MMbtu)
Next Generation Ultra Low NOx burners (NGULNB): 0.10 lbs/MMbtu
All boilers with selective catalytic reduction (SCR): 0.02 lbs/MMbtu
All other combustion burners: 100 lb/MMscf
Where: "Natural gas/refinery fuel gas" shall represent any combustion of natural gas,
refinery fuel gas, or combination of the two in the associated burner.

All fuel oil combustion: 120 lbs/Kgal

B. The default emission factors listed above apply until such time as stack testing is conducted
as outlined in SIP Section IX.H.1.e, SIP Section IX.H.11.e, the referenced approval order, or
by NSPS.

C. Compliance with the Source-wide NOx Cap shall be demonstrated for each day as follows:

Total daily NOx emissions for emission points shall be calculated by adding the results of the
NOx equations for plant gas, fuel oil, and natural gas combustion listed below. For purposes
of this subsection a "day" is defined as a period of 24-hours commencing at midnight and
ending at the following midnight.

Daily natural gas and plant gas consumption shall be determined through the use of flow
meters.

Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that
supply combustion sources.

The equations used to determine emissions for the boilers and furnaces shall be as follows:

Emissions (tons/day) = Emission Factor (lb/MMscf) * Natural Gas Consumption
(MMscf/day)/(2,000 lb/ton)

Emissions (tons/day) = Emission Factor (lb/MMscf) * Plant Gas Consumption
(MMscf/day)/(2,000 lb/ton)

Emissions (tons/day) = Emission Factor (lb/MMBTU) * Burner Heat Rating (BTU/hr)* 24
hours per day /(2,000 lb/ton)

Emissions (tons/day) = Emission Factor (lb/kgal) * Fuel Oil Consumption (kgal/day)/(2,000
lb/ton).

D. Compliance with the annual limitation shall be determined on a rolling 12-month total. No
later than 20 days after the end of each month, a new 12-month total shall be calculated using
data from the previous 12 months.

II.B.1.s.2 Recordkeeping:

29

Results shall be tabulated for each day; and records shall be kept which include the meter
readings (in the appropriate units), emission factors, and the calculated emissions. Records and
results of monitoring shall be maintained in accordance with Provision I.S.1 of this permit, SIP
Section IX.H.1, and SIP Section IX.H.11.

II.B.1.s.3 Reporting:

There are no reporting requirements for this provision except those specified in Section I of this
permit, SIP Section IX.H.1, and SIP Section IX.H.11.

Status: In Compliance – According to the NOx spreadsheet, the 12-month rolling total and daily limits have
not been exceeded. The maximum source wide daily NOx was 0.1896 tons per day (tpd)as of July
17, 2024. And the source wide 12-month period NOx was 5.955 tons as of June 30, 2024. All
calculations and emission factors have been reviewed under the stack testing and CEM program.

II.B.1.t Condition:

Emissions of SO2 from all emission points (excluding routine SRU turnaround maintenance emissions)
shall not exceed 110.3 tons per rolling 12-month period and 0.31 tons per day (tpd). [Origin: SIP Section
IX.H.2.f.iii, SIP Section IX.H.12.g.iii, DAQE-AN101230057-23]. [R307-401-8, SIP Section IX.H.2.f.iii,
SIP Section IX.H.12.g.iii]

II.B.1.t.1 Monitoring:

A. Setting of emission factors:
The emission factors listed below shall be applied to the relevant quantities of fuel
combusted:

Natural gas - 0.60 lb SO2 /MMscf

Plant gas - The emission factor to be used in conjunction with plant gas combustion shall be
determined through the use of a CEM which will measure the H2S content of the fuel gas.
The CEM shall operate as outlined in SIP Section IX.H.1.f, SIP Section IX.H.11.f. Except
for system breakdown, repairs, calibration checks, and zero and span adjustments required
under 40 CFR 60.13(d), the permittee of an affected source shall continuously operate all
required continuous monitoring systems and shall meet minimum frequency of operation
requirements as outlined in R307-170 and 40 CFR 60.13. Flow measurement shall be in
accordance with the requirements of 40 CFR 52, Appendix E; 40 CFR 60 Appendix B; or 40
CFR 75, Appendix A. The monitoring system shall comply with all applicable sections of
R307-170; 40 CFR 60.13; and 40 CFR 60, Appendix B - Performance Specifications.

Fuel oil - The emission factor to be used in conjunction with fuel oil combustion shall be
calculated based on the weight percent of sulfur, as determined by ASTM Method D-4294-
89 or EPA-approved equivalent, the density of the fuel oil, and the following equation:
EF (lb of SO2/kgal) = (density lb/gal) * (1000 gal/kgal) * (wt. %S)/100 * (64 g SO2/32 g S)
The weight percent sulfur and the fuel oil density shall be recorded for each day any fuel oil
is combusted.

B. Compliance with the Source-wide SO2 Cap shall be demonstrated for each day as follows:

Total daily SO2 emissions shall be calculated by adding daily results of the SO2 emissions
equations listed below for natural gas, plant gas, and fuel oil combustion. For purposes of
30

this subsection a "day" is defined as a period of 24-hours commencing at midnight and
ending at the following midnight.

The equations used to determine emissions are:
Emissions (tons/day) = Emission Factor (lb/MMscf) * Natural Gas Consumption
(MMscf/day)/(2,000 lb/ton)
Emissions (tons/day) = Emission Factor (lb/MMscf) * Plant Gas Consumption
(MMscf/day)/(2,000 lb/ton)
Emissions (tons/day) = Emission Factor (lb/kgal) * Fuel Oil Consumption (kgal/24
hrs)/(2,000 lb/ton)

For purposes of these equations, fuel consumption shall be measured as outlined below:
Daily natural gas and plant gas consumption shall be determined through the use of flow
meters.
Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks
that supply combustion sources.

C. Compliance with the annual limitation shall be determined on a rolling 12-month total. No
later than 20 days after the end of each month, a new 12-month total shall be calculated using
data from the previous 12 months.

II.B.1.t.2 Recordkeeping:

Results shall be tabulated for each day, and records shall be kept which include CEM readings for
H2S (averaged for each one-hour period), all meter readings (in the appropriate units), fuel oil
parameters (density and wt% sulfur for each day any fuel oil is burned), and the calculated
emissions. Records and results of monitoring shall be maintained in accordance with R307-170,
Provision I.S.1 of this permit, SIP Section IX.H.1, and SIP Section IX.H.11.

II.B.1.t.3 Reporting:

Reports shall be submitted quarterly in accordance with R307-170-9. The quarterly reports 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 in the report. There are no additional
reporting requirements for this provision except those specified in Section I of this permit, SIP
Section IX.H.1, and SIP Section IX.H.11.

Status: In Compliance – According to the SO2 spreadsheet, the 12-month rolling total and daily limits have
not been exceeded. The maximum source wide daily SO2 was 0.0545 tons per day (tpd) as of July
17, 2024. And the source wide 12-month period SO2 was 1.026 tons as of June 30, 2024. All
calculations and emission factors have been reviewed under the stack testing and CEM program.

II.B.1.u Condition: [State-only Requirement]

PM2.5 emissions (filterable + condensable) from all combustion sources shall not exceed 47.6 tons per
rolling 12-month period and 0.134 tons per day (tpd). [Origin: DAQE-AN101230057-23, SIP Section
IX.H.12.g.i]. [R307-401-8, SIP Section IX.H.12.g.i]

II.B.1.u.1 Monitoring:

A. Setting of emission factors:
The emission factors derived from the most current performance test shall be applied to the
31

relevant quantities of fuel combusted. Unless adjusted by performance testing as discussed in
B below, the default emission factors to be used are as follows:

Natural gas or Plant gas:
Combustion equipment not listed in II.B.14.a: 7.65 lb PM2.5 /MMscf
Combustion equipment listed in II.B.14.a: 0.52 lb PM2.5 /MMscf

Fuel oil:
The filterable PM2.5 emission factor for fuel oil combustion shall be determined based on the
sulfur content of the oil as follows:
PM2.5 (lb/1000 gal) = (10 * wt. % S) + 3
The condensable PM2.5 emission factor for fuel oil combustion shall be determined from the
latest edition of AP-42.

FCC Wet Scrubbers:
The PM2.5 emission factors shall be based on the most recent stack test and verified by
parametric monitoring as outlined in SIP Section IX.H.11.g.i.B.III and IX.H.12.g.i.A.

B. The default emission factors listed above apply until such time as stack testing is conducted as
outlined below. At that time a new flow-weighted average emission factor in terms of: lb
PM2.5/MMBtu shall be derived. Stack testing shall be performed as outlined in SIP Section
IX.H.11.e, R307-165, and paragraph iv. below.
i. Stack testing on all existing units listed in condition II.B.14.a shall be performed at least
once every three (3) years from the date of the last stack test.
ii. Stack testing on all equipment listed in paragraph A. above shall be performed as outlined
in SIP Section IX.H.11.e, R307-165, paragraph iv. below, and as follows:
The emission factor for PM2.5 shall be determined through use of CTM-039, or other
EPA-approved testing method, as acceptable to the Director. Both the condensable and
filterable fractions shall be included. The PM2.5 emission factor from each affected heater
and boiler shall be based on the most recent PM2.5 stack test at the affected heater or boiler
and its daily fuel consumption (MMBtu/day, HHV). For each day of operation prior to
the initial stack test of a newly-installed boiler or process heater, the default emission
factor of 0.52 lb/MMBtu shall be used.
iii. For combustion equipment not listed in condition II.B.14.a, initial stack testing is not
required.
iv. Stack testing shall be performed in accordance with the following:
(a) Notification: At least 30 days before the test, the source shall notify the Director of
the date, time, and place of testing and provide a copy of the source test protocol in
accordance with R307-165. The source test protocol shall be approved by the
Director prior to performing the test. A pretest conference between the permittee,
the tester, and the Director shall be held if directed by the Director.
(b) Sample location. The emission point shall conform to the requirements of 40 CFR
Part 60, Appendix A, Method 1, or other EPA-approved testing method, as
acceptable to the Director. Occupational Safety and Health Administration (OSHA)-
approved access shall be provided to the test location.
(c) Volumetric Flow Rate: The volumetric flow rate shall be measured using 40 CFR 60,
Appendix A, Method 2, or other EPA approved testing method, as acceptable to the
Director.
(d) Calculations: To determine mass emission rates, 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.
(e) The production rate during all compliance testing shall be no less than 90% of the
32

maximum production rate achieved in the previous three (3) years. If the desired
production rate is not achieved at the time of the test, the maximum production rate
shall be 110% of the tested achieved rate, but not more than the maximum allowable
production rate. This new allowable maximum production rate shall remain in effect
until successfully tested at a higher rate. The permittee shall request a higher
production rate when necessary. Testing at no less than 90% of the higher rate shall
be conducted. A new maximum production rate (110% of the new rate) will then be
allowed if the test is successful. This process may be repeated until the maximum
allowable production rate is achieved.

C. Compliance with the source-wide PM2.5 Cap shall be demonstrated for each day as follows:

Total 24-hour PM2.5 emissions for the emission points shall be calculated by adding the daily
results of the PM2.5 emissions equations listed below for natural gas, plant gas, and fuel oil
combustion. These emissions shall be added to the emissions from the wet scrubbers to arrive
at a combined daily PM2.5 emission total. For purposes of this subsection a "day" is defined as
a period of 24-hours commencing at midnight and ending at the following midnight.

Daily natural gas and plant gas consumption shall be determined through the use of flow
meters on all gas-fueled combustion equipment.

Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that
supply fuel oil to combustion sources.

The equations used to determine emissions for the boilers and furnaces shall be as follows:
Emissions (tons/day) = Emission Factor (lb/MMscf) * Natural/Plant Gas Consumption
(MMscf/day)/(2,000 lb/ton)
Emissions (tons/day) = Emission Factor (lb/kgal) * Fuel Oil Consumption
(kgal/day)/(2,000 lb/ton).

D. Compliance with the annual limitation shall be determined on a rolling 12-month total. No
later than 20 days after the end of each month, a new 12-month total shall be calculated using
data from the previous 12 months.

II.B.1.u.2 Recordkeeping:

Results shall be tabulated for each day, and records shall be kept which include all meter readings
(in the appropriate units), and the calculated emissions. Results of the stack testing shall be
recorded and maintained in accordance with the associated test method. Records and results of
monitoring shall be maintained in accordance with Provision I.S.1 of this permit and SIP Section
IX.H.11.

II.B.1.u.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate compliance
status. There are no additional reporting requirements for this provision except those specified in
Section I of this permit and SIP Section IX.H.11.

Status: In Compliance – According to the PM2.5 spreadsheet, the 12-month rolling total and daily limits
have not been exceeded. The maximum source wide daily PM2.5 was 0.0397 tons per day (tpd) as of
July 17, 2024. And the source wide 12-month period PM2.5 was 1.184 tons as of June 30, 2024. All
calculations and emission factors have been reviewed under the stack testing and CEM program.
33

II.B.1.v Condition:

In order for site remediation activities not to be subject to the requirements in 40 CFR 63 Subpart
GGGGG, the permittee shall determine that the total quantity of the HAP listed in Table 1 to 40 CFR 63
Subpart GGGGG that is contained in the remediation material excavated, extracted, pumped, or otherwise
removed during all of the site remediations conducted at the facility is less than 1 megagram (Mg)
annually. This exemption applies the 1 Mg limit on a facility-wide, annual basis, and there is no
restriction to the number of site remediations that can be conducted during this period. [Origin: 40 CFR
63 Subpart GGGGG]. [40 CFR 63.7881(c)]

II.B.1.v.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.1.v.2 Recordkeeping:

The permittee shall prepare and maintain on site written documentation to support the
determination that the total HAP quantity in remediation materials for the year is less than 1 Mg.
The documentation shall include a description of the methodology and data used for determining
the total HAP content of the remediation material. (40 CFR 63.7881(c)(2))

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

II.B.1.v.3 Reporting:

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

Status: In Compliance – The 2023 annual determination of the total HAP quantity in remediated material
was made and determined to be < 1 megagram (Mg). This information is maintained on a
spreadsheet and is submitted to the DAQ in an Annual Applicability Evaluation/Determination
Notice. The last notice dated, February 2, 2024, was submitted at time of the inspection. It
indicated that the facility is considered to be exempt from 40 CFR 63 Subpart GGGGG.

II.B.1.w Condition:

By May 15, 2025, the permittee shall submit documentation to the Director on the status of construction
or modification to: tanks 90, 92, 170. The referenced approval order may become invalid if construction
is not commenced by May 15, 2025 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.
[Origin: R307-401-18, DAQE-AN101230057-23]. [R307-401-18]

II.B.1.w.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.1.w.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.w.3 Reporting:
34

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

Status: In Compliance – Tanks 90, 92, and 170 were considered to be in the engineering process at time of
the inspection. According to the refinery, a construction status notice, regarding the tanks, will be
submitted before May 15, 2025. See Status of condition II.A.

II.B.2 Conditions on Fluid Catalytic Cracking (FCC) Units and Associated Scrubbers.

II.B.2.a Condition:

i. Emissions of PM10 (filterable) from the FCC Unit 4 wet gas scrubber (4V82) and FCC Unit 25 wet gas
scrubber (25FCC) shall not exceed 0.50 lb/1000 lb coke burned each.
ii. Emissions of total PM10 (filterable + condensable) from the FCC Unit 25 wet gas scrubber (25FCC)
shall not exceed 0.60 lb/1000 lb coke burned.
[Origin: DAQE-AN101230057-23]. [R307-401-8]

II.B.2.a.1 Monitoring:

To demonstrate compliance, stack testing on each affected emission unit shall be performed as
specified below.
a) Notification: At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the source test protocol in accordance with
R307-165. The source test protocol shall be approved by the Director prior to performing the
test. A pretest conference between the permittee, the tester, and the Director shall be held if
directed by the Director.
b) Sample location. The emission point shall conform to the requirements of 40 CFR Part 60,
Appendix A, Method 1, or other EPA-approved testing method, as acceptable to the Director.
Occupational Safety and Health Administration (OSHA)-approved access shall be provided to
the test location.
c) Volumetric Flow Rate: The volumetric flow rate shall be measured using 40 CFR 60,
Appendix A, Method 2, or other EPA approved testing method, as acceptable to the Director.
d) Calculations: To determine mass emission rates, 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.
e) The production rate during all compliance testing shall be no less than 90% of the maximum
production rate achieved in the previous three (3) years. If the desired production rate is not
achieved at the time of the test, the maximum production rate shall be 110% of the tested
achieved rate, but not more than the maximum allowable production rate. This new allowable
maximum production rate shall remain in effect until successfully tested at a higher rate. The
permittee shall request a higher production rate when necessary. Testing at no less than 90%
of the higher rate shall be conducted. A new maximum production rate (110% of the new rate)
will then be allowed if the test is successful. This process may be repeated until the maximum
allowable production rate is achieved.
f) For the PM10 (filterable) limit:
(1) Frequency: A stack test shall be conducted at least once every three years.
(2) Emissions of filterable PM10 shall be measured using 40 CFR 60, Appendix M, Method
5, 5B or 5F, or other EPA-approved testing method, as acceptable to the Director. All
particulate captured shall be considered PM10.
g) For the total PM10 (filterable + condensable) limit:
(1) Frequency: A stack test shall be conducted at least once annually. Upon demonstration
35

through at least three annual tests that the PM10 limits are not being exceeded, the
permittee may request approval to conduct stack testing less frequently than annually.
(2) Emissions of total PM10 (filterable + condensable) shall be measured using 40 CFR 60,
Appendix M, Method 5 and 202, or other EPA-approved testing method, as acceptable to
the Director. All particulate captured shall be considered PM10.

II.B.2.a.2 Recordkeeping:

Results of the stack testing shall be recorded and maintained in accordance with the associated
test method and Provision I.S.1 of this permit.

II.B.2.a.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate compliance
status. There are no additional reporting requirements for this provision except those specified in
Section I of this permit.

Status: In Compliance – Results of the last stack tests were received, by the DAQ, on October 11, 2023.
Stack testing of the FCC Unit #4 was conducted on September 6, 2023. Stack testing of the FCC
Unit #25 was conducted on August 22 -23, 2023. Stack Testing of the FCC Unit #4 is currently
conducted triennially and stack testing of FCC Unit #25 is currently performed annually. This is
because the request for Reduced Frequency Testing was approved.

II.B.2.b Condition

NOx emissions shall not exceed the following concentrations:
i. From FCC Unit 4:
22.5 ppmvd at 0% O2 on a 365-day rolling average basis; and
40 ppmvd at 0% O2 on a 7-day rolling average basis.
[Origin: DAQE-AN101230057-23]. [R307-401-8]
ii. From FCC Unit 25:
40 ppmvd at 0% O2 on a 365-day rolling average basis; and
80 ppmvd at 0% O2 on a 7-day rolling average basis.
[Origin: DAQE-AN101230057-23, 40 CFR 60 Subpart Ja]. [R307-401-8, 40 CFR 60.102a(b)(2)]

II.B.2.b.1 Monitoring:

The permittee shall install, calibrate, maintain, and operate a CEMs to determine NOx emissions
from each FCC unit.

For the 80 ppmvd limit on FCC unit 25, the instrument shall continuously monitor and record the
concentration by volume (dry basis, 0 percent excess air) of NOx emissions into the atmosphere.
The monitor shall include an O2 monitor for correcting the data for excess air. The permittee
shall install, operate, calibrate, and maintain each NOx and O2 monitor in accordance with 40
CFR 60.105a(f) and (i). Performance testing shall be conducted in accordance with 40 CFR
60.104a(a), (c), (d), as applicable.

Emissions of NOx from the FCC units shall be determined through use of a CEM. Except for
system breakdown, repairs, calibration checks, and zero and span adjustments required under 40
CFR 60.13(d), the permittee of an affected source shall continuously operate all required
continuous monitoring systems and shall meet minimum frequency of operation requirements as
36

outlined in R307-170 and 40 CFR 60.13. The permittee shall utilize monitors to measure
volumetric flow rates from the wet gas scrubber stacks. Flow measurement shall be in
accordance with the requirements of 40 CFR 52, Appendix E; 40 CFR 60 Appendix B; or 40 CFR
75, Appendix A. The monitoring system shall comply with all applicable sections of R307-170;
40 CFR 60.13; and 40 CFR 60, Appendix B - Performance Specifications.

The permittee shall use a NOx and O2 CEMS to monitor the performance of the FCC Units.
CEMS shall be used to demonstrate compliance with the 365-day rolling average NOx and the 7-
day rolling average NOx emission limits established above in accordance with R307-170 and 40
CFR 60 Subpart Ja, as applicable.

II.B.2.b.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.108a(a), as
applicable, R307-170, and Provision I.S.1 of this permit.

II.B.2.b.3 Reporting:

Reports shall be submitted quarterly in accordance with R307-170-9. The quarterly reports 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 in the report. There are no additional
reporting requirements for this provision except those specified in 40 CFR 60.105a(i) and 40 CFR
60.108a(a), (d), as applicable, and Section I of this permit.

Status: In Compliance – The DAQ CEM Specialist determines compliance with HF Sinclair’s CEMs
monitoring systems for the FCC Units #4 and #25. During this inspection, the CEMs were
operational and readings were within the limits specified above. Quarterly CEMs Reports are
submitted and annual RATA tests are conducted by Alliance Technical Group.

II.B.2.c Condition:

SO2 emissions from each FCC Unit shall not exceed the following concentrations:
25 ppmvd at 0% O2 on a 365-day rolling average basis; and
50 ppmvd at 0% O2 on a 7-day rolling average basis.
[Origin: DAQE-AN101230057-23, 40 CFR 60 Subpart J, 40 CFR 60 Subpart Ja, SIP Section
IX.H.1.g.i.A, SIP Section IX.H.11.g.i.A]. [R307-401-8, 40 CFR 60.104(b)(1), 40 CFR 60.102a(b)(3), SIP
Section IX.H.1.g.i.A, SIP Section IX.H.11.g.i.A]

II.B.2.c.1 Monitoring:

The permittee shall install, calibrate, maintain, and operate a CEMs to measure SO2 emissions in
the FCC unit effluent. The instrument shall continuously monitor and record the concentration by
volume (dry basis, corrected to 0 percent excess air) of SO2 emissions into the atmosphere. The
monitor shall include an O2 monitor for correcting the data for excess air. The permittee shall
install, operate, calibrate, and maintain each SO2 and O2 monitor in accordance with 40 CFR
60.104(c), (d), 40 CFR 60.105(a)(9)-(13), 40 CFR 60.106(h), 40 CFR 60.105a(g), (i).
Performance testing shall be conducted in accordance with 40 CFR 60.106(g), (k), 40 CFR
60.108(a), (d), and (e), 40 CFR 60.104a(a), (c), (d), as applicable.

Except for system breakdown, repairs, calibration checks, and zero and span adjustments required
under 40 CFR 60.13(d), the permittee of an affected source shall continuously operate all required
continuous monitoring systems and shall meet minimum frequency of operation requirements as
37

outlined in R307-170 and 40 CFR 60.13. The permittee shall utilize monitors to measure
volumetric flow rates from the wet gas scrubber stacks. Flow measurement shall be in
accordance with the requirements of 40 CFR 52, Appendix E; 40 CFR 60 Appendix B; or 40 CFR
75, Appendix A. The monitoring system shall comply with all applicable sections of R307-170;
40 CFR 60.13; and 40 CFR 60, Appendix B - Performance Specifications.

The permittee shall use a SO2 and O2 CEMS to monitor the performance of the FCC Units.
CEMS shall be used to demonstrate compliance with the 365-day rolling average SO2 and the 7-
day rolling average SO2 emission limits established above in accordance with R307-170, 40 CFR
60 Subpart J, and 40 CFR 60 Subpart Ja.

II.B.2.c.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.107(b)(1),
(4), 40 CFR 60.107(c)(1)-(4), 40 CFR 60.108a(a), R307-170, and Provision I.S.1 of this permit.

II.B.2.c.3 Reporting:

Reports shall be submitted quarterly in accordance with R307-170-9. The quarterly reports 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 in the report. There are no additional
reporting requirements for this provision except those specified in 40 CFR 60.107(c)(1)-(4), 40
CFR 60.107(d), (f), (g), 40 CFR 60.108(e), 40 CFR 60.105a(i) and 40 CFR 60.108a(a), (d), and
Section I of this permit.

Status: In Compliance – See status of condition II.B.2.b.

II.B.2.d Condition:

CO emissions from each FCC Unit shall not exceed 500 ppm by volume (dry basis) on a one-hour
average basis at 0% oxygen. [Origin: DAQE-AN101230057-23, 40 CFR 60 Subpart J, 40 CFR 60
Subpart Ja]. [40 CFR 60.103(a), 40 CFR 60.102a(b)(4), R307-401-8]

II.B.2.d.1 Monitoring:

The permittee shall install, calibrate, maintain, and operate a CEMs to measure CO emissions in
the FCC unit effluent. The instrument shall continuously monitor and record the concentration by
volume (dry basis) of CO emissions into the atmosphere. The permittee shall install, operate, and
maintain each CO monitor in accordance with 40 CFR 60.105(a)(2) and 40 CFR 60.105a(h), (i).

Performance testing shall be conducted in accordance with 40 CFR 60.106(a), (d), and 40 CFR
60.104a(a), (c), (d), as applicable.

Except for system breakdown, repairs, calibration checks, and zero and span adjustments required
under 40 CFR 60.13(d), the permittee of an affected source shall continuously operate all required
continuous monitoring systems and shall meet minimum frequency of operation requirements as
outlined in R307-170 and 40 CFR 60.13. The permittee shall utilize monitors to measure
volumetric flow rates from the wet gas scrubber stacks. Flow measurement shall be in
accordance with the requirements of 40 CFR 52, Appendix E; 40 CFR 60 Appendix B; or 40 CFR
75, Appendix A. The monitoring system shall comply with all applicable sections of R307-170
and 40 CFR 60, Appendix B - Performance Specifications.

38

The permittee shall use a CO and O2 CEMS to monitor the performance of the FCC Units. CEMS
shall be used to demonstrate compliance with the one-hour CO emission limit established above
in accordance with R307-170, 40 CFR 60 Subpart J, and 40 CFR 60 Subpart Ja.

II.B.2.d.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.105(c), 40
CFR 60.108a(a), R307-170, and Provision I.S.1 of this permit.

II.B.2.d.3 Reporting:

Reports shall be submitted quarterly in accordance with R307-170-9. The quarterly reports 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 in the report. There are no additional
reporting requirements for this provision except those specified in 40 CFR 60.105(e), 40 CFR
60.107, 40 CFR 60.105a(i), 40 CFR 60.108a(a), (d), and Section I of this permit.

Status: In Compliance – See status of condition II.B.2.b.

II.B.2.e Condition:

PM emissions shall not exceed the following:
i. From FCC Unit 4: 2.0 lb/ton of coke burn-off in the catalyst regenerator
[Origin: 40 CFR 60 Subpart J]. [40 CFR 60.102(a)(1)]
ii. From FCC Unit 25: 0.5 lb/1000 lb coke burn-off
[Origin: 40 CFR 60 Subpart Ja]. [40 CFR 60.102a(b)(1)(ii)]

II.B.2.e.1 Monitoring:

For FCC unit 4, the permittee shall conduct monitoring as required in 40 CFR 60.105(c), conduct
performance tests and demonstrate compliance with the PM standard using the test methods and
procedures required in 40 CFR 60.106(a) and (b). [40 CFR 60 Subpart J] A stack test shall be
conducted at least once every three years.

For FCC unit 25, the permittee shall conduct performance tests and demonstrate compliance with
the PM standard using the CPMS, test methods, and monitoring required in 40 CFR 60.102a(c),
40 CFR 60.104a(a) through (e), and 40 CFR 60.105a(a), (b), and (i). A stack test shall be
conducted at least once annually. [40 CFR 60 Subpart Ja]

II.B.2.e.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with Provision I.S.1 of this
permit, and as applicable, 40 CFR 60.105(c), 40 CFR 60.105a(b)(1)(ii), (iv), 40 CFR 60.108a(a),
(c).

II.B.2.e.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate compliance
status.

39

There are no additional reporting requirements for this provision except those specified in Section
I of this permit, and as applicable, 40 CFR 60.104a(b) and 40 CFR 60.108a(d).

Status: In Compliance – See Status of condition II.B.2.a.

II.B.2.f Condition:

PM emissions shall not exceed 1.0 lb/1000 lb coke burn-off from each FCC unit. [Origin: SIP Section
IX.H.1.g.i.B.I, SIP Section IX.H.11.g.i.B.I]. [SIP Section IX.H.1.g.i.B.I, SIP Section IX.H.11.g.i.B.I]

II.B.2.f.1 Monitoring:

Compliance with this limit shall be demonstrated by following the stack test protocol specified in
40 CFR 60.106(b) or 40 CFR 60.104a(d) to measure PM emissions on each FCCU, SIP Section
IX.H.1.e, and SIP Section IX.H.11.e. The permittee shall conduct stack tests once every three
years at each FCCU.

For FCC unit 25, the permittee shall install, operate and maintain a continuous parameter monitor
system (CPMS) to measure and record operating parameters from the FCCU and control devices
as per the requirements of 40 CFR 60.105a(b)(1).

[SIP Section IX.H.1.g.i.B.II, III, SIP Section IX.H.11.g.i.B.II, III]

II.B.2.f.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with SIP Section IX.H.1.c,
SIP Section IX.H.1.g.i.B.III, SIP Section IX.H.11.c, SIP Section IX.H.11.g.i.B.III, and Provision
I.S.1 of this permit.

II.B.2.f.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate compliance
status.

There are no additional reporting requirements for this provision except those specified in SIP
Section IX.H.1.c, SIP Section IX.H.11.c, and Section I of this permit.

Status: In Compliance – The stack testing sets the parameters for the CPMS. See status of condition
II.B.2.a.

II.B.2.g Condition:

Visible emissions from the FCC Unit 4/FCC Unit 4 Wet Gas Scrubber shall not exceed 20% opacity.
[Origin: DAQE-AN101230057-23, 40 CFR 60 Subpart J]. [R307-401-8, 40 CFR 60.102(a)]

II.B.2.g.1 Monitoring:

Compliance shall be demonstrated as specified in the most recent EPA-approved alternative
monitoring plan. [SIP Section IX.H.2.f.i.A, SIP Section IX.H.12.g.i.A]

II.B.2.g.2 Recordkeeping:
40

Results of monitoring and records demonstrating compliance with this condition shall be
maintained as specified in the most recent EPA-approved alternative monitoring plan, SIP Section
IX.H.1.c, SIP Section IX.H.11.c, and Provision I.S.1 of this permit. A copy of the most recently
approved alternative monitoring plan shall be kept in a readily accessible location on site.

II.B.2.g.3 Reporting:

Reports shall be submitted as specified in the most recent EPA-approved alternative monitoring
plan. There are no additional reporting requirements for this provision except those specified in
40 CFR 60.105(e), SIP Section IX.H.1.c, SIP Section IX.H.11.c, and Section I of this permit.

Status: In Compliance – Stack testing of the FCC Unit #4 was conducted on September 6, 2023. Stack
Testing sets the parameters for the CPMs. No visible emissions were observed from Unit #4 at time
of the inspection.

II.B.3 Conditions on Sulfur Recovery (SRU)/Tail Gas Incinerator (Unit 17).

II.B.3.a Condition:

i. SRU off gas shall at all times be routed to the 4V82 FCC wet gas scrubber or 25FCC wet gas scrubber
prior to being vented to the atmosphere.
ii. SRU off gas shall be routed to the tail gas incinerator before venting directly to the atmosphere only
during emergency operations or during plant shutdown when both the 4V82 FCC wet gas scrubber
and 25FCC wet gas scrubber are off line.
iii. During periods of SRU downtime, all plant fuel gas shall be treated through the SRU backup scrubber
(Unit 29).
iv. The amine acid gas and sour water stripper acid gas shall be processed in the SRU.
[Origin: DAQE-AN101230057-23, SIP Section IX.H.1.g.iii]. [R307-401-8, SIP Section IX.H.1.g.iii]

II.B.3.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.3.a.2 Recordkeeping:

Records demonstrating compliance with this condition shall be kept during all periods of
operation. Records shall include the date, duration, and reason for routing to the tail gas
incinerator or SRU backup scrubber. Records shall be maintained in accordance with SIP Section
IX.H.1 and 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 SIP Section
IX.H.1 and Section I of this permit.

Status: Not Applicable – Reporting was not required at time of the inspection.

II.B.3.b Condition:

i. Except as provided in 40 CFR 60.102a(f)(3), the permittee of an affected sulfur recovery plant shall
comply with the following.
(a) For a sulfur recovery plant with an oxidation control system or a reduction control system
41

followed by incineration, the permittee shall not discharge or cause the discharge of any gases
into the atmosphere containing SO2 in excess of the emission limit calculated using Equation 2 of
40 CFR 60.102a(f)(2)(i). For Claus units that use only ambient air in the Claus burner or that
elect not to monitor O2 concentration of the air/oxygen mixture used in the Claus burner or for
non-Claus sulfur recovery plants, this SO2 emission limit is 2,500 ppmv (dry basis) at zero
percent excess air. (40 CFR 60.102a(f)(2)(i))
(b) If the sulfur recovery plant consists of multiple process trains or release points, the permittee may
comply with the applicable emission limit for each process train or release point individually or
comply with the applicable emission limit in 40 CFR 60.102a(f)(2)(i) as a flow rate weighted
average for a group of release points from the sulfur recovery plant provided that flow is
monitored as specified in 40 CFR 60.106a(a)(7); if flow is not monitored as specified in 40 CFR
60.106a(a)(7), the permittee shall comply with the applicable emission limit in 40 CFR
60.102a(f)(2)(i) for each process train or release point individually. (40 CFR 60.102a(f)(2))
ii. For a sulfur recovery plant, the permittee shall conduct a root cause analysis and a corrective action
analysis each time the SO2 emissions are more than 227 kg (500 lb) greater than the amount that
would have been emitted if the SO2 was equal to the applicable emissions limit in 40 CFR
60.102a(f)(2) during one or more consecutive periods of excess emissions or any 24-hour period,
whichever is shorter. (40 CFR 60.103a(c)(3))
iii. A root cause analysis and corrective action analysis shall be completed as soon as possible, but no
later than 45 days after a discharge meeting the condition above. Special circumstances affecting the
number of root cause analyses and/or corrective action analyses are provided in 40 CFR 60.103a(d)(1)
through (5). (40 CFR 60.103a(d))
[Origin: 40 CFR 60 Subpart Ja]. [40 CFR 60.102a(f), 40 CFR 60.103a, SIP Section IX.H.1.g.iii]

II.B.3.b.1 Monitoring:

(a) The permittee shall install, operate, calibrate, and maintain an instrument for continuously
monitoring and recording the concentration (dry basis, zero percent excess air) of any SO2
emissions into the atmosphere. The monitor shall include an oxygen monitor for correcting
the data for excess air. (40 CFR 60.106a(a)(1))
(b) For sulfur recovery plants that use oxygen or oxygen enriched air in the Claus burner and
that elect to monitor O2 concentration of the air/oxygen mixture supplied to the Claus burner,
the permittee shall install, operate, calibrate, and maintain an instrument for continuously
monitoring and recording the O2 concentration of the air/oxygen mixture supplied to the
Claus burner in order to determine the allowable emissions limit. As an alternative to the O2
monitor required in this paragraph, the permittee may install, calibrate, operate, and maintain
a CPMS to measure and record the volumetric gas flow rate of ambient air and oxygen-
enriched gas supplied to the Claus burner and calculate the hourly average O2 concentration
of the air/oxygen mixture used in the Claus burner as specified in 40 CFR 60.106a(a)(6). (40
CFR 60.106a(a)(5), (6))
(c) If the permittee elects to comply with the SO2 emission limit in 40 CFR 60.102a(f)(2)(i) as a
flow rate weighted average for a group of release points from the sulfur recovery plant rather
than for each process train or release point individually, the permittee shall install, calibrate,
operate, and maintain a CPMS to measure and record the volumetric gas flow rate of each
release point within the group of release points from the sulfur recovery plant as specified in
40 CFR 60.106a(a)(7). (40 CFR 60.106a(a)(7))
(d) The permittee shall implement the corrective action(s) identified in the corrective action
analysis in accordance with 40 CFR 60.103a(e). (40 CFR 60.103a(e))
(e) Performance testing shall be conducted in accordance with 40 CFR 60.104a(a), (c), and (h).
(f) Except for system breakdown, repairs, calibration checks, and zero and span adjustments
required under 40 CFR 60.13(d), the permittee of an affected source shall continuously
operate all required continuous monitoring systems and shall meet minimum frequency of
operation requirements as outlined in R307-170 and 40 CFR 60.13. Flow measurement shall
42

be in accordance with the requirements of 40 CFR 52, Appendix E; 40 CFR 60 Appendix B;
or 40 CFR 75, Appendix A. The monitoring system shall comply with all applicable sections
of R307-170; 40 CFR 60.13; and 40 CFR 60, Appendix B - Performance Specifications. (SIP
Section IX.H.1.f.i)

II.B.3.b.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.103a(e), 40
CFR 60.108a(a)-(c), R307-170, and Provision I.S.1 of this permit.

II.B.3.b.3 Reporting:

Reports shall be submitted quarterly in accordance with R307-170-9. The quarterly reports 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 in the report. There are no additional
reporting requirements for this provision except those specified in 40 CFR 60.106a(b), 40 CFR
60.108a(d), and Section I of this permit.

Status: In Compliance – The Reduction in Air Pollutants 40 CFR 60 Subpart Ja SRU SO2 Limit Voluntary
Reduction Notice, dated May 17, 2024, was received by the DAQ on May 20, 2024. Also, a Notice of
Compliance Status Operation Maintenance and Monitoring Plan (OMMP) update, regarding the
Reduction in SO2 Air Pollutants was received by the DAQ on September 3, 2024. It is considered
to be a work in progress. See attached email.

II.B.4 Conditions on Compression Ignition (CI) and Spark Ignition (SI) RICE.

II.B.4.a Condition:

For the two natural gas-fired standby engines, each 170 kW (228 hp):

i. For stationary SI ICE with a maximum engine power greater than or equal to 75 KW (100 HP)
(except gasoline and rich burn engines that use LPG), the permittee shall comply with the emission
standards in Table 1 of 40 CFR 60 Subpart JJJJ. (40 CFR 60.4233(e))
ii. For emergency stationary SI ICE with a maximum engine power of greater than 19 KW (25 HP), the
permittee shall not install engines that do not meet the applicable requirements in 40 CFR 60.4233
after January 1, 2011. (40 CFR 60.4236(c)) This requirement does not apply to affected emission
units that have been modified or reconstructed, and it does not apply to affected emission units that
were removed from one existing location and reinstalled at a new location. (40 CFR 60.4236(e))
iii. The permittee shall operate and maintain affected emission units that achieve the emission standards
as required in this condition over the entire life of the engine (40 CFR 60.4234)
iv. The air-to-fuel ratio (AFR) controller, if used, shall be maintained and operated appropriately by the
permittee in order to ensure proper operation of affected emission units and control device to
minimize emissions at all times. (40 CFR 60.4243(g))
[Origin: 40 CFR 60 Subpart JJJJ]. [40 CFR 63 Subpart ZZZZ, 40 CFR 60.4233(e), 40 CFR 60.4234, 40
CFR 60.4236, 40 CFR 60.4243]

II.B.4.a.1 Monitoring:

(a) For affected emission units subject to 40 CFR 60.4233(e), the permittee shall demonstrate
compliance according to one of the methods specified in paragraphs (a)(1) and (2) of this
section.
(1) Purchasing an engine certified according to procedures specified in 40 CFR 60 Subpart
43

JJJJ, for the same model year and demonstrating compliance according to one of the
methods specified in paragraphs (1)a) and b) of this section.
a) If the permittee operates and maintains the certified stationary SI internal
combustion engine and control device according to the manufacturer's emission-
related written instructions, the permittee shall keep records of conducted
maintenance to demonstrate compliance, but no performance testing is required.
The permittee shall also meet the requirements as specified in 40 CFR part 1068,
subparts A through D, as they apply. If the permittee adjusts engine settings
according to and consistent with the manufacturer's instructions, the affected
emission unit will not be considered out of compliance.
b) If the permittee does not operate and maintain the certified stationary SI internal
combustion engine and control device according to the manufacturer's emission-
related written instructions, the engine will be considered a non-certified engine,
and the permittee shall demonstrate compliance according to (i) of this section.
(i) If the affected emission unit is greater than or equal to 100 HP and less than or
equal to 500 HP, the permittee shall keep a maintenance plan and records of
conducted maintenance and shall, to the extent practicable, maintain and
operate the engine in a manner consistent with good air pollution control
practice for minimizing emissions. In addition, the permittee shall conduct an
initial performance test within 1 year of engine startup to demonstrate
compliance.
(2) Purchasing a non-certified engine and demonstrating compliance with the emission
standards specified in 40 CFR 60.4233(e) and according to the requirements specified
in 40 CFR 60.4244, as applicable, and according to paragraph (2)a) of this section.
a) If the affected emission unit is greater than 25 HP and less than or equal to 500
HP, the permittee shall keep a maintenance plan and records of conducted
maintenance and shall, to the extent practicable, maintain and operate the engine
in a manner consistent with good air pollution control practice for minimizing
emissions. In addition, the permittee shall conduct an initial performance test to
demonstrate compliance.
(Origin: 40 CFR 60.4243(b))
(b) For affected emission units less than or equal to 500 HP and if the permittee purchases a
non-certified engine or does not operate and maintain the certified affected emission unit and
control device according to the manufacturer's written emission-related instructions, the
permittee is required to perform initial performance testing as indicated in this section, but is
not required to conduct subsequent performance testing unless the stationary engine
undergoes rebuild, major repair or maintenance as specified in 40 CFR 60.4243(f). (Origin:
40 CFR 60.4243(f))
(c) The permittee shall conduct performance tests in accordance with the procedures in 40 CFR
60.4244(a) through (f). (Origin: 40 CFR 60.4244)

Records required for this permit condition will also serve as monitoring.

II.B.4.a.2 Recordkeeping:

(a) For each affected emission unit, the permittee shall keep records of the information in
paragraphs (a)(1) through (4) of this section.
(1) All notifications submitted to comply with this condition and all documentation
supporting any notification.
(2) Maintenance conducted on each affected emission unit.
(3) If the affected emission unit is a certified engine, documentation from the manufacturer
that the affected emission unit is certified to meet the emission standards and
information as required in 40 CFR parts 1048, 1054, and 1060, as applicable.
44

(4) If the affected emission unit is not a certified engine or is a certified engine operating in
a non-certified manner and subject to section (a)(1)b) of monitoring, documentation
that the engine meets the emission standards.
(Origin: 40 CFR 60.4245(a))
(b) The permittee shall keep records of the install date of each affected emission unit and the
applicable requirements under 40 CFR 60 Subpart JJJJ for the respective model year engine.

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

II.B.4.a.3 Reporting:

For affected emission units that are subject to performance testing, the permittee shall submit a
copy of each performance test as conducted in 40 CFR 60.4244 within 60 days after the test has
been completed. (Origin: 40 CFR 60.4245(d))

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

Status: In Compliance – There is a natural gas backup generator for the Administration (East Engine) and
Maintenance Buildings (West Engine). The natural gas generators are considered to be certified
engines and are operated accordingly. Both generators have gas flow meters and non-resettable
hour meters. Repairs are made in-house on an as needed basis. Major repairs are conducted by
Energy Management Corp., which provides invoices. The engines are maintenance checked weekly
for 15 – 30 minutes.

II.B.4.b Condition:

For the two natural gas-fired standby engines, each 170 kW (228 hp):

The permittee shall operate the emergency affected emission units according to the requirements in
paragraphs i. through iii. In order for the engine to be considered an emergency stationary ICE under 40
CFR 60 Subpart JJJJ, any operation other than emergency operation, maintenance and testing, and
operation in non-emergency situations for 50 hours per year, as described in i. through iii., is prohibited.
If the engine is not operated in accordance with paragraphs i. through iii., it will not be considered an
emergency engine and shall meet all requirements for non-emergency engines.
i. There is no time limit on the use of emergency stationary ICE in emergency situations.
ii. Emergency stationary ICE may be operated for the purpose specified in 40 CFR 60.4243(d)(2)(i) for
a maximum of 100 hours per calendar year. Any operation for non-emergency situations as allowed
by paragraph iii. counts as part of the 100 hours per calendar year allowed by this paragraph.
(a) Emergency stationary ICE may be operated for maintenance checks and readiness testing,
provided that the tests are recommended by federal, state or local government, the
manufacturer, the vendor, the regional transmission organization or equivalent balancing
authority and transmission operator, or the insurance company associated with the engine. The
permittee may petition for approval of additional hours to be used for maintenance checks and
readiness testing, but a petition is not required if the permittee maintains records indicating that
federal, state, or local standards require maintenance and testing of emergency ICE beyond 100
hours per calendar year.
iii. Emergency stationary ICE may operate up to 50 hours per calendar year in non-emergency
situations, as specified in 40 CFR 60.4243(d)(3).

The permittee may operate affected natural gas fired emission units using propane for a maximum of 100
hours per year as an alternative fuel solely during emergency operations, but the permittee shall keep
45

records of such use. If propane is used for more than 100 hours per year in an affected emission unit that
is not certified to the emission standards when using propane, the permittee is required to conduct a
performance test to demonstrate compliance with the emission standards of 40 CFR 60.4233.
[Origin: 40 CFR 60 Subpart JJJJ]. [40 CFR 60.4243(d), 40 CFR 60.4243(e), 40 CFR 63 Subpart ZZZZ]

II.B.4.b.1 Monitoring:

To determine the duration of operation, the permittee shall install a non-resettable hour meter for
each emergency engine. [Origin: DAQE-AN101230057-23] Records required for this permit
condition will also serve as monitoring.

II.B.4.b.2 Recordkeeping:

Records documenting the operation of each emergency engine shall be kept in a log on a monthly
basis and shall include the following:
(a) The date the emergency engine was used
(b) The duration of operation in hours
(c) The reason for the emergency engine usage
[Origin: DAQE-AN101230057-23]

If additional hours are to be used for maintenance checks and readiness testing, the permittee
shall maintain records indicating that federal, state, or local standards require maintenance and
testing of emergency ICE beyond 100 hours per calendar year. (Origin: 40 CFR 60.4243(d))

The permittee shall keep records of propane usage to demonstrate compliance with 40 CFR
60.4243(e).

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

II.B.4.b.3 Reporting:

The permittee shall submit an annual report in accordance with 40 CFR 60.4245(e), as applicable.
There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In Compliance – Engine hours of operation for 2024, at time of the inspection:

Engine Hours of Operation
East Natural Gas Engine 3.3 Maintenance
0.0 Emergency
West Natural Gas Engine 6.7 Maintenance
0.0 Emergency

II.B.4.c Condition:

For the diesel-fired engine, 540 hp standby:

The permittee shall operate and maintain affected emission units that achieve the emission standards as
required in 40 CFR 60.4205 over the entire life of the engine. The permittee shall do all of the following,
except as permitted in 40 CFR 60.4211(g):
i. Operate and maintain the stationary CI ICE and control device according to the manufacturer's
46

emission-related written instructions;
ii. Change only those emission-related settings that are permitted by the manufacturer; and
iii. Meet the requirements of 40 CFR part 1068, as applicable.
[Origin: 40 CFR 60 Subpart IIII]. [40 CFR 60.4206, 40 CFR 60.4211(a)]

II.B.4.c.1 Monitoring:

(a) The permittee shall document activities performed to assure proper operation and
maintenance.
(b) If the permittee does not install, configure, operate, and maintain affected emission units and
control devices according to the manufacturer's emission-related written instructions, or
changes emission-related settings in a way that is not permitted by the manufacturer, the
permittee shall demonstrate compliance as follows:
(1) For affected emission units greater than 500 HP:
a. Keep a maintenance plan and records of conducted maintenance; and
b. To the extent practicable, maintain and operate the engine in a manner consistent
with good air pollution control practice for minimizing emissions; and
c. Conduct an initial performance test to demonstrate compliance with the applicable
emission standards within 1 year of startup, or within 1 year after an engine and
control device is no longer installed, configured, operated, and maintained in
accordance with the manufacturer's emission-related written instructions, or within 1
year after changing emission-related settings in a way that is not permitted by the
manufacturer. The permittee shall conduct subsequent performance testing every
8,760 hours of engine operation or 3 years, whichever comes first, thereafter to
demonstrate compliance with the applicable emission standards.
(Origin: 40 CFR 60.4211(g)).

II.B.4.c.2 Recordkeeping:

Records demonstrating compliance with this condition and results of monitoring shall be
maintained in accordance with Provision I.S.1 of this permit.

II.B.4.c.3 Reporting:

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

Status: In Compliance – The 540 hp diesel generator is considered to be a certified engine and is operated
accordingly. The generator has a resettable hour meter. Repairs are made in-house on an as needed
basis. Maintenance records are kept at the Pump/Maintenance shop. Major repairs are conducted
by Energy Management Corp., which provides invoices. The engine is maintenance checked weekly
for 15 – 30 minutes.

II.B.4.d Condition:

For the diesel-fired engine, 540 hp standby:

Any diesel fuel combusted in the emergency generator shall meet the requirements of 40 CFR 1090.305
for nonroad diesel fuel. [Origin: 40 CFR 60 Subpart IIII]. [40 CFR 60.4207(b)]

II.B.4.d.1 Monitoring:

47

Records required for this permit condition will serve as monitoring.

II.B.4.d.2 Recordkeeping:

The permittee shall keep records of fuel purchase invoices, fuel supplier certifications, or records
of testing that demonstrate compliance with this condition. These records shall be maintained in
accordance with Provision I.S.1. of this permit.

II.B.4.d.3 Reporting:

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

Status: In Compliance – See status of condition II.B.1.m.

II.B.4.e Condition:

For the diesel-fired engine, 540 hp standby:

The permittee shall operate the emergency affected emission unit according to the requirements in
paragraphs i. through iii. In order for the engine to be considered an emergency stationary ICE under 40
CFR 60 Subpart IIII, any operation other than emergency operation, maintenance and testing, and
operation in non-emergency situations for 50 hours per year, as described in i. through iii., is prohibited.
If the engine is not operated in accordance with paragraphs i. through iii., it will not be considered an
emergency engine and shall meet all requirements for non-emergency engines.
i. There is no time limit on the use of emergency stationary ICE in emergency situations.
ii. Emergency stationary ICE may be operated for the purpose specified in 40 CFR 60.4211(f)(2)(i) for
a maximum of 100 hours per calendar year. Any operation for non-emergency situations as allowed
by paragraph iii. counts as part of the 100 hours per calendar year allowed by this paragraph.
(a) Emergency stationary ICE may be operated for maintenance checks and readiness testing,
provided that the tests are recommended by federal, state or local government, the
manufacturer, the vendor, the regional transmission organization or equivalent balancing
authority and transmission operator, or the insurance company associated with the engine. The
permittee may petition for approval of additional hours to be used for maintenance checks and
readiness testing, but a petition is not required if the permittee maintains records indicating that
federal, state, or local standards require maintenance and testing of emergency ICE beyond 100
hours per calendar year.
iii. Emergency stationary ICE may operate up to 50 hours per calendar year in non-emergency
situations, as specified in 40 CFR 60.4211(f)(3).
[Origin: 40 CFR 40 CFR 60 Subpart IIII]. [40 CFR 60.4211(f)]

II.B.4.e.1 Monitoring:

To determine the duration of operation, the permittee shall install a non-resettable hour meter for
each emergency engine. [Origin: DAQE-AN101230057-23] Records required for this permit
condition will also serve as monitoring.

II.B.4.e.2 Recordkeeping: Records documenting the operation of each emergency engine shall be kept in a log on a monthly basis and shall include the following: (a) The date the emergency engine was used
48

(b) The duration of operation in hours
(c) The reason for the emergency engine usage
[Origin: DAQE-AN101230057-23]

If additional hours are to be used for maintenance checks and readiness testing, the permittee shall maintain records indicating that federal, state, or local standards require maintenance and
testing of emergency ICE beyond 100 hours per calendar year. (40 CFR 60.4211(f))
Records demonstrating compliance with this condition shall be maintained in accordance with
Provision I.S.1 of this permit.

II.B.4.e.3 Reporting:

The permittee shall submit an annual report in accordance with 40 CFR 60.4214(d), as applicable.
There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In Compliance – Engine hours of operation for 2024, at time of the inspection:

Engine Hours of Operation
540 hp Diesel Engine 19.2 Maintenance
0.0 Emergency

II.B.4.f Condition:

For the diesel-fired engine, 540 hp standby:

i. After December 31, 2008, the permittee shall not install stationary CI ICE (excluding fire pump
engines) that do not meet the applicable requirements for 2007 model year engines.
ii. The permittee shall not import stationary CI ICE with a displacement of less than 30 liters per
cylinder that do not meet the applicable requirements specified in paragraph i. of this condition after
the dates specified in paragraph i. of this condition.
iii. These requirements do not apply to affected emission units that have been modified or reconstructed,
and do not apply to affected emission units that were removed from one existing location and
reinstalled at a new location.
[Origin: 40 CFR 60 Subpart IIII]. [40 CFR 60.4208]

II.B.4.f.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.4.f.2 Recordkeeping:

The permittee shall keep records of the install date of each affected emission unit and the
applicable requirements under 40 CFR 60 Subpart IIII for the respective model year engine.
Records shall be maintained as described in Provision I.S.1 of this permit.

II.B.4.f.3 Reporting:

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

Status: In Compliance – The 540 hp diesel engine is a 2014 and is considered to be the newest on-site
generator. See status of condition II.B.4.c.
49

II.B.4.g Condition:

For the diesel-fired engine, 540 hp standby:

2007 model year and later emergency affected emission units with a displacement of less than 30 liters
per cylinder that are not fire pump engines shall comply with the emission standards for new nonroad CI
ICE in 40 CFR 60.4202, for all pollutants, for the same model year and maximum engine power for their
2007 model year and later emergency stationary CI ICE. If the permittee conducts performance tests in-
use on emergency stationary CI ICE with a displacement of less than 30 liters per cylinder they shall meet
the not-to-exceed (NTE) standards as indicated in 40 CFR 60.4212. [Origin: 40 CFR 60 Subpart IIII].
[40 CFR 60.4205(b), 40 CFR 60.4205(e)]

II.B.4.g.1 Monitoring:

The permittee shall comply by purchasing an engine certified to the emission standards in 40 CFR
60.4205(b) for the same model year and maximum engine power. The engine shall be installed
and configured according to the manufacturer's emission-related specifications, except as
permitted in 40 CFR 60.4211(g). (Origin: 40 CFR 60.4211(c))

If the permittee does not install, configure, operate, and maintain affected emission units and
control devices according to the manufacturer's emission-related written instructions, or changes
emission-related settings in a way that is not permitted by the manufacturer, the permittee shall
demonstrate compliance as follows:
(a) For affected emission units greater than 500 HP:
i. Keep a maintenance plan and records of conducted maintenance; and
ii. To the extent practicable, maintain and operate the engine in a manner consistent with
good air pollution control practice for minimizing emissions; and
iii. Conduct an initial performance test to demonstrate compliance with the applicable
emission standards within 1 year of startup, or within 1 year after an engine and control
device is no longer installed, configured, operated, and maintained in accordance with the
manufacturer's emission-related written instructions, or within 1 year after changing
emission-related settings in a way that is not permitted by the manufacturer. The
permittee shall conduct subsequent performance testing every 8,760 hours of engine
operation or 3 years, whichever comes first, thereafter to demonstrate compliance with the
applicable emission standards.
(Origin: 40 CFR 60.4211(g))

II.B.4.g.2 Recordkeeping:

Records demonstrating compliance with this condition and results of monitoring shall be
maintained in accordance with Provision I.S.1 of this permit.

II.B.4.g.3 Reporting:

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

Status: In Compliance – See status of condition II.B.4.c.

II.B.4.h Condition:

For the nine diesel-fired engines, 224 hp water well No. 3, 393 hp fire pump No. 1, 393 hp fire pump No.
50

2, 180 hp fire pump, three (220 hp each) plant air backup compressors, 470 hp standby at Boiler House,
and 380 hp standby at Central Control Room:

The permittee shall comply with the following requirements at all times for each emergency affected
emission unit:
i. The permittee shall operate the affected emission unit according to the requirements in paragraphs i(a)
through i(c). In order for the engine to be considered an emergency stationary RICE under 40 CFR 63
Subpart ZZZZ, any operation other than emergency operation, maintenance and testing, and operation
in non-emergency situations for 50 hours per year, as described in i(a) through i(c), is prohibited. If
the engine is not operated in accordance with paragraphs i(a) through i(c), it will not be considered an
emergency engine and shall meet all requirements for non-emergency engines.
(a) There is no time limit on the use of emergency stationary RICE in emergency situations.
(b) Emergency stationary RICE may be operated for the purpose specified in paragraph (1) for a
maximum of 100 hours per calendar year. Any operation for non-emergency situations as allowed
by paragraph i(c) counts as part of the 100 hours per calendar year allowed by this paragraph.
(1) Emergency stationary RICE may be operated for maintenance checks and readiness testing,
provided that the tests are recommended by federal, state or local government, the
manufacturer, the vendor, the regional transmission organization or equivalent balancing
authority and transmission operator, or the insurance company associated with the engine. The
permittee may petition for approval of additional hours to be used for maintenance checks and
readiness testing, but a petition is not required if the permittee maintains records indicating that
federal, state, or local standards require maintenance and testing of emergency RICE beyond
100 hours per calendar year.
(c) Emergency stationary ICE may operate up to 50 hours per calendar year in non-emergency
situations, as specified in 40 CFR 63.6640(f)(3).
ii. The permittee shall meet the following requirements at all times, except during periods of startup:
(a) Change oil and filter every 500 hours of operation or annually, whichever comes first;
(b) Inspect air cleaner every 1,000 hours of operation or annually, whichever comes first, and replace
as necessary;
(c) Inspect all hoses and belts every 500 hours of operation or annually, whichever comes first, and
replace as necessary.
During periods of startup, the permittee shall minimize the engine's time spent at idle and minimize
the engine's startup time to a period needed for appropriate and safe loading of the engine, not to
exceed 30 minutes, after which time the non-startup emission limitations apply.
iii. The permittee shall comply with the applicable general provisions in 40 CFR 63.1-15 as identified in
Table 8 of 40 CFR 63 Subpart ZZZZ.
[Origin: 40 CFR 63 Subpart ZZZZ]. [40 CFR 63.6595(a)(1), 40 CFR 63.6602, 40 CFR 63.6605(a), 40
CFR 63.6625(h), 40 CFR 63.6640(f), 40 CFR 63.6665, 40 CFR 63 Subpart ZZZZ Table 2c, 40 CFR 63
Subpart ZZZZ Table 8]

II.B.4.h.1 Monitoring:

The permittee shall install a non-resettable hour meter if one is not already installed. [40 CFR
63.6625(f), DAQE-AN101230057-23]

If an emergency engine is operating during an emergency and it is not possible to shut down the
engine in order to perform the work practice requirements on the required schedule, or if
performing the work practice on the required schedule would otherwise pose an unacceptable risk
under federal, state, or local law, the work practice can be delayed until the emergency is over or
the unacceptable risk under federal, state, or local law has abated. The work practice shall be
performed as soon as practicable after the emergency has ended or the unacceptable risk under
federal, state, or local law has abated. [40 CFR 63 Subpart ZZZZ Table 2c Footnote 1]

51

The permittee shall demonstrate continuous compliance by operating and maintaining the
stationary RICE and after-treatment control device (if any) according to the manufacturer's
emission-related written operation and maintenance instructions or develop and follow their own
maintenance plan which must provide to the extent practicable for the maintenance and operation
of the engine in a manner consistent with good air pollution control practice for minimizing
emissions. [40 CFR 63.6625(e), 40 CFR 63.6640(a), 40 CFR 63 Subpart ZZZZ Table 6]

The permittee has the option of utilizing an oil analysis program in order to extend the specified
oil change requirement in accordance with 40 CFR 63.6625(i).

The permittee shall comply with the applicable general provisions in 40 CFR 63.1-15 as
identified in Table 8 of 40 CFR 63 Subpart ZZZZ. [40 CFR 63.6665].

II.B.4.h.2 Recordkeeping:

Records documenting the operation of each emergency engine shall be kept in a log on a monthly
basis and shall include the following:
(a) The date the emergency engine was used
(b) The duration of operation in hours
(c) The reason for the emergency engine usage
[Origin: DAQE-AN101230057-23]

The permittee shall keep the records described in 40 CFR 63.6655(a)(1)-(5) as applicable. [40
CFR 63.6655(a)]

If additional hours are to be used for maintenance checks and readiness testing, the permittee
shall maintain records indicating that federal, state, or local standards require maintenance and
testing of emergency RICE beyond 100 hours per calendar year. [40 CFR 63.6640(f)(2)(i)]

The permittee shall keep records that demonstrate continuous compliance with each applicable
work or management practice [including, but not limited to, the manufacturer's emission-related
operation and maintenance instructions or the permittee-developed maintenance plan]. [40 CFR
63.6655(d), 40 CFR 63 Subpart ZZZZ Table 6]

Records of the maintenance conducted shall be kept in order to demonstrate that the permittee
operated and maintained the affected emission unit and after-treatment control device (if any)
according to their own maintenance plan. [40 CFR 63.6655(e)]

The permittee shall comply with the applicable general provisions in 40 CFR 63.1-15 as
identified in Table 8 of 40 CFR 63 Subpart ZZZZ. [40 CFR 63.6665]

Records demonstrating compliance with this condition shall be maintained in accordance with 40
CFR 63.6660 and Provision I.S.1 of this permit.

II.B.4.h.3 Reporting:

The permittee shall report any failure to perform the work practice on the schedule required and
the federal, state or local law under which the risk was deemed unacceptable. [40 CFR 63 Subpart
ZZZZ Table 2c Footnote 1]

The permittee shall comply with the applicable general provisions in 40 CFR 63.1-15 as
identified in 40 CFR 63 Subpart ZZZZ Table 8. [40 CFR 63.6665] The permittee shall also
report each instance in which it did not meet the applicable requirements in Table 8.
52

[40 CFR 63.6640(e)]

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

Status: In Compliance – The 470 hp diesel Boiler House generator is considered to be a certified engine.
The remaining engines, in this condition, are not certified and have been grandfathered. The
engines are maintenance checked weekly for 15 – 30 minutes.

Engine hours of operation as of July 19, 2024:

Engine Hours of Operation - Maintenance Hours of Operation – Emergency
224 hp Water Well #3 6.6 24.5
393 hp Fire Pump #1 2.5 0.0
393 hp Fire Pump #2 12.7 13.6
180 hp Fire Pump DD 6.1 1.7
220 hp Backup Air
Compressor K13
4.9 0.0
220 hp Back Air
Compressor K14
2.3 0.0
202 hp Backup Air
Compressor K16
1.8 0.0
470 hp Boiler House 3.4 0.0
380 hp Central Control
Room
6.5 0.0

II.B.4.i Condition:

For the nine diesel-fired engines, 224 hp water well No. 3, 393 hp fire pump No. 1, 393 hp fire pump No.
2, 180 hp fire pump, three (220 hp each) plant air backup compressors, 470 hp standby at Boiler House,
and 380 hp standby at Central Control Room:

At all times the permittee shall operate and maintain any affected source, including associated air
pollution control equipment and monitoring equipment, in a manner consistent with safety and good air
pollution control practices for minimizing emissions. The general duty to minimize emissions does not
require the permittee to make any further efforts to reduce emissions if levels required by this standard
have been achieved. Determination of whether such operation 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, review of operation and maintenance procedures, review of operation and maintenance records,
and inspection of the source. [Origin: 40 CFR 63 Subpart ZZZZ]. [40 CFR 63.6605(b)]

II.B.4.i.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.4.i.2 Recordkeeping:

The permittee shall keep records of actions taken during periods of malfunction to minimize
emissions in accordance with 40 CFR 63.6605(b), including corrective actions to restore
malfunctioning process and air pollution control and monitoring equipment to its normal or usual
manner of operation. [40 CFR 63.6655(a)] The permittee shall document activities performed to
53

assure proper operation and maintenance. Records shall be maintained in accordance with 40
CFR 63.6660 and Provision I.S.1 of this permit.

II.B.4.i.3 Reporting:

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

Status: In Compliance – See status of condition II.B.4.h.

II.B.4.j Condition:

For the diesel-fired engine, 540 hp standby:

The permittee shall submit an Initial Notification as required in 40 CFR 63.6645(f) for each new or
reconstructed emergency stationary RICE. [Origin: 40 CFR 63 Subpart ZZZZ]. [40 CFR 63.6590(b)(1)]

II.B.4.j.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.4.j.2 Recordkeeping:

The permittee shall keep a copy of each notification in accordance with 40 CFR 63.6660 and
Provision I.S.1 of this permit.

II.B.4.j.3 Reporting:

For each affected emission unit, the permittee shall submit an Initial Notification containing the
information in 40 CFR 63.9(b)(2)(i) through (v), and a statement that the stationary RICE has no
additional requirements and that explains the basis of the exclusion. There are no additional
reporting requirements for this provision except those specified in Section I of this permit.

Status: In Compliance – The Initial Notification regarding the 450 hp diesel generator, dated February 18,
2016, was received on February 22, 2016. See status of condition II.B.4.c.

II.B.4.k Condition:

The ETF portable diesel generator shall not be operated more than 1,100 hours per rolling 12-month
period without prior approval in accordance with R307-401. [Origin: DAQE-AN101230057-23].
[R307-401-8]

II.B.4.k.1 Monitoring:

To determine the duration of operation, the permittee shall install a non-resettable hour meter. To
demonstrate compliance with a rolling 12-month total, the permittee shall calculate a new 12-
month total by the 20th day of each month using data from the previous 12 months.

II.B.4.k.2 Recordkeeping: Records of the hours of operation shall be kept for all periods when the plant is in operation. The 12-month rolling totals shall be recorded monthly. Records and results of monitoring shall be maintained in accordance with Provision I.S.1 of this permit.
54

II.B.4.k.3 Reporting:

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

Status: In Compliance – The East Tank Farm (ETF) portable generator has a non-resettable hour meter.
The generator has operated for a total of 131.1 hours. The generator has operated for 5.4 hours in
2024, as of July 19, 2024.

II.B.5 Conditions on Flares (Unit 66) and Flare Gas Recovery.

II.B.5.a Condition:

The permittee shall install and operate a flare gas recovery system designed to limit hydrocarbon flaring
produced from each affected flare during normal operations to levels below the values listed in 40 CFR
60.103a(c). Flare gas recovery is not required for dedicated SRU flare and header systems, or HF flare
and header systems.
[Origin: DAQE-AN101230057-23, SIP Section IX.H.1.g.v.B, SIP Section IX.H.2.f.v, SIP Section
IX.H.11.g.v.B, SIP Section IX.H.12.g.vi]. [SIP Section IX.H.1.g.v.B, SIP Section IX.H.2.f.v, SIP Section
IX.H.11.g.v.B, SIP Section IX.H.12.g.vi]

II.B.5.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.5.a.2 Recordkeeping:

The permittee shall keep records that demonstrate installation and operation of the flare gas
recovery system is in compliance with the requirements in this condition. Any information used
to determine compliance shall be recorded for all periods when the source is in operation. Any or
all of these records shall be made available to the Director upon request, and shall include a
period of two years ending with the date of the request. Records shall be maintained in
accordance with Provision I.S.1 of this permit.

II.B.5.a.3 Reporting:

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

Status: In Compliance – The flares comply with Subpart Ja. The refinery has installed a flare gas recovery
unit (FGRU). The unit is designed to limit hydrocarbon flaring from both the North and South
Flares, during normal operations, to levels below the values listed in 40 CFR 60.103a (c). Subpart
Ja. The Notice of Completion (NOC) of the FGRU was submitted on August 11, 2017.

II.B.5.b Condition:

i. For each flare, the permittee shall develop and implement a written flare management plan in
accordance with 40 CFR 60.103a(a).
ii. For each flare, the permittee shall conduct a root cause analysis and a corrective action analysis for
each of the following conditions.
(a) Any time the SO2 emissions exceed 227 kilograms (kg) (500 lb) in any 24-hour period; or
55

(b) Any discharge to the flare in excess of 14,160 standard cubic meters (m3) (500,000 standard
cubic feet (scf)) above the baseline, determined in 40 CFR 60.103a(a)(4), in any 24-hour
period; or
(c) If the monitoring alternative in 40 CFR 60.107a(g) is elected, any period when the flare gas
line pressure exceeds the water seal liquid depth, except for periods attributable to compressor
staging that do not exceed the staging time specified in 40 CFR 60.103a(a)(3)(vii)(C).
iii. A root cause analysis and corrective action analysis shall be completed as soon as possible, but no
later than 45 days after a discharge meeting one of the conditions above. Special circumstances
affecting the number of root cause analyses and/or corrective action analyses are provided in 40
CFR 60.103a(d)(1) through (5).
iv. The permittee shall not burn in any affected flare any fuel gas that contains H2S in excess of 162
ppmv determined hourly on a 3-hour rolling average basis. The combustion in a flare of process
upset gases or fuel gas that is released to the flare as a result of relief valve leakage or other
emergency malfunctions is exempt from this limit.
[Origin: 40 CFR 60 Subpart Ja, SIP Section IX.H.1.g.v.A, SIP Section IX.H.11.g.v.A]. [40 CFR 60.103a]

II.B.5.b.1 Monitoring:

The permittee shall install, calibrate, maintain, and operate an instrument for continuously
monitoring and recording the concentration by volume (dry basis) of H2S in the fuel gases before
being burned in any flare in accordance with 40 CFR 60.107a(a)(2) and (3), 40 CFR 60.107a(i),
R307-170. Monitoring shall be performed in accordance with 40 CFR 60.107a(e), 40 CFR
60.107a(f), and 40 CFR 60.107a(g).

The permittee shall implement the corrective action(s) identified in the corrective action analysis
in accordance with 40 CFR 60.103a(e).

Performance testing shall be conducted in accordance with 40 CFR 60.104a(a), (c), and (j).

II.B.5.b.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.103a(e), 40
CFR 60.108a(c), R307-170, and Provision I.S.1 of this permit.

II.B.5.b.3 Reporting:

Reports shall be submitted quarterly in accordance with R307-170-9. The quarterly reports 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 in the report. There are no additional
reporting requirements for this provision except those specified in 40 CFR 60.103a(b), 40 CFR
60.107a(i), 40 CFR 60.108a(d), and Section I of this permit.

Status: In Compliance – The Flare Management Plan (FMP), dated September 2019, is in place regarding
the North and South flares. The plan is reviewed annually. FMP information is provided in the
Semi-annual Subpart Ja Periodic reports and also Quarterly CEMs reports. The latest Semi-annual
Subpart Ja Periodic report was received on August 5, 2024.

II.B.5.c Condition:

The permittee shall operate each flare with a pilot flame present on an individual burner or stage of
burners at all times when regulated material is routed to the flare. Each 15-minute block during which
there is at least one minute where no pilot flame on an individual burner or stage of burners is present
56

when regulated material is routed to the flare is a deviation of the standard. Deviations in different 15-
minute blocks from the same event are considered separate deviations. [Origin: 40 CFR 63 Subpart CC].
[40 CFR 63.640(s), 40 CFR 63.670(b)]

II.B.5.c.1 Monitoring:

The permittee shall continuously monitor for the presence of a pilot flame as specified in 40 CFR
63.670(g). The permittee shall install, operate, calibrate, and maintain the CPMS as specified in
40 CFR 63.671.

II.B.5.c.2 Recordkeeping:

Records shall be maintained in accordance with 40 CFR 63.655(i)(9) and Provision I.S.1 of this
permit.

II.B.5.c.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 63.655(g)(11). There are no additional
reporting requirements for this provision except those specified in Section I of this permit.

Status: In Compliance – The control room monitors the flares in real time. CPMs or two sets of IR cameras
also monitor the flares 24/7. This information is provided in the Semi-annual MACT Subparts CC,
UUU, ZZZZ, and DDDD Periodic reports. The latest report was received on August 5, 2024.

II.B.5.d Condition:

The permittee shall specify the smokeless design capacity of each flare and operate with no visible
emissions, except for periods not to exceed a total of 5 minutes during any 2 consecutive hours, when
regulated material is routed to the flare and the flare vent gas flow rate is less than the smokeless design
capacity of the flare. [Origin: 40 CFR 63 Subpart CC]. [40 CFR 63.640(s), 40 CFR 63.670(c)]

II.B.5.d.1 Monitoring:

The permittee shall conduct visible emissions monitoring as specified in 40 CFR 63.670(h). The
permittee shall install, operate, calibrate, and maintain the CPMS as specified in 40 CFR 63.671,
as applicable.

II.B.5.d.2 Recordkeeping:

Records shall be maintained in accordance with 40 CFR 63.670(h), 40 CFR 63.655(i)(9), and
Provision I.S.1 of this permit.

II.B.5.d.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 63.670(h) and 40 CFR 63.655(g)(11).
There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In Compliance – See status of condition II.B.5.c.

II.B.5.e Condition:

57

i. For each flare, the permittee shall comply with the flare tip velocity requirements specified in 40 CFR
63.670(d), whenever regulated material is routed to the flare for at least 15-minutes and the flare vent
gas flow rate is less than the smokeless design capacity of the flare.
ii. The permittee shall operate each flare to maintain the net heating value of flare combustion zone gas
(NHVcz) at or above 270 British thermal units per standard cubic feet (Btu/scf) determined on a 15-
minute block period basis when regulated material is routed to the flare for at least 15-minutes.
[Origin: 40 CFR 63 Subpart CC]. [40 CFR 63.640(s), 40 CFR 63.670(d), 40 CFR 63.670(e)]

II.B.5.e.1 Monitoring:

The permittee shall monitor flare tip velocity using the procedures specified in 40 CFR 63.670(i)
and (k). The permittee shall monitor gas composition and determine net heating value of flare
vent gas, if applicable, using the procedures specified in 40 CFR 63.670(j) and (l). The permittee
shall monitor and calculate the net heating value of the combustion zone gas (NHVcz) as specified
in 40 CFR 63.670(m)(1) or (2), as applicable. The permittee shall install, operate, calibrate, and
maintain the CPMS as specified in 40 CFR 63.671.

II.B.5.e.2 Recordkeeping:

Records shall be maintained in accordance with 40 CFR 63.655(i)(9) and Provision I.S.1 of this
permit.

II.B.5.e.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 63.655(g)(11). There are no additional
reporting requirements for this provision except those specified in Section I of this permit.

Status: In Compliance – See status of condition II.B.5.c.

II.B.5.f Condition:

The permittee shall comply with the following provisions for each flare that has the potential to operate
above its smokeless capacity under any circumstance.
i. Develop a flare management plan to minimize flaring during periods of startup, shutdown, or
emergency releases in accordance with 40 CFR 63.670(o)(1). The plan shall be developed,
implemented, and updated periodically as specified in 40 CFR 63.670(o)(2).
ii. Conduct a root cause analysis and a corrective action analysis in accordance with 40 CFR
63.670(o)(3) and (4) for each flow event that contains regulated material and that meets either of the
following criteria.
(a) The vent gas flow rate exceeds the smokeless capacity of the flare based on a 15-minute block
average and visible emissions are present from the flare for more than 5 minutes during any 2
consecutive hours during the release event.
(b) The vent gas flow rate exceeds the smokeless capacity of the flare and the 15-minute block
average flare tip velocity exceeds the maximum flare tip velocity determined using the methods
in 40 CFR 60.670(d)(2).
iii. If required to conduct a root cause analysis and corrective action analysis as specified in 40 CFR
63.670(o)(3) and (4), the permittee shall implement the corrective action(s) identified in the corrective
action analysis in accordance with the applicable requirements in 40 CFR 63.670(o)(5).
iv. The permittee shall determine the total number of events for which a root cause and corrective action
analyses was required during the calendar year for each affected flare in accordance with 40 CFR
63.670(o)(6).
v. The events described in 40 CFR 63.670(o)(7) shall be a violation of this emergency flaring work
58

practice standard.
[Origin: 40 CFR 63 Subpart CC]. [40 CFR 63.640(s), 40 CFR 63.670(o)]

II.B.5.f.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.5.f.2 Recordkeeping:

The permittee shall keep records that demonstrate compliance with this provision. Records shall
be maintained in accordance with 40 CFR 63.670(o)(5), 40 CFR 63.655(i)(9), and Provision I.S.1
of this permit.

II.B.5.f.3 Reporting:

The permittee shall submit the flare management plan in accordance with 40 CFR 63.670(o)(2).
Reports shall be submitted in accordance with 40 CFR 63.655(g)(11). There are no additional
reporting requirements for this provision except those specified in Section I of this permit.

Status: In Compliance – The latest Semi-annual Subpart Ja Periodic report and Semi-annual MACT
Subparts CC, UUU, ZZZZ, and DDDD Periodic report were received on August 5, 2024. See status
of condition II.B.5.b.

II.B.6 Conditions on Storage Tanks (Unit 68).

II.B.6.a Condition:

A Group 1 storage vessel storing liquid with a maximum true vapor pressure less than 76.6 kilopascals
(11.1 pounds per square inch) that is part of a new or existing source shall comply with the requirements
in 40 CFR 63 subpart WW as specified in 40 CFR 63.660(a) through (i).
i. A floating roof storage vessel complying with the requirements of 40 CFR 63 subpart WW may
comply with the control option specified in paragraph 40 CFR 63.660(b)(1) and, if equipped with a
ladder having at least one slotted leg, shall comply with one of the control options as described in 40
CFR 63.660(b)(2), as applicable. If the floating roof storage vessel does not meet the requirements of
40 CFR 63.1063(a)(2)(i) through (a)(2)(viii) as of June 30, 2014, these requirements do not apply
until the next time the vessel is completely emptied and degassed, or January 30, 2026, whichever
occurs first. [40 CFR 63.660(b)]
ii. For an uncontrolled fixed roof storage vessel that commenced construction on or before June 30,
2014, and that meets the definition of “Group 1 storage vessel”, paragraph (2), in 40 CFR 63.641 but
not the definition of “Group 1 storage vessel”, paragraph (1), in 40 CFR 63.641, the requirements of
40 CFR 63.1062 do not apply until the next time the storage vessel is completely emptied and
degassed, or January 30, 2026, whichever occurs first. [40 CFR 63.660(d)]
iii. The permittee shall comply with one of the requirements listed in 40 CFR 63.1062(a).
iv. The permittee who elects to use a floating roof to comply with the requirements of 40 CFR 63.1062
shall comply with the requirements in 40 CFR 63.1063(a) through (e).
[Origin: 40 CFR 63 Subpart CC, 40 CFR 63 Subpart WW]. [40 CFR 63.660, 40 CFR 63.1062, 40 CFR
63.1063]

59

II.B.6.a.1 Monitoring:

Monitoring shall be performed in accordance with 40 CFR 63.660(e). Inspections shall be
conducted as specified in 40 CFR 63.1063(c) and (d). Conditions causing inspection failures
under 40 CFR 63.1063(d) shall be repaired as specified in 40 CFR 63.1063(e).

II.B.6.a.2 Recordkeeping:

Records shall be maintained in accordance with 40 CFR 63.1065 and Provision I.S.1 of this
permit.

II.B.6.a.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 63.655(g), (h), and 40 CFR 63.660(h).
There are no additional reporting requirements for this provision except those specified in Section
I of this permit.

Status: In Compliance – There are a total of 27 Group I storage vessels on-site. A 30-day notice is provided
for Semi-annual and Annual inspections. If any repairs are required, based on the tank inspections,
they are included in the Semi-annual MACT Subparts CC, UUU, ZZZZ, and DDDD Periodic
reports. The latest report was received on August 5, 2024.

II.B.6.b Condition:

For tank 323:
i. For each storage vessel either with a design capacity greater than or equal to 151 m3 containing a
VOL that, as stored, has a maximum true vapor pressure equal to or greater than 5.2 kPa but less than
76.6 kPa or with a design capacity greater than or equal to 75 m3 but less than 151 m3 containing a
VOL that, as stored, has a maximum true vapor pressure equal to or greater than 27.6 kPa but less
than 76.6 kPa, the permittee shall equip each storage vessel with one of the following:
(a) A fixed roof in combination with an internal floating roof meeting the specifications in 40 CFR
60.112b(a)(1).
(b) An external floating roof meeting the specifications in 40 CFR 60.112b(a)(2).
(c) A closed vent system and control device meeting the specifications in 40 CFR 60.112b(a)(3).
(d) An equivalent system in accordance with 40 CFR 60.112b(a)(4) and 40 CFR 60.114b.
ii. For each storage vessel with a design capacity greater than or equal to 75 m3 which contains a VOL
that, as stored, has a maximum true vapor pressure greater than or equal to 76.6 kPa, the permittee
shall equip each storage vessel with one of the following:
(a) A closed vent system and control device as specified in 40 CFR 60.112b(a)(3).
(b) A system equivalent to that described in paragraph (ii)(a) as provided in 40 CFR 60.114b.
[Origin: 40 CFR 60 Subpart Kb]. [40 CFR 60.112b]

II.B.6.b.1 Monitoring:

Depending on the control equipment installed to meet the requirements of 40 CFR 60.112b, the
permittee shall meet the requirements of 40 CFR 60.113b, as applicable. Monitoring shall be
performed in accordance with 40 CFR 60.116b. Records required for this permit condition will
also serve as monitoring.

II.B.6.b.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.115b and
60

Provision I.S.1 of this permit.

II.B.6.b.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.113b and 40 CFR 60.115b. There are
no additional reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance – Ethanol is railed to the refinery and stored in Tank # 323. Tank true vapor
pressure, daily storage temperature, and throughput are monitored and recorded in a material
tracking spreadsheet. A 30-day notice is provided for Semi-annual and Annual inspections. If any
repairs are required, based on the tank inspections, they are included in the Semi-annual MACT
Subparts CC, UUU, ZZZZ, and DDDD Periodic reports. The latest report was received on
August 5, 2024.

II.B.6.c Condition:

i. For tanks 11, 12, 14, 15, 19, 20, 23, 24, 28, 31, 35, 37, 47, 48, 52-59, 61, 63, 65, 70-79, 86, 90, 92, 99-
109, 126-129, 131-135, 138-141, 143, 145, 146, 159, 170-172, 323:
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 kilopascals (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 director.
ii. For petroleum liquid storage tanks not subject to R307-327-4(1), but containing a petroleum liquid
with a true vapor pressure greater than 7.0 kPa (1.0 psia), the permittee shall maintain records of the
average monthly storage temperature, the type of liquid, throughput quantities, and the maximum true
vapor pressure.
iii. The permittee shall comply with the retrofit requirements for floating roof tanks in R307-327-6, as
applicable.
[Origin: R307-327]. [R307-327-4, R307-327-6]

II.B.6.c.1 Monitoring:

The permittee shall ensure that all control equipment on storage vessels is properly installed and
maintained in accordance with R307-327-5(1). Inspections shall be conducted as specified in
R307-327-5(2)-(4).

II.B.6.c.2 Recordkeeping:

Results of monitoring and records demonstrating compliance with this condition shall be
maintained in accordance with R307-327-4(1) and (2), R307-327-6(2)(c), and Provision I.S.1 of
this permit.

61

II.B.6.c.3 Reporting:

The permittee shall notify the director seven 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 R307-327 shall be corrected before the tank is refilled. [R307-327-5(5)] There
are no additional reporting requirements for this provision except those specified in Section I of
this permit.

Status: In Compliance – This condition includes Group I and II storage vessels, also tanks that are
considered to be non-applicable. Tank true vapor pressure, storage temperature, type of liquid, and
throughput are monitored and recorded in a material tracking spreadsheet. A 30-day notice is
provided for Semi-annual and Annual inspections. If any repairs are required, based on the tank
inspections, they are included in the Semi-annual MACT Subparts CC, UUU, ZZZZ, and DDDD
Periodic reports. The latest report was received on August 5, 2024. Three-day tank degassing and
seven-day tank refilling notices are submitted. Finally, a Clarification of Applicability Letter, dated
May 17, 2024, was sent to the DAQ regarding tank #129. See attached email.

II.B.6.d Condition: State-only Requirement

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 Section IX.H.11.g.vi].
[SIP Section IX.H.11.g.vi]

II.B.6.d.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.6.d.2 Recordkeeping:

For each degassing event the permittee shall keep records that document compliance with the
requirements of this condition prior to allowing the tank to be opened to the atmosphere. Records
shall be maintained in accordance with SIP Section IX.H.11.c and Provision I.S.1 of this permit.

II.B.6.d.3 Reporting:

The Director shall be notified of the intent to degas any tank subject to this condition. Except in
an emergency situation, initial notification shall be submitted at least three (3) days prior to
degassing operations. The initial notification shall include:
i. Start date and time;
ii. Tank owner, address, tank location, and applicable tank permit numbers;
iii. Degassing operator s name, contact person, telephone number;
iv. Tank capacity, volume of space to be degassed, and materials stored;
v. Description of vapor control device.
(SIP Section IX.H.11.g.vi.C)

There are no additional reporting requirements for this provision except those specified in SIP
Section IX.H.11.c and Section I of this permit.

62

Status: In Compliance – HCPSC Industrial Outsourcing, LP conducts the tank degassing operations
(Portable Thermal Oxidizer) and provides the reports to HF Sinclair. The reports are entered into
the Tank Degassing Log.

II.B.7 Conditions on NESHAP CC Equipment.

II.B.7.a Condition:

The permittee shall comply with the applicable fenceline monitoring provisions of 40 CFR 63.658.
[Origin: 40 CFR 63 Subpart CC]. [40 CFR 63.640(h), 40 CFR 63.658, 40 CFR 63 Subpart CC Table
11(4)(vi)]

II.B.7.a.1 Monitoring:

The permittee shall conduct sampling along the facility property boundary and analyze the
samples in accordance with the applicable requirements of 40 CFR 63.658.

II.B.7.a.2 Recordkeeping:

Records shall be maintained in accordance with 40 CFR 63.655(i)(8) and Provision I.S.1 of this
permit.

II.B.7.a.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 63.655(h)(8) and 40 CFR 63.658(h). There
are no additional reporting requirements for this provision except those specified in Section I of
this permit.

Status: In Compliance – Tubes with absorbent (Passive Monitoring) are attached to the refinery’s fence
line for two weeks. The tubes are then sent to the lab for analysis. According to the database the
Benzene limit of 9 ug/m3 has never been exceeded.

II.B.7.b Condition:

At all times, the permittee shall operate and maintain any affected source subject to 40 CFR 63 Subpart
CC, including associated air pollution control equipment and monitoring equipment, in a manner
consistent with safety and good air pollution control practices for minimizing emissions. The general duty
to minimize emissions does not require the permittee to make any further efforts to reduce emissions if
levels required by the applicable standard have been achieved. Determination of whether a source is
operating in compliance with operation and maintenance requirements will be based on information
available to the Director which may include, but is not limited to, monitoring results, review of operation
and maintenance procedures, review of operation and maintenance records, and inspection of the source.
[Origin: 40 CFR 63 Subpart CC]. [40 CFR 63.642(n)]

II.B.7.b.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.7.b.2 Recordkeeping: The permittee shall document activities performed to assure proper operation and maintenance. Records shall be maintained in accordance with 40 CFR 63.655(i) and Provision I.S.1 of this permit.
63

II.B.7.b.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 63.655(e)-(h). There are no additional
reporting requirements for this provision except those specified in Section I of this permit.

Status: In Compliance – The information in this condition is included in Quarterly CEMs reports and
included in the Semi-annual MACT Subparts CC, UUU, ZZZZ, and DDDD Periodic reports. The
latest report was received on August 5, 2024.

II.B.7.c Condition:

For Group 1 miscellaneous process vents, the permittee shall comply with the requirements of either 40
CFR 63.643(a)(1) or (2). [Origin: 40 CFR 63 Subpart CC]. [40 CFR 63.643(a)]

II.B.7.c.1 Monitoring:

The permittee shall comply with the applicable monitoring provisions for miscellaneous process
vents contained in 40 CFR 63.644 using the test methods and procedures specified in 40 CFR
63.645.

II.B.7.c.2 Recordkeeping:

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

II.B.7.c.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 63.655(e)-(h). There are no additional
reporting requirements for this provision except those specified in Section I of this permit.

Status: In Compliance – Miscellaneous process vent information is included in the Semi-annual MACT
Subparts CC, UUU, ZZZZ, and DDDD Periodic reports. The latest report was received on
August 5, 2024.

II.B.7.d Condition:

For process vents designated as maintenance vents, the permittee shall comply with the applicable
requirements of 40 CFR 63.643(c) for each maintenance vent. [Origin: 40 CFR 63 Subpart CC]. [40 CFR
63.643(a), 40 CFR 63.643(c)]

II.B.7.d.1 Monitoring:

The permittee shall comply with the applicable requirements in 40 CFR 63.643(c) for each
maintenance vent.

II.B.7.d.2 Recordkeeping:

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

II.B.7.d.3 Reporting:

64

Reports shall be submitted in accordance with 40 CFR 63.655(g)(13). There are no additional
reporting requirements for this provision except those specified in Section I of this permit.

Status: In Compliance – Maintenance venting is conducted on any equipment during turnarounds, except
storage tanks. Maintenance Vent Forms are completed when equipment is vented. The forms are
electronically and hard copy filled. If the limits are not met during equipment venting the data is
provided in the Semi-annual MACT Subparts CC, UUU, ZZZZ, and DDDD Periodic reports. The
latest report was received on August 5, 2024.

II.B.8 Conditions on Boiler NESHAP Combustion Units.

II.B.8.a Condition:

For 4H1, 6H1, 6H2, 6H3, 7H3, 8H2, 10H1, 11H1, 12H1, 19H1, 20H2, 20H3, 24H1, 25H1, Boiler #4, #5,
#8, #9, #10, and 11:
The permittee shall conduct a tune-up of each affected emission unit as specified in 40 CFR 63.7540.
[Origin: 40 CFR 63 Subpart DDDDD]. [40 CFR 63.7500(a), 40 CFR 63 Subpart DDDDD Table 3]

II.B.8.a.1 Monitoring:

The permittee shall demonstrate initial compliance for existing affected sources and new or
reconstructed affected sources as required in 40 CFR 63.7510(e) and (g). The permittee shall
demonstrate continuous compliance as specified in 40 CFR 63.7540(a)(10).

To demonstrate continuous compliance the permittee shall conduct an annual tune-up of each
affected emission unit as specified in 40 CFR 63.7515(d) and 40 CFR 63.7540(a)(10)(i)-(vi).
Each annual tune-up shall be conducted no more than 13 months after the previous tune-up. If
the unit is not operating on the required date for a tune-up, the tune-up shall be conducted within
30 calendar days of startup.
[40 CFR 63.7515(d), 40 CFR 63.7540(a)(10), 40 CFR 63.7540(a)(13)]

II.B.8.a.2 Recordkeeping:

Records shall be kept as specified in 40 CFR 63.7555(a) and (h), as applicable. Records shall be
maintained in accordance with 40 CFR 63.7560 and Provision I.S.1 of this permit.

II.B.8.a.3 Reporting:

In addition to the reporting requirements of Section I of this permit, the permittee shall comply
with the applicable notification and reporting requirements specified in 40 CFR 63.7495(d), 40
CFR 63.7540(a)(10)(vi), 40 CFR 63.7545(a), (c), (e), (f), (h), and 40 CFR 63.7550(a)-(c), (h).

Status: In Compliance – The above heater/boilers and their tune-up status are maintained on the Tune-up
Check List Spreadsheet. Boiler tune-ups are performed in-house. The tune-ups comply with EPA
tune-up procedures. Notice of Compliance (NOC) are submitted when new heater/boilers are
acquired. Heater/boiler tune-up information is included in the Semi-annual MACT Subparts CC,
UUU, ZZZZ, and DDDD Periodic reports. The latest report was received on August 5, 2024.

II.B.8.b Condition:

For 9H1, 13H1:
The permittee shall conduct a tune-up of each affected emission unit as specified in 40 CFR 63.7540.
65

[Origin: 40 CFR 63 Subpart DDDDD]. [40 CFR 63.7500(a), 40 CFR 63.7500(e), 40 CFR 63 Subpart
DDDDD Table 3]

II.B.8.b.1 Monitoring:

The permittee shall demonstrate continuous compliance as specified in 40 CFR 63.7540(a)(11).

To demonstrate continuous compliance the permittee shall conduct a biennial tune-up of each
affected emission unit as specified in 40 CFR 63.7515(d) and 40 CFR 63.7540(a)(10)(i)-(vi).
Each biennial tune-up shall be conducted no more than 25 months after the previous tune-up. If
the unit is not operating on the required date for a tune-up, the tune-up shall be conducted within
30 calendar days of startup.
[40 CFR 63.7515(d), 40 CFR 63.7540(a)(11), 40 CFR 63.7540(a)(13)]

II.B.8.b.2 Recordkeeping:

Records shall be kept as specified in 40 CFR 63.7555(a) and (h), as applicable. Records shall be
maintained in accordance with 40 CFR 63.7560 and Provision I.S.1 of this permit.

II.B.8.b.3 Reporting:

In addition to the reporting requirements of Section I of this permit, the permittee shall comply
with the applicable notification and reporting requirements specified in 40 CFR 63.7495(d), 40
CFR 63.7540(a)(10)(vi), 40 CFR 63.7545(f), (h), and 40 CFR 63.7550(a)-(c), (h).

Status: In Compliance – Tune-ups are still conducted annually for the above-mentioned units (9H1 and
13H1). See status of condition II.B.8.a.

II.B.8.c Condition:

For 7H1, 9H2, 68H2, 68H3:
The permittee shall conduct a tune-up of each affected emission unit as specified in 40 CFR 63.7540.
[Origin: 40 CFR 63 Subpart DDDDD]. [40 CFR 63.7500(a), 40 CFR 63.7500(e), 40 CFR 63 Subpart
DDDDD Table 3]

II.B.8.c.1 Monitoring:

The permittee shall demonstrate continuous compliance as specified in 40 CFR 63.7540(a)(12).

To demonstrate continuous compliance the permittee shall conduct a tune-up of each affected
emission unit every 5 years as specified in 40 CFR 63.7540(a)(10)(i)-(vi). Each 5-year tune-up
shall be conducted no more than 61 months after the previous tune-up. Burner inspection may be
delayed until the next scheduled or unscheduled unit shutdown but the permittee shall inspect
each burner at least once every 72 months. If an oxygen trim system is utilized, the permittee
shall set the oxygen level no lower than the oxygen concentration measured during the most
recent tune-up. If the unit is not operating on the required date for a tune-up, the tune-up shall be
conducted within 30 calendar days of startup.
[40 CFR 63.7515(d), 40 CFR 63.7540(a)(12), 40 CFR 63.7540(a)(13)]

II.B.8.c.2 Recordkeeping:

Records shall be kept as specified in 40 CFR 63.7555(a) and (h), as applicable. Records shall be
66

maintained in accordance with 40 CFR 63.7560 and Provision I.S.1 of this permit.

II.B.8.c.3 Reporting:

In addition to the reporting requirements of Section I of this permit, the permittee shall comply
with the applicable notification and reporting requirements specified in 40 CFR 63.7495(d), 40
CFR 63.7540(a)(10)(vi), 40 CFR 63.7545(f), (h), and 40 CFR 63.7550(a)-(c), (h).

Status: In Compliance – Tune-ups are still conducted annually for the above-mentioned units (7H1, 9H2,
68H2, and 68H3). See status of condition II.B.8.a.

II.B.8.d Condition:

At all times, the permittee shall operate and maintain each affected emission unit, including associated air
pollution control equipment and monitoring equipment, in a manner consistent with safety and good air
pollution control practices for minimizing emissions. Determination of whether such operation and
maintenance procedures are being used will be based on information available to the Director that may
include, but is not limited to, monitoring results, review of operation and maintenance procedures, review
of operation and maintenance records, and inspection of the source. [Origin: 40 CFR 63 Subpart
DDDDD]. [40 CFR 63.7500(a)(3)]

II.B.8.d.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.8.d.2 Recordkeeping:

The permittee shall document activities performed to assure proper operation and maintenance.
Maintenance performed on each affected emission unit shall be recorded. Records shall be
maintained in accordance with 40 CFR 63.7560 and Provision I.S.1 of this permit.

II.B.8.d.3 Reporting:

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

Status: In Compliance – Heater/boiler maintenance is tracked by the SAP Work Order System.

II.B.9 Conditions on NESHAP UUU Equipment.

II.B.9.a Condition:

i. At all times, the permittee shall be in compliance with all of the non-opacity standards and the opacity
and visible emission limits in 40 CFR 63 Subpart UUU.
ii. At all times, the permittee shall operate and maintain any affected source, including associated air
pollution control equipment and monitoring equipment, in a manner consistent with safety and good
air pollution control practices for minimizing emissions. The general duty to minimize emissions does
not require the permittee to make any further efforts to reduce emissions if levels required by the
applicable standard have been achieved. Determination of whether a source is operating in compliance
with operation and maintenance requirements will be based on information available to the Director
which may include, but is not limited to, monitoring results, review of operation and maintenance
procedures, review of operation and maintenance records, and inspection of the source.
67

[Origin: 40 CFR 63 Subpart UUU]. [40 CFR 63.1570]

II.B.9.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.9.a.2 Recordkeeping:

The permittee shall document activities performed to assure proper operation and maintenance.
The permittee shall record actions taken to minimize emissions and any corrective actions taken
to return the affected unit to its normal or usual manner of operation. Records shall be
maintained in accordance with 40 CFR 63.1576 and Provision I.S.1 of this permit.

II.B.9.a.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 63.1570(f) and 40 CFR 63.1575. There
are no additional reporting requirements for this provision except those specified in Section I of
this permit.

Status: In Compliance – Subpart UUU equipment operation and maintenance activities are documented in
the Operation Maintenance and Monitoring Plan (OMMP), dated September 8, 2022. The plan is
reviewed every 3 years or on an as needed basis. This information is included in the Quarterly
CEMs and Semi-annual MACT Subparts CC, UUU, ZZZZ, and DDDD Periodic reports. The latest
MACT report was received on August 5, 2024. See status of condition II.B.3.b and attached email.

II.B.9.b Condition:

For each affected emission unit, the permittee shall prepare and implement an operation, maintenance,
and monitoring plan according to the requirements in 40 CFR 63.1574(f) and operate at all times
according to the procedures in the plan. [Origin: 40 CFR 63 Subpart UUU]. [40 CFR 63.1564(a)(3), 40
CFR 63.1565(a)(3), 40 CFR 63.1566(a)(5), 40 CFR 63.1567(a)(3), 40 CFR 63.1568(a)(3), 40 CFR
63.1569(a)(3), 40 CFR 63.1574(f)]

II.B.9.b.1 Monitoring:

The permittee shall demonstrate continuous compliance with the work practice standard by
complying with the procedures in the operation, maintenance, and monitoring plan. Records
required for this permit condition will also serve as monitoring.

II.B.9.b.2 Recordkeeping:

The permittee shall demonstrate continuous compliance by maintaining records to document
conformance with the procedures in the operation, maintenance, and monitoring plan. [40 CFR
63.1564(c)(2), 40 CFR 63.1565(c)(2), 40 CFR 63.1566(c)(2), 40 CFR 63.1567(c)(2), 40 CFR
63.1568(c)(2), 40 CFR 63.1569(c)(2)] The permittee shall keep a current copy of the operation,
maintenance, and monitoring plan onsite and available for inspection.

Records shall be maintained in accordance with 40 CFR 63.1576 and Provision I.S.1 of this
permit.

II.B.9.b.3 Reporting:

68

The permittee shall submit the plan and any changes to the plan to the Director for review and
approval in accordance with 40 CFR 63.1574(f). The permittee shall comply with the applicable
notification and reporting requirements specified in 40 CFR 63.1574 and 40 CFR 63.1575. There
are no additional reporting requirements for this provision except those specified in Section I of
this permit.

Status: In Compliance – See status of conditions II.B.3.b and II.B.9.a.

II.B.9.c Condition:

i. The permittee shall meet the following emission limitations for metal HAP emissions from catalytic
cracking units. The permittee shall meet the emission limitations for PM in 40 CFR 60.102 (FCC Unit
4) and 40 CFR 60.102a(b)(1) (FCC Unit 25).
(a) From FCC Unit 4: PM emissions shall not exceed 1.0 gram per kilogram (g/kg) (1.0 lb/1,000 lb)
of coke burn-off, and the opacity of emissions shall not exceed 20 percent in accordance with 40
CFR 63 Subpart UUU Table 1(1) and DAQE-AN101230057-23.
(b) From FCC Unit 25: PM emissions shall not exceed 0.5 g/kg coke burn-off (0.5 lb/1,000 lb coke
burn-off) in accordance with 40 CFR 63 Subpart UUU Table 1(3).
ii. The permittee shall comply with each of the following operating limits in accordance with 40 CFR
63.1564(a)(2).
(a) FCC Unit 25: For continuous parameter monitoring systems for a wet scrubber, the permittee
shall:
1) Maintain the 3-hour rolling average liquid-to-gas ratio above the limit established in the
performance test.
2) Except for periods of startup, shutdown, and hot standby, maintain the 3-hour rolling average
pressure drop above the limit established in the performance test.
(40 CFR 63 Subpart UUU Table 2(2)(d) via Table 2(3))
(b) FCC Unit 4 and 25: During periods of startup, shutdown, or hot standby, the permittee shall meet
the requirements in 40 CFR 63.1564(a)(5). (40 CFR 63 Subpart UUU Table 2(10))
[Origin: 40 CFR 63 Subpart UUU, DAQE-AN101230057-23]. [40 CFR 63.1564(a)(1), 40 CFR
63.1564(a)(2), R307-401-8]

II.B.9.c.1 Monitoring:

The permittee shall demonstrate compliance according to the following requirements.
i. For FCCU 4:
(a) The permittee shall monitor as specified in the most recent EPA-approved alternative
monitoring plan.
(b) The permittee shall conduct a performance test at least once every five years, or annually
if required by 40 CFR 63.1571(a)(5)(ii), for each catalytic cracking unit according to the
requirements in 40 CFR 63.1571 and under the conditions specified in Table 4 of 40
CFR 63 Subpart UUU. (40 CFR 63.1564(b), 40 CFR 63.1571(a)(5), 40 CFR 63 Subpart
UUU Table 4(2))
(c) The permittee shall demonstrate continuous compliance as follows.
1) Determine and record each day the average coke burn-off rate (thousands of
kilograms per hour) using Equation 1 in 40 CFR 63.1564 and the hours of operation
for each catalyst regenerator.
2) Conduct a performance test following the testing frequency in 40 CFR 63.1571(a)(5)
as applicable.
3) Monitor as specified in the most recent EPA-approved alternative monitoring plan.
(40 CFR 63.1564(c), 40 CFR 63 Subpart UUU Table 6(1))
ii. For FCCU 25:
(a) In accordance with the requirements in 40 CFR 63.1564(b), 40 CFR 63.1572(c), 40 CFR
69

63 Subpart UUU Table 3(2)(c) via Table 3(4) and Table 41, the permittee shall install,
operate, and maintain a continuous parameter monitoring system (CPMS) to measure
and record the pressure drop across the scrubber, the gas flow rate entering or exiting the
control device, and total liquid (or scrubbing liquor) flow rate to the control device.
(b) The permittee shall conduct a performance test for each catalytic cracking unit according
to the requirements in 40 CFR 63.1571 and under the conditions specified in Table 4 of
40 CFR 63 Subpart UUU. (40 CFR 63.1564(b), 40 CFR 63.1571(a)(5), 40 CFR 63
Subpart UUU Table 4(4))
(c) The permittee shall demonstrate continuous compliance as follows.
1) Determine and record each day the average coke burn-off rate (thousands of
kilograms per hour) using Equation 1 in 40 CFR 63.1564 and the hours of operation
for each catalyst regenerator.
2) Maintain PM emission rate below 0.5 g/kg (0.5 lb/1,000 lb) of coke burn-off.
3) Conduct a performance test once every year.
4) Collect the hourly and 3-hr rolling average gas flow rate and scrubber liquid flow
rate monitoring data according to 40 CFR 63.1572.
5) Determine and record the 3-hr liquid-to-gas ratio.
6) Maintain the 3-hr rolling average liquid-to-gas ratio at or above the limit established
during the performance test.
7) Collect the hourly and 3-hr rolling average pressure drop monitoring data according
to 40 CFR 63.1572.
8) Except for periods of startup, shutdown and hot standby, maintain the 3-hr rolling
average pressure drop at or above the limit established during the performance test.
(40 CFR 63.1564(c), 40 CFR 63 Subpart UUU Table 6(3), 40 CFR 63 Subpart UUU
Table 7(2)(c))
iii. For FCCU 4 and FCCU 25:
(a) The permittee shall monitor and collect data according to the requirements in 40 CFR
63.1572(d).
(b) Performance tests shall be conducted according to the requirements of 40 CFR
63.1571(a) and (b), and 40 CFR 63 Subpart UUU Table 4(1).
(c) The permittee shall establish each applicable site-specific operating limit in 40 CFR 63
Subpart UUU Table 2 according to the procedures in 40 CFR 63 Subpart UUU Table 4.

II.B.9.c.2 Recordkeeping:

Records shall be maintained in accordance with 40 CFR 63.1576, the most recent EPA-approved
alternative monitoring plan, and Provision I.S.1 of this permit.

II.B.9.c.3 Reporting:

The permittee shall comply with the applicable notification and reporting requirements specified
in 40 CFR 63.1574, 40 CFR 63.1575, and the most recent EPA-approved alternative monitoring
plan. There are no additional reporting requirements for this provision except those specified in
Section I of this permit.

Status: In Compliance – Results of the last stack tests were received, by the DAQ, on October 11, 2023.
Stack testing of the FCC Unit #4 was conducted on September 6, 2023. Stack testing of the FCC
Unit #25 was conducted on August 22 – 23, 2023. Stack Testing of the FCC Unit #4 is currently
conducted triennially and stack testing of FCC Unit #25 is currently performed annually. This is
because the request for Reduced Frequency Testing was approved. The stack testing sets the
parameters for the Unit #4 and Unit #25 CPMS. See Status of condition II.B.2.a.

70

II.B.9.d Condition:

The permittee shall meet the following emission limitation for organic HAP emissions from catalytic
cracking units. The permittee shall meet the emission limitation for CO in 40 CFR 60.103(a) (FCC Unit
4) and 40 CFR 60.102a(b)(4) (FCC Unit 25).
i. CO emissions from the catalyst regenerator vent or CO boiler serving the catalytic cracking unit shall
not exceed 500 parts per million volume (ppmv) (dry basis).
ii. During periods of startup, shutdown, or hot standby, the permittee shall comply with the requirements
in 40 CFR 63.1565(a)(5).
[Origin: 40 CFR 63 Subpart UUU]. [40 CFR 63.1565(a)(1), 40 CFR 63.1565(a)(5), 40 CFR 63 Subpart
UUU Table 8(1)]

II.B.9.d.1 Monitoring:

The permittee shall demonstrate compliance according to the following requirements.
i. The permittee shall install, operate, and maintain a continuous emission monitoring system
(CEMS) to measure and record the concentration by volume (dry basis) of CO emissions from
each catalyst regenerator vent according to the requirements in 40 CFR 63.1565(b), 40 CFR
63.1572(a), 40 CFR 63 Subpart UUU Table 10(1), and Table 40(3).
ii. If complying with the operating limit in 40 CFR 63.1565(a)(5)(ii) during periods of startup,
shutdown or hot standby, the permittee shall install, operate, and maintain a continuous
parameter monitoring system to measure and record the concentration by volume (wet or dry
basis) of oxygen from each catalyst regenerator vent. If measurement is made on a wet basis,
the permittee shall comply with the limit as measured (no moisture correction). (40 CFR 63
Subpart UUU Table 10(3))
iii. The permittee shall demonstrate continuous compliance as follows.
(a) Collect the hourly average CO monitoring data according to 40 CFR 63.1572 and
maintain the hourly average CO concentration at or below 500 ppmv (dry basis).
(b) If complying with the operating limit in 40 CFR 63.1565(a)(5)(ii) during periods of
startup, shutdown or hot standby, the permittee shall collect the hourly average oxygen
concentration monitoring data according to 40 CFR 63.1572 and maintain the hourly
average oxygen concentration at or above 1 volume percent (dry basis).
(40 CFR 63.1565(c), 40 CFR 63 Subpart UUU Table 13(1), 40 CFR 63 Subpart UUU Table
14(3)
iv. The permittee shall monitor and collect data according to the requirements in 40 CFR
63.1572(d).

II.B.9.d.2 Recordkeeping:

Records shall be maintained in accordance with 40 CFR 63.1576 and Provision I.S.1 of this
permit.

II.B.9.d.3 Reporting:

The permittee shall comply with the applicable notification and reporting requirements specified
in 40 CFR 63.1574 and 40 CFR 63.1575. There are no additional reporting requirements for this
provision except those specified in Section I of this permit.

Status: In Compliance – The DAQ CEM Specialist determines compliance with HF Sinclair’s CEMs
monitoring systems for the FCC Units #4 and #25. During this inspection, the CEMs were
operational and readings were within the limits. Quarterly CEMs Reports are submitted. See
status of condition II.B.2.b.
71

II.B.9.e Condition:

The permittee shall meet the following emission limitations for organic HAP emissions from catalytic
reforming units.
i. For each applicable process vent for a new or existing catalytic reforming unit, the permittee shall vent
emissions of total organic compounds (TOC) to a flare. The flare shall meet the requirements of 40
CFR 63.670.
ii. The emission limitations in 40 CFR 63 Subpart UUU Tables 15 and 16 apply to emissions from
catalytic reforming unit process vents as specified in 40 CFR 63.1566(a)(3) and (4).
[Origin: 40 CFR 63 Subpart UUU]. [40 CFR 63.1566(a)(1)-(4), 40 CFR 63 Subpart UUU Table 15(1), 40
CFR 63 Subpart UUU Table 16(1)]

II.B.9.e.1 Monitoring:

The permittee shall demonstrate compliance according to the following requirements.
i. The permittee shall install, operate, and maintain a continuous monitoring system according to
the requirements in 40 CFR 63.1566(b), 40 CFR 63.1572 and 40 CFR 63 Subpart UUU Table
17. For flares, the permittee shall install, operate, calibrate, and maintain monitoring systems
as specified in 40 CFR 63.670 and 40 CFR 63.671.
ii. To demonstrate continuous compliance, the permittee shall vent emissions to a flare that
meets the requirements of 40 CFR 63.670. (40 CFR 63.1566(c))
(40 CFR 63.1566(b) and (c), 40 CFR 63.1572(c), 40 CFR 63 Subpart UUU Table 17(1), 40 CFR
63 Subpart UUU Table 18(1), 40 CFR 63 Subpart UUU Table 19(1), 40 CFR 63 Subpart UUU
Table 20(1), 40 CFR 63 Subpart UUU Table 21(1))

II.B.9.e.2 Recordkeeping:

Records shall be maintained in accordance with 40 CFR 63.1576 and Provision I.S.1 of this
permit.

II.B.9.e.3 Reporting:

The permittee shall comply with the applicable notification and reporting requirements specified
in 40 CFR 63.1574 and 40 CFR 63.1575. There are no additional reporting requirements for this
provision except those specified in Section I of this permit.

Status: In Compliance – There is a Regenerating Catalyst on the reforming unit. Organics, part of the fuel
gas system, are flared. The flares are monitored 24/7. This condition meets MACT Subpart CC
requirements. See status of condition II.B.5.c.

II.B.9.f Condition:

The permittee shall meet the following emission limitations for inorganic HAP emissions from catalytic
reforming units.
i. For each applicable catalytic reforming unit process vent during coke burn-off and catalyst
rejuvenation, the permittee shall reduce uncontrolled emissions of HCl to a concentration of 10 ppmv
(dry basis), corrected to 3 percent oxygen.
ii. The permittee shall meet this site-specific operating limit during coke burn-off and catalyst
rejuvenation:
(a) The daily average temperature of the gas entering or exiting the adsorption system shall not
exceed the limit established during the performance test; and
(b) The HCl concentration in the adsorption system exhaust gas shall not exceed the limit established
72

during the performance test.
[Origin: 40 CFR 63 Subpart UUU]. [40 CFR 63.1567(a)(1), 40 CFR 63.1567(a)(2), 40 CFR 63 Subpart
UUU Table 22(2), 40 CFR 63 Subpart UUU Table 23(4)]

II.B.9.f.1 Monitoring:

The permittee shall demonstrate compliance according to the following requirements.
i. In accordance with the requirements in 40 CFR 63.1567(b), 40 CFR 63.1572(c) and (d), 40
CFR 63 Subpart UUU Table 24(4) and Table 41, the permittee shall install, operate, and
maintain a continuous parameter monitoring system (CPMS) to measure and record the
temperature of the gas entering or exiting the adsorption system during coke burn-off and
catalyst rejuvenation; and colormetric tube sampling system to measure the gaseous HCl
concentration in the adsorption system exhaust and at a point within the absorbent bed not to
exceed 90 percent of the total length of the absorbent bed during coke burn-off and catalyst
rejuvenation. The colormetric tube sampling system shall meet the requirements in 40 CFR 63
Subpart UUU Table 41.
ii. The permittee shall conduct each performance test for a catalytic reforming unit according to
the requirements in 40 CFR 63.1571 and the conditions specified in 40 CFR 63 Subpart UUU
Table 25. (40 CFR 63.1567(b)(2), 40 CFR 63.1571, 40 CFR 63 Subpart UUU Table 25(1))
iii. The permittee shall establish each site-specific operating limit for temperature and HCl
concentration according to the procedures in 40 CFR 63 Subpart UUU Table 25. (40 CFR
63.1567(b)(3), 40 CFR 63 Subpart UUU Table 25(5))
iv. Compliance shall be demonstrated in accordance with 40 CFR 63.1567(b) and 40 CFR 63
Subpart UUU Table 26(2).
v. The permittee shall demonstrate continuous compliance in accordance with 40 CFR
63.1567(c) and according to the methods specified in 40 CFR 63 Subpart UUU Tables 27 and
28.
(a) Maintain an HCl concentration no more than 10 ppmv (dry basis), corrected to 3 percent
oxygen. (40 CFR 63 Subpart UUU Table 27(2))
(b) Collect the hourly and daily average temperature monitoring data according to 40 CFR
63.1572; and maintain the daily average temperature below the operating limit
established during the performance test. (40 CFR 63 Subpart UUU Table 28(4)(a))
(c) Measure and record the concentration of HCl weekly or during each regeneration cycle,
whichever is less frequent, using a colormetric tube sampling system at a point within the
adsorbent bed not to exceed 90 percent of the total length of the adsorption bed during
coke-burn-off and catalyst rejuvenation; implement procedures in the operating and
maintenance plan if the HCl concentration at the sampling location within the adsorption
bed exceeds the operating limit; and maintain the HCl concentration in the gas from the
adsorption system below the applicable operating limit. (40 CFR 63 Subpart UUU Table
28(4)(b))

II.B.9.f.2 Recordkeeping:

Records shall be maintained in accordance with 40 CFR 63.1576 and Provision I.S.1 of this
permit.

II.B.9.f.3 Reporting:

The permittee shall comply with the applicable notification and reporting requirements specified
in 40 CFR 63.1574 and 40 CFR 63.1575. There are no additional reporting requirements for this
provision except those specified in Section I of this permit.

73

Status: In Compliance – The concentration of HCL from the exhaust of the regeneration process vent
caustic scrubber is checked every four hours with Dragger Tubes. The HCL concentration is
documented in the Exhaust HCL Process Log. If the HCL concentration exceeds the permitted
limit, of 10 ppmv, the exceedance is mentioned in the Semi-annual MACT Subparts CC, UUU,
ZZZZ, and DDDD Periodic reports. The latest MACT report was received on August 5, 2024.

II.B.9.g Condition:

The permittee shall meet the following emission limitations for HAP emissions from sulfur recovery
units.
i. The permittee shall meet this emission limit for each process vent: 300 ppmv of total reduced sulfur
(TRS) compounds, expressed as an equivalent SO2 concentration (dry basis) at zero percent oxygen.
ii. The permittee shall meet the applicable operating limits in 40 CFR 63 Subpart UUU Table 30.
(a) Maintain the daily average combustion zone temperature above the limit established during the
performance test; and
(b) Maintain the daily average oxygen concentration in the vent stream (percent, dry basis) above the
limit established during the performance test.
iii. During periods of startup and shutdown the permittee shall comply with the requirements in 40 CFR
63.1568(a)(4)(iii).
[Origin: 40 CFR 63 Subpart UUU]. [40 CFR 63.1568(a)(1), 40 CFR 63.1568(a)(2), 40 CFR
63.1568(a)(4), 40 CFR 63 Subpart UUU Table 29(3), 40 CFR 63 Subpart UUU Table 30(4), 40 CFR 63
Subpart UUU Table 30(6)]

II.B.9.g.1 Monitoring:

The permittee shall demonstrate compliance according to the following requirements.
i. In accordance with the requirements in 40 CFR 63.1568(b), 40 CFR 63.1572(c) and (d), 40
CFR 63 Subpart UUU Table 31, the permittee shall install, operate, and maintain a continuous
parameter monitoring system (CPMS) to measure and record the combustion zone
temperature of each thermal incinerator and the oxygen content (percent, dry basis) in the vent
stream of the incinerator. (40 CFR 63 Subpart UUU Table 31(3)(a)(ii), 40 CFR 63 Subpart
UUU Table 31(4) and (5) as applicable)
ii. The permittee shall conduct each performance test for a sulfur recovery unit not subject to the
NSPS for sulfur oxides according to the requirements in 40 CFR 63.1571 and under the
conditions specified in 40 CFR 63 Subpart UUU Table 32. (40 CFR 63.1568(b)(2), 40 CFR
63.1571, 40 CFR 63 Subpart UUU Table 32(3))
iii. The permittee shall establish each site-specific operating limit in 40 CFR 63 Subpart UUU
Table 30 according to the procedures in 40 CFR 63 Subpart UUU Table 32. (40 CFR
63.1568(b)(3), 40 CFR 63 Subpart UUU Table 32(3))
iv. The permittee shall correct the reduced sulfur samples to zero percent excess air in accordance
with 40 CFR 63.1568(b)(4).
v. Compliance shall be demonstrated in accordance with 40 CFR 63.1568(b) and 40 CFR 63
Subpart UUU Table 33(3).
vi. The permittee shall demonstrate continuous compliance in accordance with 40 CFR
63.1568(c) and according to the methods specified in 40 CFR 63 Subpart UUU Tables 34 and
35.
(a) Collect the hourly average TRS monitoring data according to 40 CFR 63.1572 and
maintain each 12-hour average concentration of TRS at or below the applicable emission
limitation (40 CFR 63 Subpart UUU Table 34(3)(i))
(b) Collect the hourly and daily average temperature monitoring data according to 40 CFR
63.1572; and maintain the daily average combustion zone temperature at or above the
limit established during the performance test (40 CFR 63 Subpart UUU Table 35(3)(a))
(c) Collect the hourly and daily average O2 monitoring data according to 40 CFR 63.1572;
74

and maintain the average O2 concentration above the level established during the
performance test. (40 CFR 63 Subpart UUU Table 35(3)(b))
(d) During startup or shutdown demonstrate continuous compliance in accordance with 40
CFR 63 Subpart UUU Table 35(4) or (5) as applicable.

II.B.9.g.2 Recordkeeping:

Records shall be maintained in accordance with 40 CFR 63.1576 and Provision I.S.1 of this
permit.

II.B.9.g.3 Reporting:

The permittee shall comply with the applicable notification and reporting requirements specified
in 40 CFR 63.1574 and 40 CFR 63.1575. There are no additional reporting requirements for this
provision except those specified in Section I of this permit.

Status: In Compliance – Table 30 of Subpart UUU gives the option to go with Subpart Ja regarding total
reduced sulfur (TRS) compounds, expressed as an equivalent SO2 concentration (Average Daily
SO2). A Deviation Notice was received by the DAQ on May 21, 2024, regarding not being in
compliance with TRS monitoring requirements. Next, a Reduction in Air Pollutants 40 CFR 60
Subpart Ja SRU SO2 Limit Voluntary Reduction Notice was received by the DAQ on May 20, 2024.
Also, A Notice of Compliance Status Operation Maintenance and Monitoring Plan (OMMP)
update, regarding the Reduction in SO2 Air Pollutants was received by the DAQ on September 3,
2024. Finally, Quarterly CEM reports regarding the SRU scrubber will be submitted, effective
May 3, 2024 (Date of TV Permit). See status of condition II.B.3.b and attached email.

II.B.9.h Condition:

The permittee shall meet each applicable work practice standard for HAP emissions from bypass lines.
The permittee shall meet one of the equipment standards in 40 CFR 63 Subpart UUU Table 36. [Origin:
40 CFR 63 Subpart UUU]. [40 CFR 63.1569(a)(1), 40 CFR 63 Subpart UUU Table 36]

II.B.9.h.1 Monitoring:

The permittee shall demonstrate compliance according to the following requirements.
i. For the option in 40 CFR 63.1569(a)(1)(i), the permittee shall conduct each performance test
for a bypass line according to the requirements in 40 CFR 63.1571 and under the conditions
specified in 40 CFR 63 Subpart UUU Table 37. (40 CFR 63.1569(b)(1), 40 CFR 63.1571, 40
CFR 63 Subpart UUU Table 37(1))
ii. Compliance shall be demonstrated in accordance with 40 CFR 63.1569(b) and 40 CFR 63
Subpart UUU Table 38.
iii. The permittee shall demonstrate continuous compliance in accordance with 40 CFR
63.1569(c) and according to the requirements in 40 CFR 63 Subpart UUU Table 39.

II.B.9.h.2 Recordkeeping:

Records shall be maintained in accordance with 40 CFR 63.1576 and Provision I.S.1 of this
permit.

II.B.9.h.3 Reporting:

The permittee shall comply with the applicable notification and reporting requirements specified
75

in 40 CFR 63.1574 and 40 CFR 63.1575. There are no additional reporting requirements for this
provision except those specified in Section I of this permit.

Status: Not Applicable – There are no bypass lines.

II.B.10 Conditions on Equipment Leaks.

II.B.10.a Condition:

The permittee shall comply with the applicable requirements of General Standards in 40 CFR 60 Subpart
VVa, specifically 40 CFR 60.482-1a, for equipment leaks of VOC emissions from equipment that is in
VOC service except as provided in 40 CFR 60 Subpart GGGa. [Origin: DAQE-AN101230057-23, 40
CFR 60 Subpart GGGa, 40 CFR 63 Subpart CC, SIP Section IX.H.11.g.iv]. [40 CFR 60.592a(a), 40 CFR
63.640(p)(2)]

II.B.10.a.1 Monitoring:

The permittee shall comply with the test methods and procedures specified in 40 CFR 60.485a, as
applicable, except as provided in 40 CFR 60.593a. [40 CFR 60.592a(d)]

II.B.10.a.2 Recordkeeping:

The permittee shall comply with the recordkeeping requirements of 40 CFR 60.486a. [40 CFR
60.592a(e)] Records shall also be maintained in accordance with Provision I.S.1 of this permit.

II.B.10.a.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.487a. [40 CFR 60.592a(e)] There are
no additional reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance – Subparts VV, VVa, and GGGa are more stringent than the 2008 Consent Decree,
regarding equipment leaks. Quarterly VOC Monitoring and Semi-annual Monitoring reports are
submitted as required.

II.B.10.b Condition:

The permittee shall comply with the applicable requirements for pumps in light liquid service in 40 CFR
60 Subpart VVa, specifically 40 CFR 60.482-2a, for equipment leaks of VOC emissions. This applies to
pumps in light liquid service that are in VOC service, except as provided in 40 CFR 60 Subpart GGGa.
[Origin: DAQE-AN101230057-23, 40 CFR 60 Subpart GGGa, 40 CFR 63 Subpart CC, SIP Section
IX.H.11.g.iv]. [40 CFR 60.592a(a), 40 CFR 63. 640(p)(2)]

II.B.10.b.1 Monitoring:

The permittee shall comply with the test methods and procedures specified in 40 CFR 60.485a, as
applicable, except as provided in 40 CFR 60.593a. [40 CFR 60.592a(d)]

76

II.B.10.b.2 Recordkeeping:

The permittee shall comply with the recordkeeping requirements of 40 CFR 60.486a. [40 CFR
60.592a(e)] Records shall also be maintained in accordance with Provision I.S.1 of this permit.

II.B.10.b.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.487a. [40 CFR 60.592a(e)] There are
no additional reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance – Single seal pumps are inspected monthly and dual seal pumps are inspected
annually using Method 21. LDAR inspections results are maintained in the Guidwear database.
The last Quarterly VOC Monitoring report for the 3rd Quarter 2024, was received on October 18,
2024. The last Semi-annual VOC Monitoring report was received on July 29, 2024.

II.B.10.c Condition:

The permittee shall comply with the applicable requirements for compressors in 40 CFR 60 Subpart VVa,
specifically 40 CFR 60.482-3a, for equipment leaks of VOC emissions. This applies to compressors that
are in VOC service, except as provided in 40 CFR 60 Subpart GGGa. [Origin: DAQE-AN101230057-
23, 40 CFR 60 Subpart GGGa, 40 CFR 63 Subpart CC, SIP Section IX.H.11.g.iv]. [40 CFR 60.592a(a),
40 CFR 63. 640(p)(2)]

II.B.10.c.1 Monitoring:

The permittee shall comply with the test methods and procedures specified in 40 CFR 60.485a, as
applicable, except as provided in 40 CFR 60.593a. [40 CFR 60.592a(d)]

II.B.10.c.2 Recordkeeping:

The permittee shall comply with the recordkeeping requirements of 40 CFR 60.486a. [40 CFR
60.592a(e)] Records shall also be maintained in accordance with Provision I.S.1 of this permit.

II.B.10.c.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.487a. [40 CFR 60.592a(e)] There are
no additional reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance – Compressors are inspected quarterly using Method 21. Inspection results are
maintained in the Guidwear database. The last Quarterly VOC Monitoring report for the 3rd
Quarter 2024, was received on October 18, 2024. The last Semi-annual VOC Monitoring report was
received on July 29, 2024.

II.B.10.d Condition:

The permittee shall comply with the applicable requirements for pressure relief devices in gas/vapor
service in 40 CFR 60 Subpart VVa, specifically 40 CFR 60.482-4a, for equipment leaks of VOC
emissions. This applies to pressure relief devices in VOC gas/vapor service, except as provided in 40 CFR
60 Subpart GGGa. In accordance with 40 CFR 63.640(s), flares used to comply with this condition shall
comply only with the provisions of 40 CFR 63 Subpart CC. [Origin: DAQE-AN101230057-23, 40 CFR
77

60 Subpart GGGa, 40 CFR 63 Subpart CC, SIP Section IX.H.11.g.iv]. [40 CFR 60.592a(a), 40 CFR
63.640(s)]

II.B.10.d.1 Monitoring:

The permittee shall comply with the test methods and procedures specified in 40 CFR 60.485a, as
applicable, except as provided in 40 CFR 60.593a. [40 CFR 60.592a(d)]

II.B.10.d.2 Recordkeeping:

The permittee shall comply with the recordkeeping requirements of 40 CFR 60.486a. [40 CFR
60.592a(e)] Records shall also be maintained in accordance with Provision I.S.1 of this permit.

II.B.10.d.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.487a. [40 CFR 60.592a(e)] There are
no additional reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance – Pressure relief devices (PRDs) which release to the flares are inspected quarterly
using Method 21. Inspection results are maintained in the Guidwear database. The last Quarterly
VOC Monitoring report for the 3rd Quarter 2024, was received on October 18, 2024. The last Semi-
annual VOC Monitoring report was received on July 29, 2024.

II.B.10.e Condition:

The permittee shall comply with the applicable requirements for sampling connection systems in 40 CFR
60 Subpart VVa, specifically 40 CFR 60.482-5a, for equipment leaks of VOC emissions. This applies to
sampling connection systems that are in VOC service, except as provided in 40 CFR 60 Subpart GGGa.
[Origin: DAQE-AN101230057-23, 40 CFR 60 Subpart GGGa, 40 CFR 63 Subpart CC, SIP Section
IX.H.11.g.iv]. [40 CFR 60.592a(a), 40 CFR 63.640(p)(2)]

II.B.10.e.1 Monitoring:

The permittee shall comply with the test methods and procedures specified in 40 CFR 60.485a, as
applicable, except as provided in 40 CFR 60.593a. [40 CFR 60.592a(d)]

II.B.10.e.2 Recordkeeping:

The permittee shall comply with the recordkeeping requirements of 40 CFR 60.486a. [40 CFR
60.592a(e)] Records shall also be maintained in accordance with Provision I.S.1 of this permit.

II.B.10.e.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.487a. [40 CFR 60.592a(e)] There are
no additional reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance – Sampling connecting systems (Sample Ports) are inspected quarterly using
Method 21. Inspection results are maintained in the Guidwear database. The last Quarterly VOC
Monitoring report for the 3rd Quarter 2024, was received on October 18, 2024. The last Semi-
annual VOC Monitoring report was received on July 29, 2024.
78

II.B.10.f Condition:

The permittee shall comply with the applicable requirements for open-ended valves or lines in 40 CFR 60
Subpart VVa, specifically 40 CFR 60.482-6a, for equipment leaks of VOC emissions. This applies to
open-ended valves or lines that are in VOC service, except as provided in 40 CFR 60 Subpart GGGa. The
permittee shall also comply with R307-326-9(8). [Origin: DAQE-AN101230057-23, 40 CFR 60 Subpart
GGGa, 40 CFR 63 Subpart CC, Section IX.H.11.g.iv, R307-326-9(8)]. [40 CFR 60.592a(a), 40 CFR
63.640(p)(2), R307-326-9(8)]

II.B.10.f.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.10.f.2 Recordkeeping:

The permittee shall keep records that demonstrate compliance with the requirements in 40 CFR
60.482-6a and R307-326-9(8). The permittee shall comply with the recordkeeping requirements
of 40 CFR 60.486a. [40 CFR 60.592a(e)] Records shall be maintained in accordance with
Provision I.S.1 of this permit.

II.B.10.f.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.487a. [40 CFR 60.592a(e)] There are
no additional reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance – Open-ended lines are found as they are detected using Method 21. When detected,
the open-ended lines are doubled blocked. Open-ended line documentation is maintained in the
Title V Deviation Report spreadsheet. There are no open-ended valves at the refinery.

II.B.10.g 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 40 CFR 60.482-7a, for equipment leaks of VOC
emissions. This applies to valves in gas/vapor service and in light liquid service that are in VOC service,
except as provided in 40 CFR 60 Subpart GGGa. [Origin: DAQE-AN101230057-23, 40 CFR 60 Subpart
GGGa, 40 CFR 63 Subpart CC, SIP Section IX.H.11.g.iv]. [40 CFR 60.592a(b), 40 CFR 63.640(p)(2)]

II.B.10.g.1 Monitoring:

The permittee shall comply with the test methods and procedures specified in 40 CFR 60.485a, as
applicable, except as provided in 40 CFR 60.593a. [40 CFR 60.592a(d)]

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. [DAQE-AN101230057-23, SIP Section
IX.H.11.g.iv.B]

79

II.B.10.g.2 Recordkeeping:

The permittee shall comply with the recordkeeping requirements of 40 CFR 60.486a. [40 CFR
60.592a(e)] Records shall also be maintained in accordance with Provision I.S.1 of this permit.

II.B.10.g.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.487a. [40 CFR 60.592a(e)] There are
no additional reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance – Valves in gas/vapor service and in light liquid services are inspected quarterly
using Method 21. Inspection results are maintained in the Guidwear database. The last Quarterly
VOC Monitoring report for the 3rd Quarter 2024, was received on October 18, 2024. The last Semi-
annual VOC Monitoring report was received on July 29, 2024.

II.B.10.h 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 40 CFR 60.482-8a, for equipment leaks of VOC emissions. This applies to pumps and
valves in heavy liquid service, pressure relief devices in light liquid or heavy liquid service, and all
connectors in heavy liquid, gas/vapor, or light liquid service, that are in VOC service, except as provided
in 40 CFR 60 Subpart GGGa. [Origin: DAQE-AN101230057-23, 40 CFR 60 Subpart GGGa, 40 CFR 63
Subpart CC, SIP Section IX.H.11.g.iv]. [40 CFR 60.592a(a), 40 CFR 60.593a(g), 40 CFR 63.640(p)(2)]

II.B.10.h.1 Monitoring:

The permittee shall comply with the test methods and procedures specified in 40 CFR 60.485a, as
applicable, except as provided in 40 CFR 60.593a. [40 CFR 60.592a(d)]

II.B.10.h.2 Recordkeeping:

The permittee shall comply with the recordkeeping requirements of 40 CFR 60.486a. [40 CFR
60.592a(e)] Records shall also be maintained in accordance with Provision I.S.1 of this permit.

II.B.10.h.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.487a. [40 CFR 60.592a(e)] There are
no additional reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance – Pumps, valves, and connectors in heavy liquid service and PRDs in light or heavy
liquid service are inspected quarterly using Method 21. Audible, Visual, Olfactory (AVO)
inspections are also used to detect for spills. Inspection results are maintained in the Guidwear
database. The last Quarterly VOC Monitoring report for the 3rd Quarter 2024, was received on
October 18, 2024. The last Semi-annual VOC Monitoring report was received on July 29, 2024.

II.B.10.i Condition:

The permittee shall comply with the applicable requirements for delay of repair in 40 CFR 60 Subpart
VVa, specifically 40 CFR 60.482-9a, for equipment leaks of VOC emissions. This applies to applicable
80

equipment in VOC service, except as provided in 40 CFR 60 Subpart GGGa. [Origin: DAQE-
AN101230057-23, 40 CFR 60 Subpart GGGa, 40 CFR 63 Subpart CC, SIP Section IX.H.11.g.iv]. [40
CFR 60.592a(a), 40 CFR 63.640(p)(2)]

II.B.10.i.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.10.i.2 Recordkeeping:

The permittee shall comply with the recordkeeping requirements of 40 CFR 60.486a. [40 CFR
60.592a(e)] Records shall also be maintained in accordance with Provision I.S.1 of this permit.

II.B.10.i.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.487a. [40 CFR 60.592a(e)] There are
no additional reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance – Delay of repair (DOR) occurs when parts need to be ordered or when a process
needs to shut down or isolated before a leak can be repaired. DORs have a two-month follow-up
and then entered in the Guidwear database. The last Quarterly VOC Monitoring report for the 3rd
Quarter 2024, was received on October 18, 2024. The last Semi-annual VOC Monitoring report was
received on July 29, 2024.

II.B.10.j Condition:

The permittee shall comply with the applicable requirements for closed vent systems and control devices
in 40 CFR 60 Subpart VVa, specifically 40 CFR 60.482-10a, for equipment leaks of VOC emissions from
equipment in VOC service, except as provided in 40 CFR 60 Subpart GGGa. In accordance with 40 CFR
63.640(s), flares used to comply with this condition shall comply only with the provisions of 40 CFR 63
Subpart CC. [Origin: DAQE-AN101230057-23, 40 CFR 60 Subpart GGGa, 40 CFR 63 Subpart CC, SIP
Section IX.H.11.g.iv]. [40 CFR 60.592a(a), 40 CFR 63.640(p)(2), 40 CFR 63.640(s)]

II.B.10.j.1 Monitoring:

The permittee shall comply with the test methods and procedures specified in 40 CFR 60.485a, as
applicable, except as provided in 40 CFR 60.593a. [40 CFR 60.592a(d)]

II.B.10.j.2 Recordkeeping:

The permittee shall comply with the recordkeeping requirements of 40 CFR 60.486a. [40 CFR
60.592a(e)] Records shall also be maintained in accordance with Provision I.S.1 of this permit.

II.B.10.j.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.487a. [40 CFR 60.592a(e)] There are
no additional reporting requirements for this provision except those specified in Section I of this
permit.

Status: In Compliance – Closed vent systems and control devices are inspected quarterly using Method 21.
Inspection results are maintained in the Guidwear database. The last Quarterly VOC Monitoring
81

report for the 3rd Quarter 2024, was received on October 18, 2024. The last Semi-annual VOC
Monitoring report was received on July 29, 2024.

II.B.10.k Condition:

Except as specified in 40 CFR 63.648(j)(4), the permittee shall comply with the requirements in 40 CFR
63.648(j)(1) and (2) for pressure relief devices in organic HAP gas or vapor service instead of the
pressure relief device requirements of 40 CFR 60.482-4a. Except as specified in 40 CFR 63.648(j)(4) and
(5), the permittee shall also comply with the requirements specified in 40 CFR 63.648(j)(3) for all
pressure relief devices in organic HAP service. [Origin: 40 CFR 63 Subpart CC]. [40 CFR 63.640(p)(2),
40 CFR 63.648(j)]

II.B.10.k.1 Monitoring:

Testing shall comply with the applicable requirements of 40 CFR 60.485a except as provided in
40 CFR 63.648.

II.B.10.k.2 Recordkeeping:

Records shall comply with the applicable requirements of 40 CFR 60.486a, 40 CFR 63.648, and
40 CFR 63.655. Records shall also be maintained in accordance with Provision I.S.1 of this
permit.

II.B.10.k.3 Reporting:

Reporting shall comply with the applicable requirements of 60.487a, 40 CFR 63.655 and as
specified in Section I of this permit.

Status: In Compliance – PRDs in organic HAP gas and vapor service are inspected quarterly using Method
21. Inspection results are maintained in the Guidwear database. The last Quarterly VOC
Monitoring report for the 3rd Quarter 2024, was received on October 18, 2024. The last Semi-
annual VOC Monitoring report was received on July 29, 2024.

II.B.10.l Condition:

In accordance with R307-326-6, the permittee shall minimize VOCs emitted to the atmosphere during
process unit turnarounds. [Origin: R307-326]. [R307-326-6]

II.B.10.l.1 Monitoring:

The permittee shall develop and submit to the director for approval a procedure for minimizing
VOC emissions during turnarounds as specified in R307-326-6.

II.B.10.l.2 Recordkeeping:

Records shall be kept as specified in R307-326-6. Records shall be maintained in accordance
with Provision I.S.1 of this permit and shall be made available for review by the director or the
director's representative.

II.B.10.l.3 Reporting: There are no reporting requirements for this provision except those specified in Section I of this permit.
82

Status: In Compliance – The refinery follows State Rule 307-326, regarding the minimization of emissions
during turnarounds. Different procedures are also used to minimize equipment emissions during
turnarounds such as Chemical Cleanings, Vapor Recovery Units, Diesel Scrubs, and Carbon
Canisters. Once the turnaround is completed, the equipment is put back into process.

II.B.10.m Condition:

The permittee shall develop and conduct a VOC monitoring program in accordance with R307-326-9. 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. [Origin: R307-326]. [R307-326-8, R307-326-9]

II.B.10.m.1 Monitoring:

The permittee shall monitor in accordance with R307-326-9(2) through (5).

II.B.10.m.2 Recordkeeping:

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

II.B.10.m.3 Reporting:

Reports shall be submitted in accordance with R307-326-9(7). There are no additional reporting
requirements for this provision except those specified in Section I of this permit.

Status: In Compliance – The refinery has developed and implemented a VOC monitoring program, in
accordance with State Rule 307-326. The program has been incorporated into the Guidwear
database. Quarterly and Semi-annul VOC Monitoring reports are submitted accordingly. The last
Quarterly VOC Monitoring report for the 3rd Quarter 2024, was received on October 18, 2024.
The last Semi-annual VOC Monitoring report was received on July 29, 2024.

II.B.11 Conditions on Wastewater Treatment (Unit 56).

II.B.11.a Condition:

i. Each of the following process drains shall be equipped with water seal controls that meet the
applicable requirements in 40 CFR 60.692-2(a).
Unit 4 - south of regenerator, south of catalyst hopper, north of Quincy, west of 4H1 north, west of
4H1 south, air compressor and dryer building
Unit 7 - north of ReVap skid, east of ReVap skid, northeast corner of ReVap skid, south of 7P15,
south of 7P16, south of 7P17, ASO neutralization drum east, ASO neutralization drum center,
ASO neutralization drum west, southwest of building at cooling tower 11, north of Alky DeC3
feed surge tank
Unit 16 - Sour gas KO drum, sweet gas KO drum and absorber
Unit 17 - below acid gas combustion air DMV, west of sour gas KO drum, west of acid gas KO
drum, below final condenser, below sulfur condenser, between air blowers, French drain pump &
incinerator pilot gas double block & bleed
Unit 18 - oily condensate pump, northeast of sour water stripper, north side of SWS overhead
condenser, SWS reflux pump, east side of SWS reflux drum
Unit 24 - south of 24P1, north of 24E7, north of 24E10 , north of 24P8, north of 24P9, west of
v24P12, north of 24P45, southeast of 24P5A, north of 24V1, south of 24P7, south of 24P6, south
of 24E9, south of 24E13, southwest of 24V8, west of 24P11, west of 24V10, southwest of
83

condensate tank, southeast of condensate tank, east of condensate tank, northeast of condensate
tank
Unit 25 - east of 25P33B, south of 25P33A/B, under 25V54B west, under 25V54B east, under
25V54A west, under 25V54A east, west of 25V54A, under 25V56A west, under 25V56A center,
under 25V56A east, 25P34B, 25P34A, 25P35B, 25P35A, northwest of 25V55, west of 25K1,
west of 25K2, east of 25K2, northwest of 25P20, south of 25V54, north of 25P3A, north of 25P3,
north of 25P6A, north of 25P5, south of 25P19, northwest of 25V7, 25E1B, north of 25E4, north
of 25P7, north of 25E15, north of 25P11, north of 25P12, north of 25V16, north of 25V12,
northwest of 26P6, south of 15P10, east of 25E16, west of 25V9, west of 25E11, north of 25V10,
north of 25P8, south of 25P2, south of 25P4, west of 25P1, west of 25V1, east of 25P22, north of
25P22, north of 25V24, northeast of 25V20, northeast of 25E19, northwest of 25E19, southwest
of 25E19, south of 25V21, northeast of 25MP8 control panel, south of 25V52, southwest of
25V52, east of 25V47, south of 25P27, south of 25P28, west of 25P26, west of 25P25, west of
25P24, north of wet gas scrubber
Unit 26 - west of 26V8, west of 26V6, east of 26V10, east of 26P7, northeast of 26P7A, west of
26V14, north of 26V14, south of 26P12, 26P4, 26P4A, 26P3, 26P3A, 26P2, 26P2A, south of
26V7, south of 26V9, chemical building 26V17, 26P14
Unit 57 - CA FH-2-P, CA FH-4-P, CA FH-8-P, GC FH-1-P, GC FH-3-P, SP FH-1-P, SP FH-2-P, SP
FH-6-P. SP FH-9-P, HF FH-2-P, RS FH-1, OCT-FH-1-P
ii. 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.
iii. The permittee shall comply with the requirements of 40 CFR 60.692-2 and with 40 CFR 60.693-1,
except during periods of startup, shutdown, or malfunction.
[Origin: 40 CFR 60 Subpart QQQ]. [40 CFR 60.692-1(a), 40 CFR 60.692-2(a), 40 CFR 60.692-2(e)]

II.B.11.a.1 Monitoring:

Monitoring shall be conducted in accordance with 40 CFR 60.692-2(a)(2)-(5) and 40 CFR
60.696(a).

II.B.11.a.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.697 and
Provision I.S.1 of this permit.

II.B.11.a.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.698 and as specified in Section I of this
permit.

Status: In Compliance – Process drains are maintained on a monthly basis. Junction boxes are maintained
on a semi-annual basis. All maintenance is conducted in-house and tracked using spreadsheets.
Water evaporation in the process drains is a common problem, which is disclosed in the Semi-
annual QQQ reports. The last Semi-annual QQQ report was received on October 4, 2024.

II.B.11.b Condition:

i. Each of the following junction boxes shall meet the applicable requirements of 40 CFR 60.692-2(b).
Junction boxes shall be equipped with a cover and may have an open vent pipe. 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.
84

Unit 4 - Manholes OWMH-305, OWMH-310, OWMH-309, CSMH-348, cleanout (blind flange
located in NW corner of SRU, OWMH-306, Cleanout southeast of SWS tower, OWMH-289,
OWMH-315A, OWMH-316, OWMH-317
Unit 7 - Manhole CSMH-330, drain junction box west side of ReVap skid
Unit 16 - Manhole CSMH-348 west of absorber
Unit 24 - Southeast of cooling tower 10
Unit 25 - Manhole southwest of wet gas scrubber, roadway west of scrubber dewatering bins
API - Stage 1 MBBR (Tank 67) hatch on top, Stage 1 MBBR (Tank 67) confined space entry
hatch south, 56V77 MBBR KO pot confined space entry hatch, API 61 north maintenance lid,
API 61A north maintenance lid, API 61A central maintenance lid, API 61A south maintenance
lid, API 61B north maintenance lid, API 61B central maintenance lid, API 61B south maintenance
lid, main water lift station, stormwater lift station, diversion box, oily water lift station.
ii. 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.
iii. The permittee shall comply with the requirements of 40 CFR 60.692-2 and with 40 CFR 60.693-1,
except during periods of startup, shutdown, or malfunction.
[Origin: 40 CFR 60 Subpart QQQ]. [40 CFR 60.692-1(a), 40 CFR 60.692-2(b), 40 CFR 60.692-2(e)]

II.B.11.b.1 Monitoring:

Monitoring shall be conducted in accordance with 40 CFR 60.692-2(b)(3), (4) and 40 CFR
60.696(a).

II.B.11.b.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.697 and
Provision I.S.1 of this permit.

II.B.11.b.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.698 and as specified in Section I of this
permit.

Status: In Compliance – Junction boxes are never opened, allowing for seals to be maintained. The last
Semi-annual QQQ report was received on October 4, 2024. See status of condition II.B.121.a.

II.B.11.c Condition:

i. Each oil-water separator tank, slop oil tank, storage vessel, or other auxiliary equipment subject to
the requirements of 40 CFR 60 Subpart QQQ shall be equipped and operated with a fixed roof,
which meets the specifications in 40 CFR 60.692-3(a)(1) through (3), except as provided in 40 CFR
60.692-3(d) or in 40 CFR 60.693-2.
ii. Each oil-water separator tank or auxiliary equipment with a design capacity to treat more than 16
liters per second (250 gallons per minute (gpm)) of refinery wastewater shall, in addition to the
requirements in 40 CFR 60.692-3(a), be equipped and operated with a closed vent system and control
device, which meet the requirements of 40 CFR 60.692-5, except as provided in 40 CFR 60.692-3(c)
or in 40 CFR 60.693-2.
iii. Slop oil from an oil-water separator tank and oily wastewater from slop oil handling equipment shall
be collected, stored, transported, recycled, reused, or disposed of in an enclosed system. Once slop
oil is returned to the process unit or is disposed of, it is no longer within the scope of 40 CFR 60
Subpart QQQ. Equipment used in handling slop oil shall be equipped with a fixed roof meeting the
85

requirements of 40 CFR 60.692-3(a).
iv. Each oil-water separator tank, slop oil tank, storage vessel, or other auxiliary equipment that is
required to comply with 40 CFR 60.692-3(a), and not 40 CFR 60.692-3(b), may be equipped with a
pressure control valve as necessary for proper system operation. The pressure control valve shall be
set at the maximum pressure necessary for proper system operation, but such that the valve shall not
vent continuously.
v. The permittee shall comply with the requirements of 40 CFR 60.692-3 and with 40 CFR 60.693-2,
except during periods of startup, shutdown, or malfunction.
[Origin: 40 CFR 60 Subpart QQQ]. [40 CFR 60.692-1(a), 40 CFR 60.692-3]

II.B.11.c.1 Monitoring:

Monitoring shall be conducted in accordance with 40 CFR 60.692-3(a)(4),(5) and 40 CFR
60.696(a), (d).

II.B.11.c.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.697 and
Provision I.S.1 of this permit.

II.B.11.c.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.698 and as specified in Section I of this
permit.

Status: In Compliance – Review of Waste Water Treatment Plant (WWTP) schematics, at time of the
inspection, demonstrated compliance. WWTP data is maintained in the Guidwear database.
Carbon bed weekly checks are documented using spreadsheets.

II.B.11.d Condition:

For closed vent systems and control devices at the wastewater treatment unit:
i. 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.
ii. Closed vent systems and control devices used to comply with provisions of 40 CFR 60 Subpart QQQ
shall be operated at all times when emissions may be vented to them.
iii. 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.
iv. Closed vent systems shall be purged to direct vapor to the control device.
v. The permittee shall comply with the requirements of 40 CFR 60.692-5 and with 40 CFR 60.693-2,
except during periods of startup, shutdown, or malfunction.
[Origin: 40 CFR 60 Subpart QQQ]. [40 CFR 60.692-1(a), 40 CFR 60.692-5]

II.B.11.d.1 Monitoring:

Monitoring shall be conducted in accordance with 40 CFR 60.692-5(e), 40 CFR 60.695(a)(3)(ii),
and 40 CFR 60.696(a), (b). The permittee shall install, calibrate, maintain, and operate according
to manufacturer's specifications, the equipment specified in 40 CFR 60.695(a)(3).

II.B.11.d.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.695(a)(3),
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40 CFR 60.697, and Provision I.S.1 of this permit.

II.B.11.d.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.698 and as specified in Section I of this
permit.

Status: In Compliance – The closed vent system is purged with Nitrogen gas (N2). The closed vent system is
checked semi-annually and vents are checked weekly using Method 21. See status of condition
II.B.11.c regarding carbon bed canisters.

II.B.11.e Condition:

Delay of repair of facilities that are subject to the provisions of 40 CFR 60 Subpart QQQ will be allowed
if the repair is technically impossible without a complete or partial refinery or process unit shutdown.
Repair of such equipment shall occur before the end of the next refinery or process unit shutdown.
[Origin: 40 CFR 60 Subpart QQQ]. [40 CFR 60.692-6]

II.B.11.e.1 Monitoring:

Records required for this permit condition shall serve as monitoring.

II.B.11.e.2 Recordkeeping:

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

II.B.11.e.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.698 and as specified in Section I of this
permit.

Status: In Compliance – There has been no DOR, concerning the WWTP, to date. Spare parts are kept on-
site. Semi-annual QQQ reports are submitted.

II.B.11.f Condition:

i. Sewer lines, as defined in 40 CFR 60 Subpart QQQ, 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.
ii. The permittee shall comply with the requirements of 40 CFR 60.692-2 and with 40 CFR 60.693-1,
except during periods of startup, shutdown, or malfunction.
[Origin: 40 CFR 60 Subpart QQQ]. [40 CFR 60.692-1(a), 40 CFR 60.692-2(c)]

II.B.11.f.1 Monitoring:

Monitoring shall be conducted in accordance with 40 CFR 60.692-2(c)(2), (3) and 40 CFR
60.696(a).

II.B.11.f.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.697 and
Provision I.S.1 of this permit.
87

II.B.11.f.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 60.698 and as specified in Section I of this
permit.

Status: In Compliance – The above ground sewer lines, concerning the WWTP, are inspected semi-
annually. Method 21 is used to inspect and monitor the lines. The last Semi-annual QQQ report was
received on October 4, 2024.

II.B.11.g Condition:

The permittee shall ensure that any wastewater (oil/water) separator handling VOCs is equipped with:
i. covers and seals approved by the Director on all separators and forebays,
ii. 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]

II.B.11.g.1 Monitoring:

A semiannual inspection shall be performed to demonstrate compliance with this condition.

II.B.11.g.2 Recordkeeping:

Records documenting the semiannual inspection results shall be maintained in accordance with
Provision I.S.1 of this permit.

II.B.11.g.3 Reporting:

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

Status: In Compliance – The separator’s closed vent system is purged with Nitrogen gas (N2). The
separator is inspected semi-annually using Method 21. The last Semi-annual QQQ report was
received on October 4, 2024.

II.B.12 Conditions on Fuel Gas Combustion Devices.

II.B.12.a Condition:

For fuel gas combustion devices subject to 40 CFR 60 Subpart J:
The permittee shall not burn in any fuel gas combustion device any fuel gas that contains hydrogen
sulfide (H2S) in excess of 230 mg/dscm (0.10 gr/dscf). The combustion in a flare of process upset gases or
fuel gas that is released to the flare as a result of relief valve leakage or other emergency malfunctions is
exempt from this paragraph. [Origin: 40 CFR 60 Subpart J]. [40 CFR 60.104(a)(1)]

II.B.12.a.1 Monitoring:

The permittee shall install, calibrate, maintain, and operate a continuous monitoring system in
accordance with R307-170 and as follows:
a) Either an instrument for continuously monitoring and recording the concentration by volume
(dry basis, zero percent excess air) of SO2 emissions into the atmosphere in accordance with
40 CFR 60.105(a)(3) or monitoring as provided in 40 CFR 60.105(a)(4). The monitor shall
88

include an oxygen monitor for correcting the data for excess.
b) Instead of the SO2 monitor in 40 CFR 60.105(a)(3), an instrument for continuously
monitoring and recording the concentration (dry basis) of H2S in fuel gases before being
burned in any fuel gas combustion device in accordance with 40 CFR 60.105(a)(4).
(40 CFR 60.105(a), (a)(3), (a)(4))

Performance testing shall be conducted in accordance with 40 CFR 60.106(a) and (e).

II.B.12.a.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.107(e),
R307-170, and Provision I.S.1 of this permit.

II.B.12.a.3 Reporting:

Reports shall be submitted quarterly in accordance with R307-170-9. The quarterly reports 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 in the report. There are no additional
reporting requirements for this provision except those specified in 40 CFR 60.105(e), 40 CFR
60.107, and Section I of this permit.

Status: In Compliance – Fuel gas combustion devices entail the on-site heaters and boilers. The DAQ CEM
Specialist determines compliance with HF Sinclair’s CEMs monitoring systems that monitor the
concentration H2S from the fuel gas combustion devices. Quarterly CEMs Reports are submitted.

II.B.12.b Condition:

For fuel gas combustion devices subject to 40 CFR 60 Subpart Ja:
Except as provided in 40 CFR 60.102a(g)(1)(iii), for each fuel gas combustion device, the permittee shall
comply with the fuel gas concentration limit as follows.
i. The permittee shall not burn in any fuel gas combustion device any fuel gas that contains H2S in
excess of 162 ppmv determined hourly on a 3-hour rolling average basis and H2S in excess of 60
ppmv determined daily on a 365 successive calendar day rolling average basis.
[Origin: 40 CFR 60 Subpart Ja, SIP Section IX.H.1.g.ii, SIP Section IX.H.11.g.ii]. [40 CFR
60.102a(g)(1), SIP Section IX.H.1.g.ii, SIP Section IX.H.11.g.ii]

II.B.12.b.1 Monitoring:

Except as provided in 40 CFR 60.107a(a)(3), the permittee shall install, calibrate, maintain, and
operate an instrument for continuously monitoring and recording the concentration by volume
(dry basis) of H2S in the fuel gases before being burned in any fuel gas combustion device in
accordance with R307-170, 40 CFR 60.107a(a)(2), and 40 CFR 60.107a(i).

The permittee shall conduct a root cause analysis and a corrective action analysis for each of the
conditions specified in 40 CFR 60.103a(c), as applicable. A root cause analysis and corrective
action analysis shall be completed as soon as possible, in accordance with 40 CFR 60.103a(d).
The permittee shall implement the corrective action(s) identified in the corrective action analysis
in accordance with 40 CFR 60.103a(e).

Performance testing shall be conducted in accordance with 40 CFR 60.104a(a), (c), and (j).

II.B.12.b.2 Recordkeeping:
89

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.103a(e), 40
CFR 60.108a(a), (c), R307-170, and Provision I.S.1 of this permit.

II.B.12.b.3 Reporting:

Reports shall be submitted quarterly in accordance with R307-170-9. The quarterly reports 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 in the report. There are no additional
reporting requirements for this provision except those specified in 40 CFR 60.107a(i), 40 CFR
60.108a(a), (b), (d), and Section I of this permit.

Status: In Compliance – Subpart Ja is followed because it is more stringent than Subpart J. See status of
condition II.B.12.a.

II.B.12.c Condition:

For fuel gas combustion devices subject to 40 CFR 60 Subpart Ja:
For each process heater with a rated capacity of greater than 40 MMBtu/hr on a higher heating value
basis, the permittee shall not discharge to the atmosphere any emissions of NOx in excess of the
applicable limits in 40 CFR 60.102a(g)(2)(i) through (iv). [Origin: 40 CFR 60 Subpart Ja]. [40 CFR
60.102a(g)(2)]

II.B.12.c.1 Monitoring:

For process heaters complying with the NOx concentration-based limit or the NOx heating value-
based or mass-based limit, the permittee shall install, calibrate, maintain, and operate an
instrument for continuously monitoring and recording the concentration (dry basis, 0-percent
excess air) of NOx emissions into the atmosphere in accordance with R307-170, 40 CFR
60.107a(c) and (d), as applicable, and 40 CFR 60.107a(i). The monitor shall include an 02 monitor
for correcting the data for excess air in accordance with 40 CFR 60.107a(c), as applicable. The
permittee shall determine the F factor of the fuel gas stream no less frequently than once per day,
install, calibrate, maintain, and operate an instrument for continuously monitoring and recording
the flow rate of the fuel gas and fuel oil fed to the process heater, determine gas composition, or
the heating value in accordance with 40 CFR 60.107a(d), as applicable.

Performance testing shall be conducted in accordance with 40 CFR 60.104a(a), (c), and (i).

II.B.12.c.2 Recordkeeping:

Records and results of monitoring shall be maintained in accordance with 40 CFR 60.108a(a),
R307-170, and Provision I.S.1 of this permit.

II.B.12.c.3 Reporting:

Reports shall be submitted quarterly in accordance with R307-170-9. The quarterly reports 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 in the report. There are no additional
reporting requirements for this provision except those specified in 40 CFR 60.107a(i), 40 CFR
60.108a(a), (b), (d), and Section I of this permit.

Status: In Compliance – The DAQ CEM Specialist determines compliance with HF Sinclair’s CEMs
monitoring systems that monitor the O2. Quarterly CEMs Reports are submitted. Stack Testing for
90

NOx is conducted every two years. The initial NOx Stack Test was conducted on May 8 and 9, 2023,
which failed. The retest was conducted on August 17, 2023, which is considered to be the last Stack
Test. The next NOx Stack Test will be performed in 2025.

II.B.13 Conditions on Cooling Towers (Unit 54).

II.B.13.a Condition: [State-only Requirement]

For heat exchange systems in VOC service, the permittee shall comply with the requirements of 40 CFR
63.654. For this condition only, the following applies in lieu of 40 CFR 63.654(b). A heat exchange
system is exempt from the requirements in 40 CFR 63.654(c) through (g), if it meets any one of the
criteria in paragraphs i. through ii.
i. All heat exchangers that are in VOC service within the heat exchange system that either:
a) Operate with the minimum pressure on the cooling water side at least 35 kilopascals greater than
the maximum pressure on the process side; or
b) Employ an intervening cooling fluid, containing less than 10 percent by weight of VOCs,
between the process and the cooling water. This intervening fluid must serve to isolate the
cooling water from the process fluid and must not be sent through a cooling tower or discharged.
For purposes of this section, discharge does not include emptying for maintenance purposes.
ii. The heat exchange system cools process fluids that contain less than 10 percent by weight VOCs
(i.e., the heat exchange system does not contain any heat exchangers that are in VOC service).
[Origin: DAQE-AN101230057-23, SIP Section IX.H.11.g.iii]. [R307-401-8, SIP Section IX.H.11.g.iii]

II.B.13.a.1 Monitoring:

The permittee shall perform monthly monitoring of Cooling Towers 4, 6, 7, 8, 10, and 11 to
comply with the requirements of 40 CFR 63.654 for heat exchange systems in VOC service.

The permittee may elect to use another EPA-approved method other than the Modified El Paso
Method if approved by the Director.

II.B.13.a.2 Recordkeeping:

Records and results of monitoring shall be kept monthly and shall be maintained in accordance
with 40 CFR 63.655(i)(5) and Provision I.S.1 of this permit.

II.B.13.a.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 63.655(g) and as specified in Section I of
this permit.

Status: In Compliance – The modified El Paso Method / Method 21 is performed monthly on the on-site
cooling towers. The results of the inspections are maintained on a spread sheet and the Guidware
data base. The information is provided in the Semi-annual MACT Subparts CC, UUU, ZZZZ, and
DDDD Periodic reports. The latest MACT report was received on August 5, 2024.

II.B.13.b Condition:

For the heat exchange systems associated with cooling towers 4, 6, 7, 8, 10, and 11, the permittee shall
comply with the applicable requirements in 40 CFR 63.654. [Origin: 40 CFR 63 Subpart CC]. [40 CFR
63.654(a)]

91

II.B.13.b.1 Monitoring:

The permittee shall perform monitoring to identify and repair leaks of total strippable volatile
organic compounds (VOC) from each heat exchange system subject to the requirements of 40
CFR 63 Subpart CC according to the procedures in 40 CFR 63.654(c)-(g).

II.B.13.b.2 Recordkeeping:

Records shall be maintained in accordance with 40 CFR 63.654(g), 40 CFR 63.655(i)(5), and
Provision I.S.1 of this permit.

II.B.13.b.3 Reporting:

Reports shall be submitted in accordance with 40 CFR 63.655(e)-(h). There are no additional
reporting requirements for this provision except those specified in Section I of this permit.

Status: In Compliance – See status of condition II.B.13.a.

II.B.14 Conditions on Specific Heaters and Boilers.

II.B.14.a Condition:

The emissions of PM10 from process heaters 8H2, 19H1, 20H2, 20H3, 24H1, and 25H1, and boilers #8,
#9, #10, and #11 shall not exceed:
i. 6.5 tons per year, combined total, based on a daily rolling 365-day sum, and
ii. 0.0070 lb/MMbtu each.
[Origin: DAQE-AN101230057-23]. [R307-401-8]

II.B.14.a.1 Monitoring:

a) To demonstrate compliance with the PM10 BACT limit in II.B.14.a.ii, stack testing to verify
the PM10 emissions shall be performed as specified below:
(1) Frequency: A stack test shall be conducted at least once every three years.
(2) Notification: At least 30 days before the test, the source shall notify the Director of the
date, time, and place of testing and provide a copy of the source test protocol in
accordance with R307-165. The source test protocol shall be approved by the Director
prior to performing the test. A pretest conference between the permittee, the tester, and
the Director shall be held if directed by the Director.
(3) Sample location. The emission point shall conform to the requirements of 40 CFR Part
60, Appendix A, Method 1, or other EPA-approved testing method, as acceptable to the
Director. Occupational Safety and Health Administration (OSHA)-approved access shall
be provided to the test location.
(4) Volumetric Flow Rate: The volumetric flow rate shall be measured using 40 CFR 60,
Appendix A, Method 2, or other EPA approved testing method, as acceptable to the
Director.
(5) Emissions of PM10 shall be determined through use of CTM-039, or other EPA-
approved testing method, as acceptable to the Director. The condensable particle
emissions shall be used for compliance demonstration and for inventory purposes.
(6) Calculations: To determine mass emission rates, 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.
92

(7) The production rate during all compliance testing shall be no less than 90% of the
maximum production rate achieved in the previous three (3) years. If the desired
production rate is not achieved at the time of the test, the maximum production rate shall
be 110% of the tested achieved rate, but not more than the maximum allowable
production rate. This new allowable maximum production rate shall remain in effect
until successfully tested at a higher rate. The permittee shall request a higher production
rate when necessary. Testing at no less than 90% of the higher rate shall be conducted. A
new maximum production rate (110% of the new rate) will then be allowed if the test is
successful. This process may be repeated until the maximum allowable production rate
is achieved.
b) To demonstrate compliance with the PM10 emissions cap in II.B.14.a.i, the permittee shall
calculate and record on a daily basis the daily and 365-day rolling sum PM10 emissions for
each affected process heater and boiler individually and for the combined total of twelve
affected units. The daily PM10 emissions from each affected heater and boiler shall be based
on the emission factor (lb/MMBtu, HHV) from the most recent PM10 stack test at the affected
heater or boiler and its daily fuel consumption (MMBtu/day, HHV). For each day of
operation prior to the initial stack test of a newly-installed boiler or process heater, the BACT
emission factor of 0.0070 lb/MMBtu (HHV) shall be used.

II.B.14.a.2 Recordkeeping:

Results of the daily and 365-day rolling sum calculations shall be kept on a daily basis for each
affected process heater and boiler individually and for the combined total of twelve affected units.
Results of the stack testing shall be recorded and maintained in accordance with the associated
test method. Results of monitoring and any information used to determine compliance shall be
recorded and maintained in accordance with Provision I.S.1 of this permit.

II.B.14.a.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate compliance
status. There are no additional reporting requirements for this provision except those specified in
Section I of this permit.

Status: In Compliance – PM10 Stack Testing for the heaters and boilers was conducted on July 17, 2024.
Results of the Stack Test was .001095042 Tons/Yr.

II.B.14.b Condition:

The emissions of NOx shall not exceed:
i. 0.10 lb/MMBtu from process heater 12H1
ii. 0.02 lb/MMBtu each, from boilers #5, #8, #9, #10, #11
iii. 0.04 lb/MMBtu each, from process heaters 8H2, 20H3, 24H1, and 25H1.
[Origin: DAQE-AN101230057-23]. [R307-401-8]

II.B.14.b.1 Monitoring:

To demonstrate compliance, stack testing to verify the NOx emissions shall be performed on each
affected emission unit as specified below:
a) Frequency: A stack test shall be conducted at least once every three years.
b) Notification: At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the source test protocol in accordance with
93

R307-165. The source test protocol shall be approved by the Director prior to performing the
test. A pretest conference between the permittee, the tester, and the Director shall be held if
directed by the Director.
c) Sample location. The emission point shall conform to the requirements of 40 CFR Part 60,
Appendix A, Method 1, or other EPA-approved testing method, as acceptable to the Director.
Occupational Safety and Health Administration (OSHA)-approved access shall be provided to
the test location.
d) Volumetric Flow Rate: The volumetric flow rate shall be measured using 40 CFR 60,
Appendix A, Method 2, or other EPA approved testing method, as acceptable to the Director.
e) Emissions of NOx shall be measured using 40 CFR 60, Appendix A, Method 7E, or other
EPA-approved testing method, as acceptable to the Director.
f) Calculations: To determine mass emission rates, 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.
g) The production rate during all compliance testing shall be no less than 90% of the maximum
production rate achieved in the previous three (3) years. If the desired production rate is not
achieved at the time of the test, the maximum production rate shall be 110% of the tested
achieved rate, but not more than the maximum allowable production rate. This new allowable
maximum production rate shall remain in effect until successfully tested at a higher rate. The
permittee shall request a higher production rate when necessary. Testing at no less than 90%
of the higher rate shall be conducted. A new maximum production rate (110% of the new rate)
will then be allowed if the test is successful. This process may be repeated until the maximum
allowable production rate is achieved.

II.B.14.b.2 Recordkeeping:

Results of the stack testing shall be recorded and maintained in accordance with the associated
test method and Provision I.S.1 of this permit.

II.B.14.b.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate compliance
status. There are no additional reporting requirements for this provision except those specified in
Section I of this permit.

Status: In Compliance – NOx Stack Testing regarding the above process heaters and boilers:

Equipment Date NOx Limits (lb/MMBtu) NOx Results (lb/MMBtu)
Heater 12H1 5/6/2022 0.01 0.054
Boiler #5 2/12/2022 0.02 0.0014
Boiler #8 7/18/2022 0.02 0.013
Boiler #9 5/23/2024 0.02 0.015
Boiler #10 7/7/2022 0.02 0.0059
Boiler #11 11/3/2022 0.02 0.016
Heater 8H2 7/3/2023 0.04 0.06
Retest 8/17/2023 0.04 0.035
Heater 20H3 4/29/2022 0.04 0.033
Heater 24H1 5/11/2022 0.04 0.025
Heater 25H1 6/2/2022 0.04 0.04

94

II.B.14.c Condition:

The emissions of CO shall not exceed:
i. 0.040 lb/MMBtu each, from process heaters 19H1, 20H3, 24H1, and 25H1
ii. 0.037 lb/MMBtu from boiler #11.
[Origin: DAQE-AN101230057-23]. [R307-401-8]

II.B.14.c.1 Monitoring:

To demonstrate compliance, stack testing to verify the CO emissions shall be performed on each
affected emission unit as specified below:
a) Frequency: A stack test shall be conducted at least once every three years.
b) Notification: At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the source test protocol in accordance with
R307-165. The source test protocol shall be approved by the Director prior to performing the
test. A pretest conference between the permittee, the tester, and the Director shall be held if
directed by the Director.
c) Sample location. The emission point shall conform to the requirements of 40 CFR Part 60,
Appendix A, Method 1, or other EPA-approved testing method, as acceptable to the Director.
Occupational Safety and Health Administration (OSHA)-approved access shall be provided to
the test location.
d) Volumetric Flow Rate: The volumetric flow rate shall be measured using 40 CFR 60,
Appendix A, Method 2, or other EPA approved testing method, as acceptable to the Director.
e) Emissions of CO shall be measured using 40 CFR 60, Appendix A, Method 10, or other EPA-
approved testing method, as acceptable to the Director.
f) Calculations: To determine mass emission rates, 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.
g) The production rate during all compliance testing shall be no less than 90% of the maximum
production rate achieved in the previous three (3) years. If the desired production rate is not
achieved at the time of the test, the maximum production rate shall be 110% of the tested
achieved rate, but not more than the maximum allowable production rate. This new allowable
maximum production rate shall remain in effect until successfully tested at a higher rate. The
permittee shall request a higher production rate when necessary. Testing at no less than 90%
of the higher rate shall be conducted. A new maximum production rate (110% of the new rate)
will then be allowed if the test is successful. This process may be repeated until the maximum
allowable production rate is achieved.

II.B.14.c.2 Recordkeeping:

Results of the stack testing shall be recorded and maintained in accordance with the associated
test method and Provision I.S.1 of this permit.

II.B.14.c.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate compliance
status. There are no additional reporting requirements for this provision except those specified in
Section I of this permit.

Status: In Compliance – CO Stack Testing regarding the above process heaters and boiler:
95

Equipment Date CO Limits (lb/MMBtu) CO Results (lb/MMBtu)
Heater 19H1 5/24/2024 0.040 0.00030
Heater 20H3 4/29/2022 0.040 0.000104
Heater 24H1 5/11/2022 0.040 0.00
Heater 25H1 6/2/2022 0.040 0.04
Boiler #11 11/3/2022 0.037 0.0088

II.B.14.d Condition:

The emissions of VOC shall not exceed:
i. 0.0054 lb/MMBtu each, from process heaters 20H3, 24H1, and 25H1
ii. 0.004 lb/MMBtu from boiler #11.
[Origin: DAQE-AN101230057-23]. [R307-401-8]

II.B.14.d.1 Monitoring:

To demonstrate compliance, stack testing to verify the VOC emissions shall be performed on
each affected emission unit as specified below:
a) Frequency: A stack test shall be conducted at least once every three years.
b) Notification: At least 30 days before the test, the source shall notify the Director of the date,
time, and place of testing and provide a copy of the source test protocol in accordance with
R307-165. The source test protocol shall be approved by the Director prior to performing the
test. A pretest conference between the permittee, the tester, and the Director shall be held if
directed by the Director.
c) Sample location. The emission point shall conform to the requirements of 40 CFR Part 60,
Appendix A, Method 1, or other EPA-approved testing method, as acceptable to the Director.
Occupational Safety and Health Administration (OSHA)-approved access shall be provided to
the test location.
d) Volumetric Flow Rate: The volumetric flow rate shall be measured using 40 CFR 60,
Appendix A, Method 2, or other EPA approved testing method, as acceptable to the Director.
e) Emissions of VOC shall be measured using 40 CFR 60, Appendix A, Method 25a, or other
EPA-approved testing method, as acceptable to the Director.
f) Calculations: To determine mass emission rates, 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.
g) The production rate during all compliance testing shall be no less than 90% of the maximum
production rate achieved in the previous three (3) years. If the desired production rate is not
achieved at the time of the test, the maximum production rate shall be 110% of the tested
achieved rate, but not more than the maximum allowable production rate. This new allowable
maximum production rate shall remain in effect until successfully tested at a higher rate. The
permittee shall request a higher production rate when necessary. Testing at no less than 90%
of the higher rate shall be conducted. A new maximum production rate (110% of the new rate)
will then be allowed if the test is successful. This process may be repeated until the maximum
allowable production rate is achieved.

II.B.14.d.2 Recordkeeping:

Results of the stack testing shall be recorded and maintained in accordance with the associated
test method and Provision I.S.1 of this permit.
96

II.B.14.d.3 Reporting:

The results of stack testing shall be submitted to the Director within 60 days of completion of the
testing. Reports shall clearly identify results as compared to permit limits and indicate compliance
status. There are no additional reporting requirements for this provision except those specified in
Section I of this permit.

Status: In Compliance – VOC Stack Testing regarding the above process heaters and boiler:

Equipment Date VOC Limits (lb/MMBtu) VOC Results (lb/MMBtu)
Heater 20H3 4/1/2024 0.0054 0.00076
Heater 24H1 4/2/2024 0.0054 0.00011
Heater 25H1 4/3/2024 0.0054 0.0015
Boiler #11 11/3/2022 0.004 0.0014

II.B.14.e Condition:

For Boilers #8, #9, #10, #11:
In accordance with 40 CFR 60.48c(g), the permittee shall maintain records of the amount of each fuel
combusted during each calendar month. [Origin: 40 CFR 60 Subpart Dc]. [40 CFR 60.48c(g)]

II.B.14.e.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.14.e.2 Recordkeeping:

Records of the amounts of each fuel combusted shall be kept on a monthly basis in accordance
with 40 CFR 60.48c(g) and shall be maintained as described in Provision I.S of this permit.

II.B.14.e.3 Reporting:

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

Status: Not Evaluated – This is considered to be a new condition. According to HF Sinclair the monthly
fuel gas tracking, regarding the above boilers will commence before the next inspection.

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.

97

SECTION III: PERMIT SHIELD

A permit shield was not granted for any specific requirements.

SECTION IV: ACID RAIN PROVISIONS

This source is not subject to Title IV. This section is not applicable.

EMISSION INVENTORY: The 2023 Annual Emissions Inventory was submitted, to the DAQ, on April 15, 2024.
The 2024 Annual Emission Inventory will be due by April 15, 2025.

PREVIOUS ENFORCEMENT
ACTIONS:

None within the last five years.

COMPLIANCE STATUS &
RECOMMENDATIONS:
In Compliance with the conditions of the Title V Operating Permit
1100013001, dated May 3, 2024, and revised May 3, 2024, at time of the
inspection.

COMPLIANCE ASSISTANCE: 1) Reviewed Title V Permitting reporting – New Title V Permit
2) Discussed conditions II.B.1.e and II.B.1.f, regarding FDCP – New Title V Permit
3) Discussed condition II.B.1.j, regarding abrasive blasting – New Title V Permit
4) Discussed conditions II.B.1.h and II.B.1.k, regarding degreasing – New Title V
Permit
5) Discussed condition II.B.14.e, regarding fuel gas tracking records – New Title V
Permit

HPV STATUS: Non-Applicable

98

RECOMMENDATION FOR NEXT
INSPECTION:

Inspect as usual.
ATTACHMENTS: VEO Form
Correspondence
Incident Reports

3/14/23, 5:01 PM State of Utah Mail - Fwd: Holly Refinery March 4th
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f%3A1759720355830411627&simpl=msg-f%3A1759720355…1/3
Joe Rockwell <[e-mail]>
Fwd: Holly Refinery March 4th
3 messages
Harold Burge <[e-mail]>Tue, Mar 7, 2023 at 7:41 AM
To: Joe Rockwell <[e-mail]>
Can you find out what happened here and let me know? Thanks.
---------- Forwarded message ---------
From: Dale Bennion <[e-mail]>
Date: Mon, Mar 6, 2023 at 2:43 PM
Subject: Holly Refinery March 4th
To: [e-mail] <[e-mail]>
Dear Mr. Burge,
I'm not sure why there is any discussion at all about air quality when we have a criminal polluter like Holly
Refinery doing what I witnesses Saturday March 4th, photos aached. One of my photos is date me
stamped 3:50 PM. I was traveling north and the plume stretched nearly to farmington even in the high
winds. I'm sure they thought the high winds would disperse, minimize their crime prey fast. I'm not sure
how long this waste burn off lasted but it was bad!
Thank you,
Dale Bennion
801-814-8275
Roy, Utah
5 attachments
IMG_0124.JPG
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3/14/23, 5:01 PM State of Utah Mail - Fwd: Holly Refinery March 4th
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f%3A1759720355830411627&simpl=msg-f%3A1759720355…2/3
IMG_0127.JPG
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IMG_0128.JPG
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IMG_0118.JPG
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Joe Rockwell <[e-mail]>Tue, Mar 7, 2023 at 2:54 PM
To: Harold Burge <[e-mail]>
Will do.
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
Joe Rockwell <[e-mail]>Thu, Mar 9, 2023 at 3:14 PM
To: Harold Burge <[e-mail]>
Hi Harold -
3/14/23, 5:01 PM State of Utah Mail - Fwd: Holly Refinery March 4th
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f%3A1759720355830411627&simpl=msg-f%3A1759720355…3/3
Talked with Eric Benson the Environmental Manager at the HF Refinery. He explained the reason for the visible emission
from the flare on March 4, 2023.
On February 28, 2023, they started the process of turnaround for half of the plant. On March 2nd, the catalyst of the Gas
Oil Hydrocracker had to be cooled, with a Nitrogen purge, before shutting it down. The flare gas recovery compressor
was turned off so that none of the Nitrogen would be recovered. On March 4th (date of the complaint), the Reformer unit
was brought down. Gas from the Reformer unit was to be captured by a compressor, however the gas overwhelmed the
compressor activating the prv. The gas vapors from the prv were vented to the flare, causing the visible emissions.
The incident will be reported in both the Quarterly CEM Report and the Semi- Annual MACT Report.
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
On Tue, Mar 7, 2023 at 7:41 AM Harold Burge <[e-mail]> wrote:
[Quoted text hidden]
3/14/23, 5:04 PM State of Utah Mail - Fwd: Update - Holly Refinery Smoke on March 4th
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f%3A1759957695091456171&simpl=msg-f%3A1759957695…1/3
Joe Rockwell <[e-mail]>
Fwd: Update - Holly Refinery Smoke on March 4th
4 messages
Harold Burge <[e-mail]>Thu, Mar 9, 2023 at 10:34 PM
To: Joe Rockwell <[e-mail]>
Comments from our complainant.
Sent from my iPhone
Begin forwarded message:
From: Dale Bennion <[e-mail]>
Date: March 9, 2023 at 7:14:35 PM MST
To: Harold Burge <[e-mail]>
Subject: Re: Update - Holly Refinery Smoke on March 4th
Dear Mr. Burge,
Thank you for your response, I appreciate it. Of course I'd expect some sort of excuse from the
refinery.
My daughter in law works for Utah's DNR out of Hurricane, before that she was on a
commercial fishing boat out of O'ahu Hawaii. The federal government doesn't trust fisherman
to report everything they catch so that was her job. What you just described to me sounds like
the fox guarding the hen house.
It would be interesng to inspect the engineering on this compressor that was overwhelmed.
Also be important to find out how oen this compressor is overwhelmed and same type events
have occurred. This refinery has a history of cung corners.
What would it take to put a State observer in each of these refineries? We have a gas tax, seem
like the natural way to fund it. Is legislaon to do such a thing needed or what? If there was a
State observer present I'd expect incidents like what I saw to be reduced by half right out of the
chute.
To me, if a refinery can't funcon properly (not be a massive polluter, and we know the
dysfunconal history this one,) the State ought to be able to fine them enough that they have
to shut down.
My daughter and her family just moved from Syracuse to Idaho Falls just to have beer air. It
was a good decision they made, their asthma problems have cleared up! I've been contacng
my State Legislators for years about the Great Salt Lake and it finally got low enough that the
State is making serious effort now. We know the serious problems the dry lake bed has
produced. Next we have to get major polluters like Holly under control or shut down.
This cannot be the "Right Place" as Brigham Young said is we don't have reasonable air to
breath.
3/14/23, 5:04 PM State of Utah Mail - Fwd: Update - Holly Refinery Smoke on March 4th
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f%3A1759957695091456171&simpl=msg-f%3A1759957695…2/3
Thank you,
Dale Bennion
From: Harold Burge <[e-mail]>
Sent: Thursday, March 9, 2023 5:30 PM
To: [e-mail] <[e-mail]>
Subject: Update - Holly Refinery Smoke on March 4th

Here's an update on what my inspector found out. When the written reports are received they will be
reviewed to determine what compliance actions need to be taken.
On Thu, Mar 9, 2023 at 3:14 PM Joe Rockwell <[e-mail]> wrote:
Hi Harold -
Talked with Eric Benson the Environmental Manager at the HF Refinery. He explained the reason for the
visible emission from the flare on March 4, 2023.
On February 28, 2023, they started the process of turnaround for half of the plant. On March 2nd, the
catalyst of the Gas Oil Hydrocracker had to be cooled, with a Nitrogen purge, before shutting it down.
The flare gas recovery compressor was turned off so that none of the Nitrogen would be recovered. On
March 4th (date of the complaint), the Reformer unit was brought down. Gas from the Reformer unit was
to be captured by a compressor, however the gas overwhelmed the compressor activating the prv. The
gas vapors from the prv were vented to the flare, causing the visible emissions.
The incident will be reported in both the Quarterly CEM Report and the Semi- Annual MACT Report.
Joe Rockwell <[e-mail]>Mon, Mar 13, 2023 at 11:51 AM
To: Harold Burge <[e-mail]>
Thanks Harold.
Is there anything else we need to do regarding this complaint?
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
Harold Burge <[e-mail]>Tue, Mar 14, 2023 at 7:56 AM
To: Joe Rockwell <[e-mail]>
We just need to review what the refinery sends in to see if there was a violation or not.
Sent from my iPhone
On Mar 13, 2023, at 11:51 AM, Joe Rockwell <[e-mail]> wrote:
3/14/23, 5:04 PM State of Utah Mail - Fwd: Update - Holly Refinery Smoke on March 4th
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f%3A1759957695091456171&simpl=msg-f%3A1759957695…3/3
[Quoted text hidden]
Joe Rockwell <[e-mail]>Tue, Mar 14, 2023 at 11:46 AM
To: Harold Burge <[e-mail]>
Sounds good.
Thanks Harold,
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
Joe Rockwell <[e-mail]>
Fwd: Incident Number: 00018527 - WEST BOUNTIFUL - West Bountiful/Davis Co -
SO2 Release
5 messages
Harold Burge <[e-mail]>Tue, May 14, 2024 at 6:55 AM
To: Joe Rockwell <[e-mail]>
We also got a Holly SO2 spill report earlier yesterday morning. Not sure if they’re related. Could you contact Holly and
see if anything happened yesterday?
Sent from my iPhone
Begin forwarded message:
From: Jay Morris <[e-mail]>
Date: May 13, 2024 at 2:24:05 PM MDT
To: Harold Burge <[e-mail]>, Rik Ombach <[e-mail]>
Subject: Fwd: Incident Number: 00018527 - WEST BOUNTIFUL - West Bountiful/Davis Co - SO2
Release
FYI - Harold, please let Rik know if you receive any correspondence from the refinery on this incident.
Thanks!
Jay Morris
Assistant Director
Email: [e-mail]
Phone: Office [phone]
Main Office: [phone]
airquality.utah.gov
Emails to and from this email address may be considered public records and thus subject to Utah GRAMA
requirements.
---------- Forwarded message ---------
From: Spills Do Not Reply <[e-mail]>
Date: Mon, May 13, 2024 at 8:46 AM
Subject: Incident Number: 00018527 - WEST BOUNTIFUL - West Bountiful/Davis Co - SO2 Release
To: [e-mail] <[e-mail]>, [e-mail] <[e-mail]>,
[e-mail] <[e-mail]>, eqerrincidentnotification@
utah.gov <[e-mail]>
This is a new spill report case : 00018527
1/16/25, 4:37 PM State of Utah Mail - Fwd: Incident Number: 00018527 - WEST BOUNTIFUL - West Bountiful/Davis Co - SO2 Release
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1799032724081338710&simpl=msg-f:17990327240813387…1/3
Title / Event Name: West Bountiful/Davis Co - SO2 Release
Date / Time Reported: 5/13/2024, 3:00 AM
FYI - Any map location shown is approximate.
Click the following Google Map link to view the incident location:
Latitude = 40.884507000000575
Longitude = -111.91060800000322
Google Map:
https://www.google.com/maps/search/?api=1&query=40.884507000000575,-111.91060800000322
SPILLREPORT-00018527.pdf
19K
Joe Rockwell <[e-mail]>Tue, May 14, 2024 at 10:46 AM
To: Harold Burge <[e-mail]>
Will Do.
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
Harold Burge <[e-mail]>Tue, May 14, 2024 at 10:56 AM
To: Joe Rockwell <[e-mail]>
Thanks.
[Quoted text hidden]
Joe Rockwell <[e-mail]>Tue, May 14, 2024 at 11:48 AM
To: Harold Burge <[e-mail]>
1/16/25, 4:37 PM State of Utah Mail - Fwd: Incident Number: 00018527 - WEST BOUNTIFUL - West Bountiful/Davis Co - SO2 Release
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1799032724081338710&simpl=msg-f:17990327240813387…2/3
According to Travis Smith (Environmental Specialist w/ HF Sinclair) their substation failed, causing multiple units to go
down. This caused excess SO2 emissions to be released into the atmosphere, resulting in increased flaring. This is
probably when the complaint was filled.
Currently the refinery is working on getting the units back on-line. They are also currently determining if the root cause of
the power failure was an internal or external failure. The DEQ 24-hour Hotline has been contacted and there are plans to
submit a report within 14 days of the incident.
Yes. The flaring complaint and the SO2 release incident are related.
Harold, do I need to do anything else? Or just wait for their emergency / breakdown report ?
Thanks,

Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
Harold Burge <[e-mail]>Tue, May 14, 2024 at 12:17 PM
To: Joe Rockwell <[e-mail]>
That’s great. Thanks.
Sent from my iPhone
On May 14, 2024, at 11:48 AM, Joe Rockwell <[e-mail]> wrote:
[Quoted text hidden]
1/16/25, 4:37 PM State of Utah Mail - Fwd: Incident Number: 00018527 - WEST BOUNTIFUL - West Bountiful/Davis Co - SO2 Release
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1799032724081338710&simpl=msg-f:17990327240813387…3/3
Joe Rockwell <[e-mail]>
HF Sinclair Woods Cross Refining LLC - Requested Info
2 messages
Benson, Eric <[e-mail]>Tue, Jul 23, 2024 at 9:50 AM
To: Joe Rockwell <[e-mail]>
Joe,

From your onsite visit on 7/22/24, here is the request we submitted on May 17, 2024, to modify our AO AN101230057-23
with the add in voluntary lower limit for the SRU SO2.

Thank you,

Eric Benson
Manager | Environmental

O 801-299-6623
M 801-414-7872

[e-mail]
www.HFSinclair.com
1070 West 500 South, West Bountiful, UT 84087

CONFIDENTIALITY NOTICE: This e-mail, and any attachments, may contain information that is privileged and
confidential.If you received this message in error, please advise the sender immediately by reply e-mail and do not
retain any paper or electronic copies of this message or any attachments.Unless expressly stated, nothing contained in
this message should be construed as a digital or electronic signature or a commitment to a binding agreement.
240517 AO AN101230057-23 Subpart Ja SRU SO2 Limit Voluntary Reduction_.pdf
820K
Joe Rockwell <[e-mail]>Tue, Jul 23, 2024 at 4:12 PM
To: "Benson, Eric" <[e-mail]>
1/16/25, 4:24 PM State of Utah Mail - HF Sinclair Woods Cross Refining LLC - Requested Info
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1805385572187100903&simpl=msg-f:18053855721871009…1/2
Thanks Eric.
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
1/16/25, 4:24 PM State of Utah Mail - HF Sinclair Woods Cross Refining LLC - Requested Info
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1805385572187100903&simpl=msg-f:18053855721871009…2/2
Joe Rockwell <[e-mail]>
Clarification of Applicability - TV Condition II.B.6.c.i - Tan 129
3 messages
Benson, Eric <[e-mail]>Tue, Jul 23, 2024 at 10:40 AM
To: Joe Rockwell <[e-mail]>
Joe,

From our discussion during your site inspection on July 23, 2024. I am sending you a copy of the letter HF Sinclair
Woods Cross Refining LLC submitted to UDAQ on May 17, 2024 regarding Tank 129’s applicability to R307-327-4(1) and
Condition II.B.6.c.i of HF Sinclair’s Title V Permit.

Thank you,

Eric Benson
Manager | Environmental

O 801-299-6623
M 801-414-7872

[e-mail]
www.HFSinclair.com
1070 West 500 South, West Bountiful, UT 84087

CONFIDENTIALITY NOTICE: This e-mail, and any attachments, may contain information that is privileged and
confidential.If you received this message in error, please advise the sender immediately by reply e-mail and do not
retain any paper or electronic copies of this message or any attachments.Unless expressly stated, nothing contained in
this message should be construed as a digital or electronic signature or a commitment to a binding agreement.
240517 Clarification of Applicability R307-327-4(1) Tank 129.pdf
3282K
Joe Rockwell <[e-mail]>Tue, Jul 23, 2024 at 4:25 PM
To: "Benson, Eric" <[e-mail]>
1/16/25, 4:26 PM State of Utah Mail - Clarification of Applicability - TV Condition II.B.6.c.i - Tan 129
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1805388861577481938&simpl=msg-f:18053888615774819…1/3
Thanks Eric. See you Thursday.
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
Benson, Eric <[e-mail]>Wed, Jul 24, 2024 at 12:50 PM
To: Joe Rockwell <[e-mail]>
Joe,

We will be bringing online one of our units starting Wednesday, July 24, evening into most of the day on Thursday, July
25. There will be an exclusion zone that extends into about half of the refinery. That means we won’t have access to
about half of the refinery on Thursday for your field walk. This may impact what you are wanting to look at. We can
reschedule the field portion for Friday or next Monday if you’d like.

Let me know.

Thank you,

Eric Benson
Manager | Environmental

O 801-299-6623
M 801-414-7872

[e-mail]
www.HFSinclair.com
1070 West 500 South, West Bountiful, UT 84087

1/16/25, 4:26 PM State of Utah Mail - Clarification of Applicability - TV Condition II.B.6.c.i - Tan 129
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1805388861577481938&simpl=msg-f:18053888615774819…2/3

From: Joe Rockwell <[e-mail]>
Sent: Tuesday, July 23, 2024 4:26 PM
To: Benson, Eric <[e-mail]>
Subject: Clarification of Applicability - TV Condition II.B.6.c.i - Tan 129

CAUTION: This email originated from outside of the HF Sinclair organization. Do not click on
links or open attachments unless you recognize the sender and know the content is safe.
[Quoted text hidden]
[Quoted text hidden]
1/16/25, 4:26 PM State of Utah Mail - Clarification of Applicability - TV Condition II.B.6.c.i - Tan 129
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1805388861577481938&simpl=msg-f:18053888615774819…3/3
Joe Rockwell <[e-mail]>
Breakdown Report - UDAQ April 17, 2023
2 messages
Benson, Eric <[e-mail]>Thu, Jul 25, 2024 at 9:51 AM
To: Joe Rockwell <[e-mail]>
Joe,

Here is a copy of the Breakdown Report that HF Sinclair Woods Cross Refining LLC submitted to UDAQ for an power
failure that occurred on April 3, 2023.

Eric Benson
Manager | Environmental

O 801-299-6623
M 801-414-7872

[e-mail]
www.HFSinclair.com
1070 West 500 South, West Bountiful, UT 84087

CONFIDENTIALITY NOTICE: This e-mail, and any attachments, may contain information that is privileged and
confidential.If you received this message in error, please advise the sender immediately by reply e-mail and do not
retain any paper or electronic copies of this message or any attachments.Unless expressly stated, nothing contained in
this message should be construed as a digital or electronic signature or a commitment to a binding agreement.
230417 Breakdown Incident Report - Refinery Power Outage (230403).pdf
407K
Joe Rockwell <[e-mail]>Fri, Jul 26, 2024 at 11:27 AM
To: "Benson, Eric" <[e-mail]>
1/16/25, 4:27 PM State of Utah Mail - Breakdown Report - UDAQ April 17, 2023
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1805566790711341838&simpl=msg-f:18055667907113418…1/2
Eric,
Thank you for the April 3, 2023, Breakdown Report.
No problems regarding the exclusion zone and the inspection yesterday.

Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
1/16/25, 4:27 PM State of Utah Mail - Breakdown Report - UDAQ April 17, 2023
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1805566790711341838&simpl=msg-f:18055667907113418…2/2
Joe Rockwell <[e-mail]>
SO2 Flaring Event Complaint Correspondence - May 14, 2024
3 messages
Joe Rockwell <[e-mail]>Fri, Jul 26, 2024 at 11:42 AM
To: [e-mail]
Eric,
Attached is the May 14, 2024, email correspondence regarding the May 13, 2024, SO2 flaring complaint / incident .
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
State of Utah Mail - HF Sinclair Refinery - Fwd_ Incident Number_ 00018527 - WEST BOUNTIFUL - West
Bountiful_Davis Co - SO2 Release.pdf
230K
Benson, Eric <[e-mail]>Wed, Jul 31, 2024 at 3:30 PM
To: Joe Rockwell <[e-mail]>
Hi Joe,

It occurred to me that I hadn’t sent you the supporting documentation for condition II.B.1.v (40 CFR 63 Subpart GGGGG)
– Site Remediation MACT.

I have attached the internal evaluation and Letter to File I this email.

Please let me know if you have any questions.

Thank you,

Eric Benson
1/16/25, 4:29 PM State of Utah Mail - SO2 Flaring Event Complaint Correspondence - May 14, 2024
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-a:r-2392480069960629301&simpl=msg-a:r-14290858471515…1/3
Manager | Environmental

O 801-299-6623
M 801-414-7872

[e-mail]
www.HFSinclair.com
1070 West 500 South, West Bountiful, UT 84087

From: Joe Rockwell <[e-mail]>
Sent: Friday, July 26, 2024 11:43 AM
To: Benson, Eric <[e-mail]>
Subject: SO2 Flaring Event Complaint Correspondence - May 14, 2024

CAUTION: This email originated from outside of the HF Sinclair organization. Do not click on
links or open attachments unless you recognize the sender and know the content is safe.
[Quoted text hidden]
CONFIDENTIALITY NOTICE: This e-mail, and any attachments, may contain information that is privileged and
confidential.If you received this message in error, please advise the sender immediately by reply e-mail and do not
retain any paper or electronic copies of this message or any attachments.Unless expressly stated, nothing contained in
this message should be construed as a digital or electronic signature or a commitment to a binding agreement.
240202 2023 HF Sinclair Woods Cross Refining LLC_LTF_GGGGG Applicability Evaluation and Table.pdf
1149K
Joe Rockwell <[e-mail]>Fri, Aug 2, 2024 at 11:10 AM
To: "Benson, Eric" <[e-mail]>
Thanks Eric.
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

1/16/25, 4:29 PM State of Utah Mail - SO2 Flaring Event Complaint Correspondence - May 14, 2024
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-a:r-2392480069960629301&simpl=msg-a:r-14290858471515…2/3
Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
1/16/25, 4:29 PM State of Utah Mail - SO2 Flaring Event Complaint Correspondence - May 14, 2024
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-a:r-2392480069960629301&simpl=msg-a:r-14290858471515…3/3
Joe Rockwell <[e-mail]>
RMP Power Outage - Monday, September 23, 2024
4 messages
Benson, Eric <[e-mail]>Thu, Sep 26, 2024 at 11:52 AM
To: Joe Rockwell <[e-mail]>
Joe, I attached the links to the ABC4 Utah and KSL news articles.

Over 8,000 without power in Davis County (abc4.com)

https://www.ksl.com/article/51136535/substation-fire-knocked-out-power-for-more-than-8000-customers-in-davis-county

Eric Benson
Manager | Environmental

O 801-299-6623
M 801-414-7872

[e-mail]
www.HFSinclair.com
1070 West 500 South, West Bountiful, UT 84087

CONFIDENTIALITY NOTICE: This e-mail, and any attachments, may contain information that is privileged and
confidential.If you received this message in error, please advise the sender immediately by reply e-mail and do not
retain any paper or electronic copies of this message or any attachments.Unless expressly stated, nothing contained in
this message should be construed as a digital or electronic signature or a commitment to a binding agreement.
Joe Rockwell <[e-mail]>Thu, Sep 26, 2024 at 12:03 PM
To: "Benson, Eric" <[e-mail]>
I guess I will be receiving an incident report.
Thanks Eric.
1/16/25, 4:30 PM State of Utah Mail - RMP Power Outage - Monday, September 23, 2024
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1811282054036280210&simpl=msg-f:18112820540362802…1/3
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
Benson, Eric <[e-mail]>Fri, Sep 27, 2024 at 4:33 PM
To: Joe Rockwell <[e-mail]>
That’s correct.

Also, do you have a couple of minutes on Monday, September 30, to help us clarify a couple things regarding TV
deviation reports?

My schedule is pretty open. Just let me know what works best for you.

Thank you,

Eric Benson
Manager | Environmental

O 801-299-6623
M 801-414-7872

[e-mail]
www.HFSinclair.com
1070 West 500 South, West Bountiful, UT 84087

1/16/25, 4:30 PM State of Utah Mail - RMP Power Outage - Monday, September 23, 2024
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1811282054036280210&simpl=msg-f:18112820540362802…2/3
From: Joe Rockwell <[e-mail]>
Sent: Thursday, September 26, 2024 12:03 PM
To: Benson, Eric <[e-mail]>
Subject: RMP Power Outage - Monday, September 23, 2024

CAUTION: This email originated from outside of the HF Sinclair organization. Do not click on
links or open attachments unless you recognize the sender and know the content is safe.
[Quoted text hidden]
[Quoted text hidden]
Joe Rockwell <[e-mail]>Fri, Sep 27, 2024 at 9:16 PM
To: "Benson, Eric" <[e-mail]>
Sure, no problem. My schedule is open on Monday. Just call me when you get a minute.
Thanks Eric,
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
1/16/25, 4:30 PM State of Utah Mail - RMP Power Outage - Monday, September 23, 2024
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1811282054036280210&simpl=msg-f:18112820540362802…3/3
Joe Rockwell <[e-mail]>
Breakdown Notification - 9/27/2024
2 messages
Benson, Eric <[e-mail]>Fri, Sep 27, 2024 at 4:41 PM
To: Joe Rockwell <[e-mail]>
Cc: "Smith, F Travis" <[e-mail]>
Joe,

I tried to call the general UDAQ #801-536-4000 to report a breakdown, and got to a voicemail. I decided to notify you via
email, as allowed by R307-107-1(1).

We had a breakdown of a gas compressor, 19K4, that resulted in the following excess emissions that are not covered by
provision R307-107-1(3):

Source:
North Flare
Limit:
1. Opacity >20%.
2. Visible emissions >5 mins in a 2 hour consecutive period.

Source:
South Flare
Limit:
1. Opacity >20%.

We will be submitting a breakdown report within 14 days of the onset of the incident.

Please let me know if you have any questions.

Thank you,

Eric Benson
Manager | Environmental

O 801-299-6623
1/16/25, 4:31 PM State of Utah Mail - Breakdown Notification - 9/27/2024
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1811390840228706521&simpl=msg-f:18113908402287065…1/2
M 801-414-7872

[e-mail]
www.HFSinclair.com
1070 West 500 South, West Bountiful, UT 84087

CONFIDENTIALITY NOTICE: This e-mail, and any attachments, may contain information that is privileged and
confidential.If you received this message in error, please advise the sender immediately by reply e-mail and do not
retain any paper or electronic copies of this message or any attachments.Unless expressly stated, nothing contained in
this message should be construed as a digital or electronic signature or a commitment to a binding agreement.
Joe Rockwell <[e-mail]>Fri, Sep 27, 2024 at 9:26 PM
To: "Benson, Eric" <[e-mail]>
Thanks Eric.
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
1/16/25, 4:31 PM State of Utah Mail - Breakdown Notification - 9/27/2024
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1811390840228706521&simpl=msg-f:18113908402287065…2/2
Joe Rockwell <[e-mail]>
Breakdown Notification - 10/17/2024
2 messages
Smith, F Travis <[e-mail]>Thu, Oct 17, 2024 at 3:37 PM
To: "[e-mail]" <[e-mail]>
Cc: "Benson, Eric" <[e-mail]>
Joe,

I tried the general UDAQ #801-536-4000 (at 14:06) to make an initial notification for a release in excess of a reportable
quantity of SO2. The person who answered attempted to transfer me to the Compliance Section, but it went to the
voicemail of a name I could not understand. I decided to notify you via email, as allowed by R307-107-1(1).

An external power supply sag, confirmed by Rocky Mountain Power, occurred approximately 6:30 am. Multiple process
units in the refinery entered a state of upset, as a result. This breakdown resulted in excess emissions estimated to be
538 lbs of SO2 above our permitted site cap of 0.31 tons (620 lbs SO2) from the North Flare (66-2) and South Flare (66-
1) combined.
We will be submitting a follow-up report within 14 days of the onset of the incident.
Please let me know if you have any questions.
F. Travis Smith
Environmental Specialist | Environmental

O 801-299-6625
M 801-647-8432

[e-mail]
www.HFSinclair.com

1070 West 500 South, West Bountiful, UT 84087

CONFIDENTIALITY NOTICE: This e-mail, and any attachments, may contain information that is privileged and
confidential.If you received this message in error, please advise the sender immediately by reply e-mail and do not
retain any paper or electronic copies of this message or any attachments.Unless expressly stated, nothing contained in
this message should be construed as a digital or electronic signature or a commitment to a binding agreement.
1/16/25, 4:38 PM State of Utah Mail - Breakdown Notification - 10/17/2024
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1813198729638343552&simpl=msg-f:18131987296383435…1/2
Joe Rockwell <[e-mail]>Mon, Oct 21, 2024 at 11:35 AM
To: "Smith, F Travis" <[e-mail]>
Travis -
Thanks for Friday's phone discussions regarding breakdown Reports.
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
1/16/25, 4:38 PM State of Utah Mail - Breakdown Notification - 10/17/2024
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1813198729638343552&simpl=msg-f:18131987296383435…2/2
Joe Rockwell <[e-mail]>
HF Sinclair Woods Cross September 2024 Breakdown Reports
2 messages
Smith, F Travis <[e-mail]>Fri, Oct 18, 2024 at 2:24 PM
To: Joe Rockwell <[e-mail]>
Cc: "Benson, Eric" <[e-mail]>
1/16/25, 4:38 PM State of Utah Mail - HF Sinclair Woods Cross September 2024 Breakdown Reports
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1813284891361406192&simpl=msg-f:18132848913614061…1/3
Joe,

Attached are the two Breakdown Reports from September that we spoke about on the phone. The first was submitted to
UDAQ, via Certified Mail, on 10/7/24, and the second on 10/10/24.

Thank you,

F. Travis Smith
Environmental Specialist | Environmental

O 801-299-6625
M 801-647-8432

[e-mail]
www.HFSinclair.com

1070 West 500 South, West Bountiful, UT 84087

CONFIDENTIALITY NOTICE: This e-mail, and any attachments, may contain information that is privileged and
confidential.If you received this message in error, please advise the sender immediately by reply e-mail and do not
retain any paper or electronic copies of this message or any attachments.Unless expressly stated, nothing contained in
this message should be construed as a digital or electronic signature or a commitment to a binding agreement.
2 attachments
241007 240923 UDAQ Breakdown Written Followup and Appendix A.pdf
3758K
241010 240927 UDAQ Breakdown Written Followup and Appendix A.pdf
3239K
Joe Rockwell <[e-mail]>Mon, Oct 21, 2024 at 11:08 AM
To: "Smith, F Travis" <[e-mail]>
Travis -
Thanks for emailing me the September 23 and 27, 2024, Breakdown Reports.
Would you please email the October 17, 2024, Breakdown Report after you receive the Certified Mail Delivery Notice.
Just like the September Breakdown Reports.
1/16/25, 4:38 PM State of Utah Mail - HF Sinclair Woods Cross September 2024 Breakdown Reports
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1813284891361406192&simpl=msg-f:18132848913614061…2/3
Thanks Again,
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
1/16/25, 4:38 PM State of Utah Mail - HF Sinclair Woods Cross September 2024 Breakdown Reports
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1813284891361406192&simpl=msg-f:18132848913614061…3/3
Joe Rockwell <[e-mail]>
Breakdown Notification - 10/21/2024
2 messages
Smith, F Travis <[e-mail]>Mon, Oct 21, 2024 at 3:33 PM
To: Joe Rockwell <[e-mail]>
Cc: "Benson, Eric" <[e-mail]>
Joe,

This is an initial notification to report a breakdown, via email, as allowed by R307-107-1(1). Additionally, I called DAQ at
[phone] at 15:20 and spoke with Rick Ombach.

We had a breakdown of a gas compressor, 4K81, that resulted in the following excess emissions that are not covered by
provision R307-107-1(3):

Source:

North Flare (66-2)

Limit: Visible emissions >5 mins in a 2 hour consecutive period.

Source:

South Flare (66-1)

Limit: Visible emissions >5 mins in a 2 hour consecutive period.

We will be submitting a breakdown report within 14 days of the onset of the incident.

Please let me know if you have any questions.

Thank you,

F. Travis Smith
Environmental Specialist | Environmental
1/16/25, 4:39 PM State of Utah Mail - Breakdown Notification - 10/21/2024
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1813560891279496593&simpl=msg-f:18135608912794965…1/2

O 801-299-6625
M 801-647-8432

[e-mail]
www.HFSinclair.com

1070 West 500 South, West Bountiful, UT 84087

CONFIDENTIALITY NOTICE: This e-mail, and any attachments, may contain information that is privileged and
confidential.If you received this message in error, please advise the sender immediately by reply e-mail and do not
retain any paper or electronic copies of this message or any attachments.Unless expressly stated, nothing contained in
this message should be construed as a digital or electronic signature or a commitment to a binding agreement.
Joe Rockwell <[e-mail]>Tue, Oct 22, 2024 at 11:07 AM
To: "Smith, F Travis" <[e-mail]>
Travis -
Thanks for sending me the Oct 17 and Oct 21,2024 Breakdown reports.
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
1/16/25, 4:39 PM State of Utah Mail - Breakdown Notification - 10/21/2024
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1813560891279496593&simpl=msg-f:18135608912794965…2/2
Joe Rockwell <[e-mail]>
2023 Emissions Fee - Invoice #250022
2 messages
Benson, Eric <[e-mail]>Tue, Nov 12, 2024 at 12:26 PM
To: Joe Rockwell <[e-mail]>
Cc: "Smith, F Travis" <[e-mail]>
Joe,

Here is a copy of the 2023 Emission Fee Invoice and check that was hand delivered to UDAQ on 9/5/2024.

Eric Benson
Manager | Environmental

O 801-299-6623
M 801-414-7872

[e-mail]
www.HFSinclair.com
1070 West 500 South, West Bountiful, UT 84087

CONFIDENTIALITY NOTICE: This e-mail, and any attachments, may contain information that is privileged and
confidential.If you received this message in error, please advise the sender immediately by reply e-mail and do not
retain any paper or electronic copies of this message or any attachments.Unless expressly stated, nothing contained in
this message should be construed as a digital or electronic signature or a commitment to a binding agreement.
2023 Emissions Invoice and Check_Stamped.pdf
472K
Joe Rockwell <[e-mail]>Tue, Nov 12, 2024 at 2:37 PM
To: "Benson, Eric" <[e-mail]>
Cc: [e-mail]
1/16/25, 4:32 PM State of Utah Mail - 2023 Emissions Fee - Invoice #250022
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1815546010751144346&simpl=msg-f:18155460107511443…1/2
Thanks Eric.
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
1/16/25, 4:32 PM State of Utah Mail - 2023 Emissions Fee - Invoice #250022
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1815546010751144346&simpl=msg-f:18155460107511443…2/2
Joe Rockwell <[e-mail]>
Title V Condition II.B.4.j Question
3 messages
Joe Rockwell <[e-mail]>Thu, Jan 16, 2025 at 2:12 PM
To: [e-mail], [e-mail]
Hi Eric and Travis -
Hope things are good.
I have a quick question regarding condition II.B.4.j of your TV Permit.
When did the DAQ receive the Initial Notice for the 540 hp diesel engine?
Thank you,
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
Smith, F Travis <[e-mail]>Thu, Jan 16, 2025 at 2:38 PM
To: Joe Rockwell <[e-mail]>, "Benson, Eric" <[e-mail]>
Joe,

Please find attached the requested info on the 540 hp diesel generator. It was submitted via certified mail on
2/18/2016 and received by UDAQ on 2/22/2016, per the return receipt.

Thank you,

F. Travis Smith
Environmental Specialist | Environmental

O 801-299-6625
M 801-647-8432

1/16/25, 4:17 PM State of Utah Mail - Title V Condition II.B.4.j Question
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-a:r277489984580676657&simpl=msg-a:r-132376695246591…1/3
[e-mail]
www.HFSinclair.com

1070 West 500 South, West Bountiful, UT 84087

From: Joe Rockwell <[e-mail]>
Sent: Thursday, January 16, 2025 2:13 PM
To: Benson, Eric <[e-mail]>; Smith, F Travis <[e-mail]>
Subject: Title V Condion II.B.4.j Queson

CAUTION: This email originated from outside of the HF Sinclair organization. Do not click on
links or open attachments unless you recognize the sender and know the content is safe.

Hi Eric and Travis -

Hope things are good.

I have a quick question regarding condition II.B.4.j of your TV Permit.
When did the DAQ receive the Initial Notice for the 540 hp diesel engine?

Thank you,
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
CONFIDENTIALITY NOTICE: This e-mail, and any attachments, may contain information that is privileged and
confidential.If you received this message in error, please advise the sender immediately by reply e-mail and do not
1/16/25, 4:17 PM State of Utah Mail - Title V Condition II.B.4.j Question
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-a:r277489984580676657&simpl=msg-a:r-132376695246591…2/3
retain any paper or electronic copies of this message or any attachments.Unless expressly stated, nothing contained in
this message should be construed as a digital or electronic signature or a commitment to a binding agreement.
160218 NOC 540 hp Diesel Emergency Generator.pdf
1358K
Joe Rockwell <[e-mail]>Thu, Jan 16, 2025 at 2:55 PM
To: "Smith, F Travis" <[e-mail]>
Thanks Travis.
Joe Rockwell | Environmental Scientist
Phone: [phone]

195 North 1950 West, Salt Lake City, UT 84116

Emails to and from this email address may be considered public records and thus subject to Utah GRAMA requirements.
[Quoted text hidden]
1/16/25, 4:17 PM State of Utah Mail - Title V Condition II.B.4.j Question
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-a:r277489984580676657&simpl=msg-a:r-132376695246591…3/3