DAQ-2024-012019

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DAQC-1211-24
Site ID 10355 (B1)

MEMORANDUM

TO: FILE – PACIFICORP ENERGY – Gadsby Power Plant

THROUGH: Harold Burge, Major Source Compliance Section Manager

FROM: Joe Rockwell, Environmental Scientist

DATE: December 4, 2024

SUBJECT: FULL COMPLIANCE EVALUATION, Major, Salt Lake County,
FRS #UT0000004903500068

INSPECTION DATE: November 26, 2024

SOURCE LOCATION: 1359 West North Temple, Salt Lake City, Utah 84116

Enter facility by way of side or rear drive.

MAILING ADDRESS: 1359 West North Temple, Salt Lake City, Utah 84116

SOURCE CONTACTS: Leah Tiberius, Environmental Analyst:
Office: 801-220-7708
Cell: 801-455-6715
[e-mail]

Dale Sherwood, Operations Manager:
Office: [phone]
[e-mail]

Joshua Sewell, Senior Engineer:
Office: [phone]
[e-mail]

OPERATING STATUS: Emission Units (EUs) #1, #2, and #3 were operating at time of the
inspection.

PROCESS DESCRIPTION:

PacifiCorp Gadsby Power Plant:

The electricity-generating plant consists of three natural-gas-fired steam-generating units and three
natural-gas-fired simple cycle combustion turbines. Unit #1 was constructed in 1951. Unit #2 was
operational in 1952. Unit #3 was operational in 1955. The three natural-gas-fired steam generating units
were converted from coal-fired to natural-gas-fired in the 1990s. Three 43.5 MW LM 6000 natural
gas-fueled simple cycle gas turbine engines were added in 2002. The operation of the Gadsby Plant is to
produce electricity for sale via the utility power distribution system and to service electrical demands of
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the Wasatch Front. The fuel systems consist of the natural gas delivery system and the fuel oil system.
Natural gas is the primary fuel for the steam generating units and is the sole fuel for the combustion
turbines. Fuel oil combustion is limited to natural gas curtailment periods and maintenance firings
between April 1 and November 30 of any calendar year. Natural gas enters the plant through a metering
station. A five hundred gallon storage tank is used for diesel-fired equipment. Fuel oil may also be
supplied to the steam generators from trucks or railcars on an as-needed basis.

Steam Generating Units:

Natural gas is combusted in each of the steam generating boilers. Units #1, #2, and #3 are equipped with
low NOx burners. The steam generation process is the primary source of emissions at this plant. Heat
generated from the combustion process is transferred to water that flows through boiler tubes in the walls
of the furnaces. Sufficient heat is generated during the combustion process to produce a quality of steam
suitable for use in the steam turbines. Emissions are generated during the combustion process. The flue
gas exits each furnace and flows through an induced draft fan. The fan discharges the flue gas up the 300
foot stack.

Simple Cycle Combustion Gas Turbines:

Ambient air is ingested and compressed in the compressor section of the turbine engines. Natural gas is
injected into the compressed air and ignited, with combustion and expansion occurring in the turbine
section of each engine. Mechanical energy produced by the combustion process is used to drive an
electric generator connected to the turbine via a common shaft. Pollutants are generated during the
combustion process. The turbine exhaust combustion gas exits the engines and flows through a CO
catalyst, then through a SCR catalyst used for NOx emissions control, and finally through an exhaust
stack prior to discharge to the atmosphere.

APPLICABLE REGULATIONS: Title V Operating Permit (TVOP) #3500068006, dated January
30, 2024, and revised January 30, 2024

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.

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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))

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: In compliance – The Gadsby Power Plant submitted their application for permit
renewal on August 16, 2023. It was submitted before the September 11, 2023, due
date. The permit expires January 30, 2029. Application for renewal is due July 30,
2028.
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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 permit renewal is due July 30, 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 – Payment was made on September 30, 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.

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:
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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 at time of the inspection. 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 – Reports and certifications submitted, by the Gadsby Power Plant,
appeared to have certification statements and were signed by the responsible officials
(RO).

I.L Compliance Certification.

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

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

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

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

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

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

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

Status: In compliance – The 2023 annual compliance certification (ACC) was initially
received on April 1, 2024. The report was revised and deemed acceptable. The revised
report was received on July 25, 2024. The revised report is considered to have been
received on the same date as the initial report, April 1, 2024.

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))

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))

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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)(g) 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: N/A – See Section III of this permit.

I.N Emergency Provision.

I.N.1 An "emergency" is any situation arising from sudden and reasonably unforeseeable events
beyond the control of the source, including acts of God, which situation requires immediate
corrective action to restore normal operation, and that causes the source to exceed a
technology-based emission limitation under this permit, due to unavoidable increases in
emissions attributable to the emergency. An emergency shall not include noncompliance to

the extent caused by improperly designed equipment, lack of preventive maintenance,
careless or improper operation, or operator error. (R307-415-6g(1))

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

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

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

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

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

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

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

Status: In compliance – No emergency events were reported since the last inspection, which
was conducted on January 5, 2024. There have been no more than five Gen 1 Alerts in
2024. None of the alerts have exceeded permit limits.

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))

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.

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

Status: In compliance – All 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:

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

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

Environmental Protection Agency, Region VIII
Office of Partnerships and Regulatory Assistance Air and Radiation Program (mail code
8P-AR)
1595 Wynkoop Street
Denver, CO 80202-1129
Phone: [phone]

Status: In compliance – The six-month monitoring reports for the 2023 ACC were received
on July 28, 2023, and January 25, 2024, and deemed acceptable. The most recent six
month monitoring report was received on July 15, 2024, for the report period
January 1, 2024 - June 30, 2024. No deviation reports were required to be submitted.

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 11, 2024,
before the due date of April 15, 2024. 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 Steam Generating Unit #1 (EU #1)
65 MW electric generator powered by 726 MMBtu/hr capacity natural gas (NG)-fired
utility boiler, equipped with low NOx burners. No. 2 fuel oil may be used as back-up fuel
during NG curtailments and maintenance firings.

II.A.3 Steam Generating Unit #2 (EU #2)
80 MW electric generator powered by 825 MMBtu/hr capacity NG-fired utility boiler,
equipped with low NOx burners. No. 2 fuel oil may be used as back-up fuel during NG
curtailments and maintenance firings.

II.A.4 Steam Generating Unit #3 (EU #3)
105 MW electric generator powered by 1,155 MMBtu/hr capacity NG-fired utility boiler.
No. 2 fuel oil may be used as back-up fuel during NG curtailments and maintenance
firings.

II.A.5 Steam Generating Units (EU #4)
Combined emission unit group consisting of Steam Generating Units #1, #2, and #3.

II.A.6 Abrasive Blasting Operation (EU #5)
Portable sand blaster, includes two glove box units with fabric filters, for maintenance and
painting operation. No unit-specific applicable requirements.

II.A.7 Emission Unit #1 Cooling Towers (EU #7)
Cooling towers for the circulating water system for Emission Unit #1. No unit-specific
applicable requirements.

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II.A.8 Emission Unit #2 Cooling Towers (EU #8)
Cooling towers for the circulating water system for Emission Unit #2. No unit-specific
applicable requirements.

II.A.9 Emission Unit #3 Cooling Towers (EU #9)
Cooling towers for the circulating water system for Emission Unit #3. No unit-specific
applicable requirements.

II.A.10 Emergency Generator (diesel engine) (EU #10)
175 kW emergency generator powered by a 280 hp diesel engine. NESHP ZZZZ.

II.A.11 Distillate Fuel Oil Tank (EU #11)
One 500 gallon tank for emergency equipment. No unit-specific applicable requirements.

II.A.12 Lube Oil Storage Tanks (EU#12)
Two 4,200 gallon tanks including vents and associated equipment that store lubricating oil.
No unit-specific applicable requirements.

II.A.13 Oil Storage Area (EU #13)
Storage area for oil contained in closed 55 gallon drums. No unit-specific applicable
requirements.

II.A.14 Miscellaneous Electrical Equipment (EU #15)
Stores transformer insulating oil. No unit-specific applicable requirements.

II.A.15 Water Treatment Chemical Tanks (EU #16)
Closed tanks to store water treatment chemicals. No unit-specific applicable requirements.

II.A.16 Paint Storage Areas (EU #17)
Various storage areas for sealed paint containers. No unit-specific applicable requirements.

II.A.17 Miscellaneous Parts Painting for Maintenance (EU #19)
Incidental preventative maintenance painting of parts for process equipment totaling less
than 1.0 ton per year of VOC and 500 pounds per year of HAPs.

II.A.18 Lube Oil Conditioners (EU #20)
Three 975-gallon lube oil conditioner vessels with vapor extractors to maintain the oil
purity. No unit-specific applicable requirements.

II.A.19 Lube Oil Reservoirs (EU #21)
Three lube oil reservoirs (two 2,800 gallon and one 3,150 gallon) with vapor extractors. No
unit-specific applicable requirements.

II.A.20 Hazardous Waste Storage Area (EU #22)
Area where hazardous waste is stored temporarily awaiting disposal. No unit-specific
applicable requirements.

II.A.21 Water Treatment Sludge Disposal Activities (EU #23)
Disposal of sludge generated from water treatment. No unit-specific applicable
requirements.

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II.A.22 Natural Gas Simple Cycle Turbines Units (EU #24)
Three GE LM6000 PC Sprint natural gas simple cycle turbines, each output rate at 43.5
MW and maximum firing rate at 367.6 MM Btu/hr, with water injection, NOx SCR catalyst
and CO oxidation catalyst.

II.A.23 Black Start Generator (EU #25)
1,007 kW emergency generator powered by a 1,350 bhp diesel engine and manufactured on
June 8, 2006. NPSP IIII and NESHP ZZZZ

Status: In compliance – No unapproved equipment was reported at the time of the inspection.
However, applying for an Experimental Approval Order (AO) was discussed
regarding item II.A.21.

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:

Visible emissions shall be no greater than 20 percent opacity for all particulate emission
sources unless otherwise noted in this permit. Fugitive dust shall be no greater than 20
percent opacity. [R307-305-3]. [R307-305-3]

II.B.1.a.1 Monitoring:

A visual observation of each emission unit indicated above shall be conducted on a weekly
basis. The observation may be completed as a general overview of the facility. If any
visible emissions are noted then an observation of that emission unit shall be performed by
an individual trained on the requirements of 40 CFR 60, Appendix A, Method 9. The
individual is not required to be a certified visible emissions observer (VEO). If the above
observation(s) indicate that visible emissions are still present then further observations
must be performed by a certified VEO in accordance with 40 CFR 60, Appendix A,
Method 9 or 58 FR 61640 Method 203C as appropriate, within 24 hours of the initial
observation.

II.B.1.a.2 Recordkeeping:

An operator's log shall be maintained of all monitoring provisions listed above. The records
shall contain all applicable information as required by section I.S.1 of this permit.

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II.B.1.a.3 Reporting:

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

Status: In compliance – The Visual Emission Source Weekly Checklists (Operators Logs)
were reviewed at the time of this inspection. The logs indicated that no visible
emissions have been observed since the last inspection. The yard area is paved and
graveled to minimize fugitive dust.

II.B.1.b Condition:

At all times, including periods of startup, shutdown, and malfunction, the permittee shall,
to the extent practicable, maintain and operate the affected emission unit, including
associated air pollution control equipment, in a manner consistent with good air pollution
control practice for minimizing emissions. Determination of whether acceptable operating
and maintenance procedures are being used will be based on information available to the
Director which may include, but is not limited to, monitoring results, opacity observations,
review of operating and maintenance procedures, and inspection of the source.
[DAQE-AN103550015-09]. [R307-401-8(2)]

II.B.1.b.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.1.b.2 Recordkeeping:

The Permittee shall document activities performed to assure proper operation and
maintenance. 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 – Maintenance activities are documented by tracking hard copy work
orders and records which are stored electronically in the SAP database. On
November 9, 2023, Emission Unit #3 experienced a deviation. The deviation was
reported in the 4th quarterly report for 2023. It was also documented in the six month
monitoring report for report period July 1, 2023 – December 31, 2023, and the 2023
ACC. See status of conditions I.S.2 and II.B.4.a.

II.B.1.c Condition:

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

15
II.B.1.c.1 Monitoring:

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

II.B.1.c.2 Recordkeeping:

All records required in 40 CFR 82, Subpart F shall be maintained consistent with the
requirements of Provision S.1 in Section I 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 most recent annual compliance certification indicates that the
Gadsby Plant complies with 40 CFR 82, Subpart F. Air conditioner/refrigerant work
is completed by Rocky Mountain Mechanical, on an as needed basis. They are
required to provide maintenance forms and certification checklists. See page 6 and 7
of the annual compliance certification.

II.B.1.d Condition:

Visible emissions from abrasive blasting operations shall not exceed 40% opacity, except
for an aggregate period of three minutes in any one hour. [R307-206-4]. [R307-206-4]

II.B.1.d.1 Monitoring:

Visible emission evaluation of abrasive blasting operations shall be conducted at least
quarterly in accordance Provision I.S.1 of this permit and the following provisions:

(a) Visible emissions shall be measured using EPA Method 9. 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 owner or operator that each nozzle, measured
separately, meets the emission and performance standards provided in R307-206-2 through
4.

(d) Visible emissions from confined blasting shall be measured at the densest point after
the air contaminant leaves the enclosure. [R307-206-5]

II.B.1.d.2 Recordkeeping:

Results of monitoring shall be maintained in accordance with Provision I.S.1 of this permit.
16
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 – Abrasive blasting takes place in the welding and maintenance shops.
Abrasive blasting visible emission observation (VEO) records were made available at
time of the inspection. The records indicated that quarterly observation are made. No
excess emissions were reported for 2024.

II.B.2 Conditions on Steam Generating Unit #1 (EU #1).

II.B.2.a Condition:

Emissions of NOx shall be no greater than 179 lbs/hour and 336 ppmdv (3% O2, dry).
[DAQE-AN103550015-09]. [R307-110-17(SIP IX.H.2.j), R307-401-8]

II.B.2.a.1 Monitoring:

(a)The permittee shall determine compliance with the NOx limits by calculating arithmetic
average of three contiguous one-hour periods NOx emission rate (lb/hr) or concentration
(ppmdv, 3% O2 dry) generated from paragraph (b) of this section.

(b) The permittee shall install, calibrate, maintain, and operate continuous emission
monitoring systems (CEMS) for NOx and CO2 as required by 40 CFR Part 75 for the Acid
Rain Program. The hourly average O2 concentration (percent by volume) shall be
calculated from CO2 concentration obtained from CO2 CEMS in accordance with 40 CFR
Part 75, Appendix F. The NOx concentration (ppm) obtained from NOx CEMS shall be
corrected to 3% O2 on hourly basis using the O2 data calculated above. The emission rate
(lb/hr) shall be calculated by multiplying the hourly average NOx emission rate
(lb/MMBtu) by the hourly heat input (MMBtu/hr). The hourly average NOx emission rate
(lb/MMBTU) shall be calculated by using NOx and CO2 concentrations obtained from
CEMS in accordance with 40 CFR Part 75, Appendix F. The heat input shall be calculated
by multiplying the measured fuel flow rate (scf/hr) by the hourly average CO2
concentration (percent by volume) and by any necessary conversion factors in accordance
with 40 CFR Part 75, Appendix F.

(c) Each continuous emission monitoring system shall meet the Specifications and Test
Procedures required by 40 CFR Part 75, Appendix A.

(d) The permittee shall implement Quality Assurance and Quality Control Procedures
required by 40 CFR Part 75, Appendix B.

II.B.2.a.2 Recordkeeping:

The permittee shall maintain a file of all measurements and calculations, including
continuous monitoring system, monitoring device, and performance testing measurements;
all continuous monitoring system performance evaluations; all continuous monitoring
system or monitoring device calibration checks; adjustments and maintenance performed
on these systems or devices recorded in a permanent form suitable for inspection. All
records shall be maintained in accordance with Provision I.S.1 of this permit.
17
II.B.2.a.3 Reporting:

The permittee shall comply with the reporting provisions in 40 CFR 75 Subpart G, and all
the reporting provisions contained in Section I of this permit.

Status: In compliance – A NOx CEM has been installed and operated. A detailed report is
submitted quarterly to the DAQ. CEM requirements are evaluated by DAQ’s CEM
specialist. See memorandums in the source file.

II.B.3 Conditions on Steam Generating Unit #2 (EU #2).

II.B.3.a Condition:

Emissions of NOx shall be no greater than 204 lbs/hour and 336 ppmdv (3% O2, dry).
[DAQE-AN103550015-09]. [R307-110-17(SIP IX.H.2.j.ii.A), R307-401-8]

II.B.3.a.1 Monitoring:

(a) The permittee shall determine compliance with the NOx limits by calculating arithmetic
average of three contiguous one-hour periods NOx emission rate (lb/hr) or concentration
(ppmdv, 3% O2 dry) generated from paragraph (b) of this section.

(b) The permittee shall install, calibrate, maintain, and operate continuous emission
monitoring systems (CEMS) for NOx and CO2 as required by 40 CFR Part 75 for the Acid
Rain Program. The hourly average O2 concentration (percent by volume) shall be
calculated from CO2 concentration obtained from CO2 CEMS in accordance with 40 CFR
Part 75, Appendix F. The NOx concentration (ppm) obtained from NOx CEMS shall be
corrected to 3% O2 on hourly basis using the O2 data calculated above. The emission rate
(lb/hr) shall be calculated by multiplying the hourly average NOx emission rate
(lb/MMBtu) by the hourly heat input (MMBtu/hr). The hourly average NOx emission rate
(lb/MMBTU) shall be calculated by using NOx and CO2 concentrations obtained from
CEMS in accordance with 40 CFR Part 75, Appendix F. The heat input shall be calculated
by multiplying the measured fuel flow rate (scf/hr) by the hourly average CO2
concentration (percent by volume) and by any necessary conversion factors in accordance
with 40 CFR Part 75, Appendix F.

(c) Each continuous emission monitoring system shall meet the Specifications and Test
Procedures required by 40 CFR Part 75, Appendix A.

(d) The permittee shall implement Quality Assurance and Quality Control Procedures
required by 40 CFR Part 75, Appendix B.

II.B.3.a.2 Recordkeeping:

The permittee shall maintain a file of all measurements and calculations, including
continuous monitoring system, monitoring device, and performance testing measurements;
all continuous monitoring system performance evaluations; all continuous monitoring
system or monitoring device calibration checks; adjustments and maintenance performed
on these systems or devices recorded in a permanent form suitable for inspection. All
records shall be maintained in accordance with provision I.S.1 of this permit.

18
II.B.3.a.3 Reporting:

The permittee shall comply with the reporting provisions in 40 CFR 75 Subpart G, and all
the reporting provisions contained in Section I of this permit.

Status: In compliance – A NOx CEM has been installed and operated. A detailed report is
submitted quarterly to the DAQ. CEM requirements are evaluated by DAQ’s CEM
specialist. See memorandums in the source file.

II.B.4 Conditions on Steam Generating Unit #3 (EU #3).

II.B.4.a Condition:

Emissions of NOx shall be no greater than 142 lbs/hour and 168 ppmdv (3% O2, dry) from
November 1 through February 28 (29). Emissions of NOx shall be no greater than 203
lbs/hour and 168 ppmdv (3% O2, dry) from March 1 through October 31.
[DAQE-AN103550015-09]. [R307-110-17(SIP IX.H.2.j.iii.A), R307-401-8]

II.B.4.a.1 Monitoring:

(a) The permittee shall determine compliance with the NOx limits by calculating arithmetic
average of three contiguous one-hour periods NOx emission rate (lb/hr) or concentration
(ppmdv, 3% O2 dry) generated from paragraph (b) of this section.

(b) The permittee shall install, calibrate, maintain, and operate continuous emission
monitoring systems (CEMS) for NOx and CO2 as required by 40 CFR Part 75 for the Acid
Rain Program. The hourly average O2 concentration (percent by volume) shall be
calculated from CO2 concentration obtained from CO2 CEMS in accordance with 40 CFR
Part 75, Appendix F. The NOx concentration (ppm) obtained from NOx CEMS shall be
corrected to 3% O2 on hourly basis using the O2 data calculated above. The emission rate
(lb/hr) shall be calculated by multiplying the hourly average NOx emission rate
(lb/MMBtu) by the hourly heat input (MMBtu/hr). The hourly average NOx emission rate
(lb/MMBTU) shall be calculated by using NOx and CO2 concentrations obtained from
CEMS in accordance with 40 CFR Part 75, Appendix F. The heat input shall be calculated
by multiplying the measured fuel flow rate (scf/hr) by the hourly average CO2
concentration (percent by volume) and by any necessary conversion factors in accordance
with 40 CFR Part 75, Appendix F.

(c) Each continuous emission monitoring system shall meet the Specifications and Test
Procedures required by 40 CFR Part 75, Appendix A.

(d) The permittee shall implement Quality Assurance and Quality Control Procedures
required by 40 CFR Part 75, Appendix B.

19
II.B.4.a.2 Recordkeeping:

The permittee shall maintain a file of all measurements and calculations, including
continuous monitoring system, monitoring device, and performance testing measurements;
all continuous monitoring system performance evaluations; all continuous monitoring
system or monitoring device calibration checks; adjustments and maintenance performed
on these systems or devices recorded in a permanent form suitable for inspection. All
records shall be maintained in accordance with Provision I.S1 of this permit.

II.B.4.a.3 Reporting:

The permittee shall comply with the reporting provisions in R307-170-9 and 40 CFR 75
Subpart G, and all the reporting provisions contained in Section I of this permit. The
quarterly reports required in R307-170-9 and 40 CFR 75 Subpart G 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.

Status: In compliance – A NOx CEM has been installed and operated. A detailed report is
submitted quarterly to the DAQ. CEM requirements are evaluated by DAQ’s CEM
specialist.

This emission unit exceeded the NOX permitted limit on November 9, 2023. The
exceedance was reported in the 4th quarterly report. It was also documented in the
six month monitoring report for report period July 1, 2023 – December 31, 2023, and
the 2023 ACC. See memorandums in the source file and status of conditions I.S.2 and
II.B.1.b.

II.B.5 Conditions on Steam Generating Units (EU #4).

II.B.5.a Condition:

Sulfur content of any fuel oil burned shall be no greater than 0.45 % by weight.
[DAQE-AN103550015-09]. [R307-401-8]

II.B.5.a.1 Monitoring:

Sulfur content shall be determined either by testing each fuel delivery of fuel oil or by
inspection of the fuel sulfur-content specifications provided by the vendor in purchase
records. Sulfur content in either instance shall be determined in accordance with
ASTM-D-4294, or equivalent.

II.B.5.a.2 Recordkeeping:

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

20
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 – No fuel oil is currently burned in the Steam Generating Emission
Units #4. The fuel oil lines have been disconnected to the units. However, the lines can
be reconnected on an as needed basis. The HF Sinclair Wyoming Refining Company’s
monthly report, dated November 15, 2024, was reviewed at time of the inspection. The
report indicated that fuel oil with a sulfur content of < 0.45 % by weight can be
delivered to the plant on an as needed basis. See status of conditions II.B.5.b and
II.B.5.c.

II.B.5.b Condition:

Visible emissions shall be no greater than 10 percent opacity for each stack.
[DAQE-AN103550015-09]. [R307-401-8]

II.B.5.b.1 Monitoring:

In lieu of monitoring via visible emission observations, fuel usage shall be monitored to
demonstrate that only natural gas is used as fuel. A 40 CFR Part 60, Method 9 test will be
conducted at least once every 24 hours during each period of natural gas curtailment over
24 hours in length when the unit is operated on fuel oil.

II.B.5.b.2 Recordkeeping:

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

II.B.5.b.3 Reporting:

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

Status: In compliance – Steam Generating Units (EU #4) are reported to operate on natural
gas only. No curtailments have been recorded since the last inspection. Pipeline
quality natural gas is monitored by a dedicated fuel flow meter. See status of
conditions II.B.5.a. and II.B.5.c.

II.B.5.c Condition:

The permittee shall use only natural gas as a primary fuel and No. 2 fuel oil or better as
back-up fuel. The fuel oil may be used only during periods of natural gas curtailment
and for maintenance firings. Maintenance firings shall not exceed one-percent of the
annual plant BTU requirement. In addition, maintenance firings shall be scheduled
between April 1 and November 30 of any calendar year. Natural gas curtailment is
defined as period when the natural gas provider/supplier imposes a curtailment or
interruption of service, and the curtailment is involuntary and beyond the control of the
permittee. [DAQE-AN103550015-09, SIP IX.H.2.j.iv and SIP IX.H.12.1.iv]. [R307-
l 10-17, R307-401-8]
21
II.B.5.c.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.5.c.2 Recordkeeping:

The permittee shall maintain records that document the reason (NG curtailment or
maintenance), date, duration, quantity consumed for each firing, and BTU content of fuel
oil during each firing. The percentage of the heat input during maintenance firings shall be
calculated as follow:

The percent of the heat input during maintenance firing = [(Sum of the heat input (MMBtu)
of all three boilers during maintenance firings of a calendar year)/ (2706 MMBtu/hr x 8760
hrs.)] x 100

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

II.B.5.c.3 Reporting:

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

Status: In compliance – Steam Generating Units (EU #4) are reported to operate on natural
gas only. No curtailments have been recorded since the last inspection. Pipeline
quality natural gas is monitored by a fuel flow meter. Maintenance firings are
conducted only on an as needed basis. See status of conditions II.B.5.a and II.B.5.b.

II.B.5.d Condition:

Emissions of PM10 shall be no greater than 44.39 tons per rolling 12-month period.
[DAQE-AN103550015-09]. [R307-401-8]

II.B.5.d.1 Monitoring:

The emissions shall be determined on a rolling 12-month total. Within the first 10 days of
each month, the total shall be calculated for each calendar month and added to the previous
11 months data.

Monthly emissions shall be the sum of emissions from each boiler and shall be calculated
using the following equation:

Monthly emissions (tons) =[(ft3/month)* x 5.0 (lb/10^6 ft3) x (1 ton/2000 lbs)] +
[(gal/month)** x 3.5 (lb/1000 gal) x (1 ton/2000 lbs)]

* natural gas consumed by all boilers combined during one month
** #2 diesel fuel consumed by all boilers combined during one month

Fuel consumption shall be determined by examination of the fuel usage records.

22
II.B.5.d.2 Recordkeeping:

Records such as gas/#2 diesel bills, or gas meter readings shall be kept on a daily basis and
used to demonstrate natural gas/#2 diesel usage. Records shall be maintained as described
in Provision I.S of this permit.

II.B.5.d.3 Reporting:

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

Status: In compliance – Records were reviewed at time of the inspection. PM10 produced by
EU #1, #2, and #3 (EU #4) was 13.87 total tons as of October 2024.
II.B.6 Conditions on Emergency Generator (diesel engine) (EU #10)

II.B.6.a Condition:

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. [40 CFR 63.6595(a)(1), 40 CFR
63.6605(b)]. [ 40 CFR 63 Subpart ZZZZ]

II.B.6.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.6.a.2 Recordkeeping:

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

The permittee shall document activities performed to 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.6.a.3 Reporting:

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

Status: In compliance – None of the requirements listed in 40 CFR 63.6655(a)(1)-(5) apply to
EU #10. The maintenance inspection was last conducted on March 27, 2024, by
Wheeler.
23
II.B.6.b Condition:

The permittee shall comply with the following operating limitations at all times for each
emergency affected emission unit:

(1) The permittee shall operate the affected emission unit according to the requirements in
40 CFR 63.6640(f)(1) through (4). Any operation other than emergency operation,
maintenance and testing, emergency demand response, and operation in non-emergency
situations for 50 hours per year, paragraphs 40 CFR 63.6640(f)(1) through (4), is
prohibited. If the engine is not operated in accordance with paragraphs 40 CFR
63.6640(f)(1) through (4), it will not be considered an emergency engine and shall meet all
requirements for non-emergency engines.

(2) 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,
except as otherwise provided under II.B.4.d.2(d);

(b). Inspect air cleaner every 1,000 hours of operation or annually, whichever comes first;

(c). Inspect all hoses and belts every 500 hours of operation or annually, whichever comes
first, and replace as necessary;

(d). The permittee may opt to perform oil analysis procedures as outlined in 40 CFR 63
.6625(i) or (j) in order to extend the specified oil change requirement found at 2(a) of this
permit condition.

(3) 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.

(4) 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 63.6595(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]. [40 CFR 63 Subpart ZZZZ]

II.B.6.b.1 Monitoring:

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

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
24
has ended or the unacceptable risk under Federal, State, or local law has abated. [40 CFR
63 Subpart ZZZZ Table 2c Footnote 1]

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.

Records shall be maintained in accordance with 40 CFR 63.6660 and Provision I.S.1 of this
permit. [40 CFR 63.6665].

II.B.6.b.2 Recordkeeping:

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

For each affected emission unit that does not meet the standards applicable to non-
emergency engines, the permittee shall keep records of the hours of operation of the engine
that are recorded through the non-resettable hour meter. The permittee shall document how
many hours are spent for emergency operation, including what classified the operation as
emergency and how many hours are spent for non-emergency operation. If the engines are
used for demand response operation, the permittee shall keep records of the notification of
the emergency situation, and the time the engine was operated as part of demand response.
[40 CFR 63.6655(£)]

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 year. [40 CFR
63.6640(f)(1)(ii)]

The permittee shall keep records that demonstrate continuous compliance with each
applicable operating limitation [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].

25
II.B.6.b.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. [40
CFR 63.6640(e)]

The permittee shall submit each report in 40 CFR 63 Subpart ZZZZ Table 7 as applicable.
[40 CFR 63.6650(a)]

If there are no deviations from any applicable operating limitations, the permittee shall
submit a compliance report semiannually for affected emission units according to the
requirements of 40 CFR 63.6650(b)(1)-(5) that contains the information required in 40
CFR 63.6650(c)(1)-(3) and a statement that there were no deviations from the operating
limitations during the reporting period. [40 CFR 63 Subpart ZZZZ Table 7.1.a]

If a deviation from any operating limitation occurs during the reporting period, the
permittee shall submit a compliance report semiannually according to the requirements of
40 CFR 63.6650(b), (f) that contains the information required in 40 CFR 63.6650(c)(1)-(3),
(d). [40 CFR 63 Subpart ZZZZ Table 7.1.b]

If a malfunction occurs during the reporting period, the permittee shall submit a
compliance report semiannually according to the requirements of 40 CFR 63.6650(b) that
contains the information required in 40 CFR 63.6650(c)(1)-(4). [40 CFR 63 Subpart ZZZZ
Table 7.1.c]

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. The permittee shall also report each
instance in which it did not meet the applicable requirements in Table 8.
[40 CFR 63.6640(e)]

The permittee shall submit an annual report as specified in 40 CFR 63.6650(h) if the
emergency stationary RICE with a site rating of more than 100 hp that operates for
the purpose specified in 40 CFR 63.6640(f)(4)(ii).

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

Status: In compliance – According to the non-resettable hour meter records, the generator ran 27.0 hours for maintenance and 2.2 hours for emergencies, as of November 26, 2024 . Wheeler conducts annual maintenance on the emergency generator and provides an annual preventative maintenance (PM) report to the Gadsby Plant. The generator is exercised once per week for < 30 minutes.

26
II.B.7 Conditions on Miscellaneous Parts Painting for Maintenance (EU #19)
II.B.7.a Condition:

(1) The permittee shall not apply coatings with a VOC content greater than the
amounts specified in Table 1 of R307-350-5, unless the permittee uses an
add-on control device as specified in R307- 350-8. If more than one
content limit indicated in Table 1 of R307-350-5 applies to a specific
coating, then the most stringent content limit shall apply
(2) The permittee shall not apply VOC containing coatings to metal parts
and products unless the coating is applied with equipment operated
according to the equipment manufactured specification and by the use of
one of the methods listed in R307-350-6.
(3) The permittee shall implement control techniques and work practices
required in R307-350-7 at all times to reduce VOC emissions. [R307-350-
5, 6, 7, and 8] [R307-350]

II.B.7.a.1 Monitoring:

Records required for this permit will serve as monitoring.

II.B.7.a.2 Recordkeeping:

The permittee shall comply with recordkeeping requirements of provision I.S.1 of this
permit and any additional recordkeeping requirements in R307-350-9.

II.B.7.a.3 Reporting:

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

Status: In compliance – UAC R307-350 VOC records were being maintained at time of the
inspection. Since this is a fairly new condition, improvements in VOC record keeping
will be made.

II.B.8 Conditions on Natural Gas Simple Cycle Turbines Units (EU #24).

II.B.8.a Condition:

The permittee shall comply with all applicable requirements of 40 CFR 60 Subpart A.
[DAQE-AN103550015-09]. [40 CFR 60 Subpart A, R307-401-8]

II.B.8.a.1 Monitoring:

The permittee shall comply with the monitoring requirements of 40 CFR 60.8(a), (b), (c),
(e) and (f), and 60.11(a).

27
II.B.8.a.2 Recordkeeping:

The permittee shall comply with the recordkeeping requirements of provision I.S.1 of this
permit and any additional recordkeeping requirements of 40 CFR 60.7.

II.B.8.a.3 Reporting:

The permittee shall comply with the reporting requirements in Section I of this permit and
any additional reporting and notification requirements of 40 CFR 60 Subpart A.

Status: In compliance – 40 CFR Subpart A 60.7(a) requires construction and initial startup
notifications which have been submitted to DAQ. 40 CFR Subpart A 60.7(b) requires
records to be kept of the occurrence and duration of any start up, shut down, or
malfunction. Malfunctions are recorded in an operator’s log, and logs alarms in a
Distributive Control System (DCS). Startup and shutdown data are recorded by the
CEM system. 40 CFR Subpart A 60.8 contains initial performance test requirements
which were met in August 2002. Additional testing requirements are stipulated in this
Title V Operating Permit. See each condition for testing details.

II.B.8.b Condition:

Total emissions of NOx from all three turbines shall be no greater than 22.2 lbs/hour (15%
O2, dry) based on 30 day rolling average under steady state operation (not including startup
and shutdown). In addition, total emissions of NOx from all three turbines shall be no
greater than 600 lbs/day (a day is defined as a period of 24-hours commencing at midnight
and ending at the following midnight). Emission of NOx from each individual turbine shall
be no greater than 5 ppmdv (15% O2, dry) based on 30 day rolling average under steady
state operation (not including startup and shutdown) and shall be no greater than 116
ppmdv (15% O2, dry) at any time. [DAQE-AN103550015-09]. [40 CFR 60 Subpart GG,
R307-110-17(SIP IX.H.2.j.v.A), R307-401-8(1)(a)(BACT)]

II.B.8.b.1 Monitoring:

(a) The permittee should install, certify, maintain, operate, and quality-assure a continuous
emission monitoring system (CEMS) consisting of NOx and O2 monitors to determine
compliance with the applicable NOx limitations. The CEMS shall be installed, certified,
maintained and operated as follows:

(1) Each CEMS must be installed and certified according to PS 2 and 3 (for diluent) of 40
CFR part 60, appendix B, except the 7-day calibration drift is based on unit operating days,
not calendar days. Appendix F, Procedure 1 is not required. The relative accuracy test audit
(RATA) of the NOx and diluent monitors may be performed individually or on a combined
basis, i.e., the relative accuracy tests of the CEMS may be performed either

(i) On a ppm basis (for NOx) and a percent O2 basis for oxygen; or
(ii) On a ppm at 15 percent O2 basis.

(2) As specified in 40 CFR 60.13(e)(2), during each full unit operating hour, each monitor
must complete a minimum of one cycle of operation (sampling, analyzing, and data
recording) for each 15-minute quadrant of the hour, to validate the hour. For partial unit
operating hours, at least one valid data point must be obtained for each quadrant of the hour
28
in which the unit operates. For unit operating hours in which required quality assurance and
maintenance activities are performed on the CEMS, a minimum of two valid data points
(one in each of two quadrants) are required to validate the hour.

(3) For purposes of identifying excess emissions, CEMS data must be reduced to hourly
averages as specified in 40 CFR 60.13(h).

(i) For each unit operating hour in which a valid hourly average, as described in paragraph
(a)(2) of this section, is obtained for both NOx and diluent, the data acquisition and
handling system must calculate and record the hourly NOx emissions in the units of percent
NOx by volume, dry basis, corrected to 15 percent O2 and International Organization for
Standardization (ISO) standard conditions (if required as given in 40 CFR 60.335(b)(1)).
For any hour in which the hourly average O2 concentration exceeds 19.0 percent O2, a
diluent cap value of 19.0 percent O2 may be used in the emission calculations.

(ii) A worst case ISO correction factor may be calculated and applied using historical
ambient data. For the purpose of this calculation, substitute the maximum humidity of
ambient air (Ho), minimum ambient temperature (Ta), and minimum combustor inlet
absolute pressure (Po) into the ISO correction equation.

(iii) If the permittee has installed a NOx CEMS to meet the requirements of 40 CFR Part
75, and is continuing to meet the ongoing requirements of 40 CFR Part 75, the CEMS may
be used to meet the requirements of this section, except that the missing data substitution
methodology provided for at 40 CFR Part 75, subpart D, is not required for purposes of
identifying excess emissions. Instead, periods of missing CEMS data are to be reported as
monitor downtime in the excess emissions and monitoring performance report required in
Sec. 60.7(c).

(b) Each continuous emission monitoring system shall meet the Specifications and Test
Procedures required by 40 CFR Part 75, Appendix A.

(c) The permittee shall implement Quality Assurance and Quality Control Procedures
required by 40 CFR Part 75, Appendix B.

(d) The quality assurance requirements of R307-170, Continuous Emission Monitoring
Systems Program, shall be used in addition to 40 CFR Part 75 procedures to fulfill data
quality assurance requirements.

(e) The daily average of NOx emissions shall be calculated once for each day (a period of
24-hours commencing at midnight and ending at the following midnight) and the 30-day
rolling average shall be calculated by adding previous 30 days data on a daily basis.

II.B.8.b.2 Recordkeeping:

Results of NOx monitoring shall be recorded and maintained as required in R307-170, 40
CFR 60 subpart GG, 40 CFR 75 subpart F, and as described in Provision I.S.1 of this
permit.

29
II.B.8.b.3 Reporting:

(a) The permittee shall comply with the reporting provisions in R307-170-9, 40 CFR 75
Subpart G, 40 CFR Subpart GG and all the reporting provisions contained in Section I of
this permit.

(b) The permittee shall submit reports of excess emissions and monitor downtime, in
accordance with 40 CFR 60.7(c). Excess emissions shall be reported for all periods of unit
operation, including startup, shutdown and malfunction. For the purpose of reports required
under 40 CFR 60.7(c), periods of excess emissions and monitor downtime that shall be
reported are defined as follows:

(1) An hour of excess emissions shall be any unit operating hour in which the 4-hour
rolling average NOx concentration exceeds applicable NSPS emission standard of 116
ppmdv (15% O2, dry). A ``4-hour rolling average NOx concentration'' is the arithmetic
average of the average NOx concentration measured by the CEMS for a given hour
(corrected to 15 percent O2 and, if required under 40 CFR 60.335(b)(1), to ISO standard
conditions) and the three unit operating hour average NOx concentrations immediately
preceding that unit operating hour.

(2) A period of monitor downtime shall be any unit operating hour in which sufficient data
are not obtained to validate the hour, for either NOx concentration or diluent (or both).

(3) Each report shall include the ambient conditions (temperature, pressure, and humidity)
at the time of the excess emission period. The ambient conditions is not required if the
permittee opt to use the worst case ISO correction factor as specified in 40 CFR
60.334(b)(3)(ii).

(4) All reports of excess emissions and monitor downtime shall be postmarked by the 30th
day following the end of each calendar quarter.

(c) The quarterly reports required in R307-170-9 and 40 CFR 75 Subpart G 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.

Status: In compliance – Initial testing was conducted in August 2002, as required. The test
protocol was submitted on June 11, 2002. Refer to memorandum dated December 12,
2002 (DAQC-011-2003), for details. A CEM has been installed and operated. CEM
requirements are evaluated by DAQ’s CEM specialist. This includes reviewing
Relative Accuracy Test Audits (RATA) and quarterly State Electronic Data Reports
(SEDR). The quarterly CEMs report has been submitted. See memorandums in the
source files.

II.B.8.c Condition:

Total emissions of CO from all three turbines shall be no greater than 26.9 lbs/hour (15%
O2, dry) based on 8-hour block average under steady state operation (not including startup
and shutdown). Emission of CO from each individual turbine shall be no greater than 10
ppmdv (15% O2, dry) based on 8-hour block average under steady state operation (not
including startup and shutdown). [DAQE-AN103550015-09]. [R307-401-8]

30
II.B.8.c.1 Monitoring:

The emission of CO shall be monitored by continuous emission monitoring system
(CEMS). The permittee shall calibrate, maintain, and operate a CEMS as required by
R307-170 to determine compliance with CO concentration (ppmdv) and CO mass emission
rate (lb/hr). The emission rate (lb/hr) shall be calculated by multiplying the CO
concentration and 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. The CO concentration shall be determined from data generated by the CEMS.
The quality assurance requirements of R307-170, Continuous Emission Monitoring
Systems Program shall be used to fulfill data quality assurance requirements.

II.B.8.c.2 Recordkeeping:

Results of CO monitoring shall be recorded and maintained as required in R307-170 and as
described in Provision I.S.1 of this permit.

II.B.8.c.3 Reporting:

The permittee shall comply with the reporting provisions in R307-170-9 and all the
reporting provisions contained in Section I of this permit. The quarterly reports required in
R307-170-9 is 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.

Status: In compliance – A CO CEM has been installed and operated. CEM requirements are
evaluated by DAQ’s CEM specialist. This includes reviewing RATA and quarterly
SEDRs. The quarterly CEMs report has been submitted. See memorandums in the
source file.

II.B.8.d Condition:

Visible emissions shall be no greater than 10 percent opacity from each turbine.
[DAQE-AN103550015-09]. [R307-401-8]

II.B.8.d.1 Monitoring:

In lieu of monitoring via visible emission observations, fuel usage shall be monitored to
demonstrate that only pipeline-quality natural gas is used as fuel.

II.B.8.d.2 Recordkeeping:

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

31
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 – The Gadsby Plant’s fuel system is configured to run strictly on
natural gas. The facility has a contract with Enbridge Gas which provides
pipeline quality natural gas to the plant. Natural gas usage is monitored via an excel
file provided by the Enbridge Gas website.

II.B.8.e Condition:

Combined 12- month rolling emissions from the three natural gas turbines shall not exceed
29.5 tons for PM10, 81.0 tons for NOx, 98.30 tons for CO, and 6.12 tons for SO2.
[DAQE-AN103550015-09]. [R307-401-8]

II.B.8.e.1 Monitoring:

The emissions shall be determined on a rolling 12-month total. Within the first 10 days of
each month, the total shall be calculated for each calendar month and added to the previous
11 months data.

Monthly emissions shall be the sum of emissions from each turbine and shall be calculated
using the following equation:

Monthly emissions (tons) turbine heat input [MMBtu/month] x emission factor
[lb/MMBtu) x (1 ton/2000 lbs)

Fuel consumption shall be determined by a fuel meter provided for each turbine or from
CEMs data. Emission factors shall be as follows:

(a) PM10 shall be obtained from EPA's Compilation of Air Pollutant Emission Factors,
AP-42 (Supplement F EPA, April 2000);

(b) NOx monthly average emission factor in lb/MMBtu shall be calculated from CEM-
recorded data (ppmdv) based on 40 CFR Part 60 App. A. Method 19;

(c) CO monthly average emission factor in lb/MMBtu shall be calculated from CEM-
recorded data (ppmdv) based on 40 CFR Part 60 App. A. Method 19;

(d) SO2 emission factor shall be calculated using natural gas sulfur content data (supplied
by local gas distribution company) and the EPA's Compilation of Air Pollutant Emission
Factors, AP-42 (Supplement F EPA, April 2000).

II.B.8.e.2 Recordkeeping:

Records such as gas meter readings, or CEMs data shall be kept on a continuous basis.
Records shall be maintained as described in Provision I.S of this permit.

32
II.B.8.e.3 Reporting:

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

Status: In compliance – The three Simple Cycle Turbines (EU #24) produced combined PM10, NOx, CO, and SO2, as of October 31, 2024: Combined Pollutants Actual (Tons) Limit (Tons)
PM10 1.35 29.5 NOx 1.22 81.0
CO 0.33 98.30 SO2 0.024 6.12

II.B.8.f Condition:

Sulfur content of any fuel burned shall be no greater than 0.8 % by weight. [40 CFR 60
Subpart GG]. [40 CFR 60 Subpart GG]

II.B.8.f.1 Monitoring:

In lieu of monitoring the total sulfur content of gaseous fuel combusted in the turbines, the
permittee should use one of the following sources of information to demonstrate that the
gaseous fuel meets the definition of natural gas in 40 CFR 60.331(u):

(a) The gas quality characteristics in a current, valid purchase contract, tariff sheet or
transportation contract for the gaseous fuel, specifying that the maximum total sulfur
content of the fuel is 20.0 grains/100 scf or less; or

(b) Representative fuel sampling data which show that the sulfur content of the gaseous
fuel does not exceed 20 grains/100 scf. At a minimum, the amount of fuel sampling data
specified in section 2.3.1.4 or 2.3.2.4 of appendix D to 40 CFR Part 75 is required.

II.B.8.f.2 Recordkeeping:

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

II.B.8.f.3 Reporting:

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

Status: In compliance – The Gadsby Plant complies with items (a) and (b) above by reviewing
tariff sheets and representative fuel sampling data provided by Enbridge Gas. See
status of condition II.B.8.d.

33
II.B.8.g Condition:

The permittee shall develop, maintain, and implement a written Emissions Minimization
Plan that describes, in detail, procedures for operating and maintaining the combustion
turbines including associated air pollution control and monitoring equipment, during events
of startup and shutdown. The Plan shall define the startup and shutdown events and shall
contain the minimum requirements as follows:

(1) Startup begins when the fuel valves open and natural gas is supplied to the combustion
turbines

(2) Startup ends when either of the following conditions is met:

(a) NOx water injection pump is operational, the dilution air temperature is greater than
600oF, the stack inlet temperature reaches 570oF, the ammonia block valve has opened and
ammonia is being injected into the SCR and the unit has reached an output of ten (10) gross
MW; or

(b) The unit has been in startup for two (2) hours.

(3) Unit shutdown begins when the unit load or output is reduced below ten (10) gross MW
with the intent of removing the unit from service.

(4) Shutdown ends at the cessation of fuel input to the turbine combustor.

(5) Periods of startup or shutdown shall not exceed two (2) hours per combustion turbine
per day.

(6) Turbine output (turbine load) shall be monitored and recorded on an hourly basis with
an electrical meter.

(7) The permittee shall periodically revise the Emissions Minimization Plan as necessary to
satisfy the requirements of this condition or to reflect changes in equipment or procedures
at the affected source. [SIP IX Part H.2.j.vi and SIP IX Part H.12.1.vi]. [R307-l l 0-17

II.B.8.g.1 Monitoring:

Recordkeeping requirements required in this permit condition shall serve as monitoring
requirement.

II.B.8.g.2 Recordkeeping:

The permittee shall maintain records demonstrating that the procedures in the Gadsby Plan
were followed. These records shall include the date and time of occurrence and duration of
each startup and shutdown for each combustion turbine per day, emissions during startup
and shutdown as well as other pertinent information.

34
II.B.8.g.3 Reporting:

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

Status: In compliance – The Emissions Minimization Plan (EMP) was last revised on May 6,
2021. The EMP is currently under review.

II.B.9 Conditions on Black Start Generator (EU #25).

II.B.9.a Condition:

Visible emissions shall be no greater than 20 percent opacity. [DAQE-AN103550015-09].
[R307-401-8]

II.B.9.a.1 Monitoring:

An opacity observation of each affected emission unit shall be conducted once every six
months 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
(VEO). If any visible emissions are observed, an opacity determination of that emission
unit shall be performed by a certified VEO in accordance with 40 CFR 60, Appendix A,
Method 9 within 24 hours of the initial observation.

II.B.9.a.2 Recordkeeping:

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

II.B.9.a.3 Reporting:

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

Status: In compliance – Black start engine opacity observation are conducted monthly by
health and safety. The observation records, for 2024, indicate that 0% opacity was
observed during initial startup.

II.B.9.b Condition:

Emergency generators shall be used for electricity production only during periods when
electric power from the public utilities is interrupted, except for routine engine maintenance
and testing. [DAQE-AN103550015-09]. [R307-401-8]

II.B.9.b.1 Monitoring:

An operation log shall be used to record the following information for each usage: date(s),
total hours used, and reason for usage.

II.B.9.b.2 Recordkeeping:

Results of monitoring shall be maintained in accordance with Provision I.S.1 of this permit.
35
II.B.9.b.3 Reporting:

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

Status: In compliance – According to the non-resettable hour meter records, the black start generator ran 17.6 hours for maintenance and 0.0 hours for emergencies as of November 26, 2024.
II.B.9.c Condition:

The permittee shall operate and maintain affected emission units that achieve the emission
standards as required in 40 CFR 60.4205 according to the manufacturer's written
instructions or procedures developed by the permittee that are approved by the engine
manufacturer, over the entire life of the engine. In addition, the permittee may only change
those settings that are permitted by the manufacturer. The permittee shall also meet the
requirements of 40 CFR parts 89, 94 and/or 1068, as they apply to the permittee. [40 CFR
60.4206 and 40 CFR 60.4211(a)]. [40 CFR 60 Subpart IIII, 40 CFR 63 Subpart ZZZZ]

II.B.9.c.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.9.c.2 Recordkeeping:

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

II.B.9.c.3 Reporting:

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

Status: In compliance – Wheeler conducts annual maintenance on the black start generator
and provides an annual preventative maintenance (PM) report to the Gadsby Plant.
The generator is exercised once per month for at least one hour. Maintenance records
were made available. This includes maintenance activities required by 40 CFR 63
Subpart ZZZZ. Maintenance was last conducted on March 27, 2024. See status of
condition II.B.9.g.

II.B.9.d Condition:

The permittee shall purchase diesel fuel that meets the following standards of 40 CFR
80.510(b) for non-road diesel fuel:

(1) Sulfur content no greater than 15 ppm (0.0015 percent) by weight and
(2) A minimum cetane index of 40 or a maximum aromatic content of 35 volume percent.
[40 CFR 60.4207(b)]. [40 CFR 60 Subpart IIII, 40 CFR 63 Subpart ZZZZ]

36
II.B.9.d.1 Monitoring:

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

II.B.9.d.2 Recordkeeping:

For each fuel load received, the permittee shall maintain either fuel receipt records or other
documentation showing fuel meets the specifications of ASTM D975 for the cetane index
and sulfur content for Grades No. 1-D S15 or 2-D S15 diesel. The permittee shall maintain
documentation demonstrating compliance with the condition. These records shall be
maintained in accordance with Provision I.S.1 of this permit.

II.B.9.d.3 Reporting:

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

Status: In compliance – HF Sinclair Wyoming Refining Co. monthly invoice, dated November
15, 2024, was reviewed at time of the inspection. It indicated that the diesel fuel that is
used to fuel the black start generator has a sulfur content < 15 ppm and cetane index
> 40. See status of conditions II.B.5.a and II.B.8.f.

II.B.9.e Condition:

Pre-2007 model year affected emission units with a displacement of less than 10 liters per
cylinder shall comply with the emission standards in Table 1 of 40 CFR 60 Subpart IIII.
Pre-2007 model year affected emission units with a displacement of greater than or equal to
10 liters per cylinder and less than 30 liters per cylinder shall comply with the emission
standards in 40 CFR part 1042, appendix I. [40 CFR 60.4205(a)]. [40 CFR 60 Subpart IIII,
40 CFR 63 Subpart ZZZZ]

II.B.9.e.1 Monitoring:

The permittee shall demonstrate compliance according to one of the methods specified in
paragraphs (a) through (e) of this section.

(a) Purchasing an engine certified according to 40 CFR part 89 or 40 CFR part 94, as
applicable, for the same model year and maximum engine power. The engine must be
installed and configured according to the manufacturer's specifications.

(b) Keeping records of performance test results for each pollutant for a test conducted on a
similar engine. The test must have been conducted using the same methods specified in 40
CFR 60 Subpart IIII and these methods must have been followed correctly.

(c) Keeping records of engine manufacturer data indicating compliance with the standards.

(d) Keeping records of control device vendor data indicating compliance with the
standards.

37
(e) Conducting an initial performance test to demonstrate compliance with the emission
standards according to the requirements specified in 40 CFR 60.4212, as applicable. (40
CFR 60.4211(b)).

II.B.9.e.2 Recordkeeping:

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

II.B.9.e.3 Reporting:

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

Status: In compliance - The black start generator is a Tier II certified engine (Certificate of
Conformity). Tier II engines meet the emissions standards listed in Table 1 of 40 CFR
60 Subpart IIII.

II.B.9.f Condition:

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. [40 CFR 63.6595(a)(1), 40 CFR
63.6605(b)]. [40 CFR 63 Subpart ZZZZ]

II.B.9.f.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.9.f.2 Recordkeeping:

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

The permittee shall document activities performed to 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.9.f.3 Reporting:

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

Status: In compliance – This 2006 engine is a Tier II certified engine. Maintenance records
were made available at the time of this inspection. See status of condition II.B.9.c.

38
II.B.9.g Condition:

The permittee shall comply with the following operating limitations at all times for each
emergency affected emission unit:

(1) The permittee shall operate the affected emission unit according to the requirements in
40 CFR 63.6640(f)(1) through (4). Any operation other than emergency operation,
maintenance and testing, emergency demand response, and operation in non-emergency
situations for 50 hours per year, paragraphs 40 CFR 63.6640(f)(1) through (4), is
prohibited. If the engine is not operated in accordance with paragraphs 40 CFR
63.6640(f)(1) through (4), it will not be considered an emergency engine and shall meet all
requirements for non-emergency engines.

(2) 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,
except as otherwise provided under 2(d) of this permit condition;

(b). Inspect air cleaner every 1,000 hours of operation or annually, whichever comes first;

(c). Inspect all hoses and belts every 500 hours of operation or annually, whichever comes
first, and replace as necessary;

(d). The permittee may opt to perform oil analysis procedures as outlined in 40 CFR
63 .6625(i) or (j) in order to extend the specified oil change requirement required under
2(a) of this permit condition.

(3) 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.

(4) 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 60.4211(f), 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]. [40 CFR 60 Subpart IIII, 40 CFR 63 Subpart
ZZZZ]

II.B.9.g.1 Monitoring:

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]
39
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.9.g.2 Recordkeeping:

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

For each affected emission unit that does not meet the standards applicable to non-
emergency engines, the permittee shall keep records of the hours of operation of the engine
that are recorded through the non-resettable hour meter. The permittee shall document how
many hours are spent for emergency operation, including what classified the operation as
emergency and how many hours are spent for non-emergency operation. If the engines are
used for demand response operation, the permittee shall keep records of the notification of
the emergency situation, and the time the engine was operated as part of demand response.
[40 CFR 63.6655(f)]

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 year. [40 CFR
63.6640(£)(1 )(ii)]

The permittee shall keep records that demonstrate continuous compliance with each
applicable operating limitation [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 shall be maintained IN ACCORDANCE WITH Provision I.S.1 of this permit.

40
II.B.9.g.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.
[40 CFR 63.6640(e)]
The permittee shall submit an annual report as specified in 40 CFR 63.6650(h) if the
emergency stationary RICE with a site rating of more than 100 hp that operates for
the purpose specified in 40 CFR 63.6640(f)(4)(ii).

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

Status: In compliance – It was noted at time of the inspection that the black start generator
was being idled for > 30 minutes for maintenance. Gadsby Power agreed to reduce the
maintenance idle time to < 30 minutes. See status of condition II.B.9.c and
Compliance Assistance below.

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.

II.E Source-specific Definitions.

The following definitions apply to the permittee. They include terms not defined in state or
federal rules or clarify or expand on existing definitions.

II.E.1 Startup. For Units#1, #2, and #3, startup begins when the forced draft and induced draft
fans are turned on and when fuel is fed to the boiler with the intent to bring the unit on line
to generate power and ends when the generating units reach minimum load. The minimum
load is 20 MW for Unit 1, 25 MW for Unit #2, and 30 MW for Unit#3. For gas turbines,
start up begins and ends as defined in Condition II.B.8.g.

II.E.2 Shutdown. For Units #1, #2, and #3, shutdown begins when the load is reduced with the
intent of bringing the unit off line and ends when the fuel flow ends and the forced draft
fans are turned off. For gas turbines, shutdown is defined in Condition II.B.8.g.

II.E.3 Downtime. Downtime is that time between the end of shutdown and the beginning of
startup.

41
II.E.4 Maintenance Outage. The removal of a unit from service availability to perform work on
specific components that can be deferred beyond the end of the next weekend, but requires
the equipment be removed from service before the next planned outage. Typically, a
Maintenance Outage may occur anytime during the year, have a flexible start date, and may
or may not have a predetermined duration.

II.E.5 Planned Outage. The removal of a unit from service availability for inspection and/or
general overhaul of one or more major equipment groups. This outage usually is scheduled
well in advance.

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

SECTION III: PERMIT SHIELD

The following requirements have been determined to be not applicable to this source in
accordance with Provision I.M, Permit Shield:

III.A. 40 CFR, Part 60, Subpart OOO (Non-metallic mineral processing)

This regulation is not applicable to the Permitted Source for the following reason(s): the
process of crushing and grinding nonmetallic minerals is not performed at this source.

III.B. 40 CFR, Part 60, Subpart Y (NSPS for Coal Preparation Plants)

This regulation is not applicable to the Permitted Source for the following reason(s):
natural gas is the primary fuel at this source and coal is not processed at this plant

III.C. 40 CFR, Part 60, Subpart K (NSPS/ Volatile Organic Liquid Storage Vessels)

This regulation is not applicable to the Distillate Fuel Oil Tank (EU #11) for the following
reason(s): this standard does not apply to Nos. 2 through 6 fuel oils or diesel fuels

III.D. 40 CFR, Part 60, Subpart Ka (NSPS/ Volatile Organic Liquid Storage Vessels)

This regulation is not applicable to the Distillate Fuel Oil Tank (EU #11) for the following
reason(s): this standard does not apply to Nos. 2 through 6 fuel oils or diesel fuels

III.E. 40 CFR, Part 60, Subpart Kb (NSPS/ Volatile Organic Liquid Storage Vessels)

This regulation is not applicable to the Distillate Fuel Oil Tank (EU #11) for the following
reason(s): construction commenced prior to July 23, 1984

III.F. 40 CFR, Part 63, Subpart Q (NESHAP for Industrial Process Cooling Towers)

This regulation is not applicable to the Emission Unit #1 Cooling Towers (EU #7) for the
following reason(s): the cooling towers are not operated with chromium-based water
treatment chemicals

42
III.G. 40 CFR, Part 63, Subpart Q (NESHAP for Industrial Process Cooling Towers)

This regulation is not applicable to the Emission Unit #2 Cooling Towers (EU #8) for the
following reason(s): the cooling towers are not operated with chromium-based water
treatment chemicals

III.H. 40 CFR, Part 63, Subpart Q (NESHAP for Industrial Process Cooling Towers)

This regulation is not applicable to the Emission Unit #3 Cooling Towers (EU #9) for the
following reason(s): the cooling towers are not operated with chromium-based water
treatment chemicals

III.I. 40 CFR Part 60, Subpart D (Standards of Performance for New Stationary Sources for
Fossil-Fuel-Fired Steam Generators)

This regulation is not applicable to the Steam Generating Units (EU #4) for the following
reason(s): construction commenced prior to August 17, 1971

III.J. 40 CFR, Part 60, Subpart Da (NSPS for Electric Utility Steam Generating Units for Which
Construction is Commenced After September 18, 1978)

This regulation is not applicable to the Steam Generating Units (EU #4) for the following
reason(s): construction commenced prior to September 18, 1978

Status: For informational purpose only. Section III lists requirements that are not applicable
to the source.

SECTION IV: ACID RAIN PROVISIONS

IV.A Utah Acid Rain Program Authority.

Authority to implement the Acid Rain Program is contained in R307-417, Permits: Acid
Rain Sources, and R307-415-6a(4), Standard permit requirements [for operating permits].

IV.B Permit Requirements.

IV.B.1 The designated representative of the source and each affected unit at the source shall:

IV.B.1.a

Submit a complete Acid Rain permit application (including a compliance plan) under
R307-417 and 40 CFR Part 72 in accordance with the deadlines specified in 40 CFR 72.30;
and

IV.B.1.b Submit in a timely manner any supplemental information that the Director determines is
necessary in order to review an Acid Rain permit application and issue or deny an Acid
Rain permit;

IV.B.2 The owners and operators shall:

IV.B.2.a Operate each affected unit at the source in compliance with a complete Acid Rain permit
application or a superseding Acid Rain permit issued by the Director; and

43
IV.B.2.b

Have an Acid Rain Permit.
IV.C Sulfur Dioxide Requirements.

IV.C.1 The owners and operators of each affected unit at the source shall:

IV.C.1.a Hold allowances, as of the allowance transfer deadline, in the unit's compliance subaccount
(after deductions under 40 CFR 73.34(c)) not less than the total annual emissions of sulfur
dioxide for the previous calendar year from the unit; and

IV.C.1.b

Comply with the applicable Acid Rain emissions limitations for sulfur dioxide.
IV.C.2 Each ton of sulfur dioxide emitted in excess of the Acid Rain emissions limitations for
sulfur dioxide shall constitute a separate violation of the Act.

IV.C.3 An affected unit shall be subject to the requirements under Provision IV.C.1. of the sulfur
dioxide requirements as follows:

IV.C.3.a Starting January 1, 2000, an affected unit under 40 CFR 72.6(a)(2); or

IV.C.3.b Starting on the later of January 1, 2000 or the deadline for monitor
certification under 40 CFR Part 75, an affected unit under 40 CFR
72.6(a)(3).

IV.C.4 Allowances shall be held in, deducted from, or transferred among Allowance Tracking
System accounts in accordance with the Acid Rain Program.

IV.C.5 An allowance shall not be deducted in order to comply with the requirements under
Provision IV.C.1.a. of the sulfur dioxide requirements prior to the calendar year for which
the allowance was allocated.

IV.C.6 An allowance allocated by the Administrator, USEPA, under the Acid Rain Program is a
limited authorization to emit sulfur dioxide in accordance with the Acid Rain Program. No
provision of the Acid Rain Program, the Acid Rain permit application, the Acid Rain
permit, or the written exemption under 40 CFR 72.7 and 72.8 and no provision of law shall
be construed to limit the authority of the United States to terminate or limit such
authorization.

IV.C.7 An allowance allocated by the Administrator, USEPA, under the Acid Rain Program does
not constitute a property right.

IV.D Nitrogen Oxides Requirements.

The owner and operators of the source and each affected unit at the source shall comply
with the applicable Acid Rain emissions limitations of nitrogen oxide.

IV.E Monitoring Requirements.

IV.E.1 The owners and operators and, to the extent applicable, designated representative of each
affected unit at the source shall comply with the monitoring requirements as provided in 40
CFR Parts 74, 75, and 76.
44
IV.E.2 The emissions measurements recorded and reported in accordance with 40 CFR Part 75
shall be used to determine compliance by the unit with the Acid Rain emissions limitations
and emissions reduction requirements for sulfur dioxide and nitrogen oxides under the Acid
Rain Program.

IV.E.3 The requirements of 40 CFR Parts 74 and 75 shall not affect the responsibility of the
owners and operators to monitor emissions of other pollutants or other emissions
characteristics at the unit under other applicable requirements of the Act and other
provisions of the operating permit for the source.

IV.F Recordkeeping and Reporting Requirements.

IV.F.1 Unless otherwise provided, the owners and operators for each affected unit at the source
shall keep on site at the source each of the following documents for a period of 5 years
from the date the document is created. This period may be extended for cause, at any time
prior to the end of 5 years, in writing by the Administrator, USEPA, or Director:

IV.F.1.a The certificate of representation for the designated representative for the source and each
affected unit at the source and all documents that demonstrate the truth of the statements in
the certificate of representation, in accordance with 40 CFR 72.24; provided that the
certificate and documents shall be retained on site at the source beyond such 5-year period
until such documents are superseded because of the submission of a new certificate of
representation changing the designated representative;

IV.F.1.b All emissions monitoring information, in accordance with 40 CFR Part 75;

IV.F.1.c

Copies of all reports, compliance certifications, and other submissions and all records made
or required under the Acid Rain Program; and,

IV.F.1.d

Copies of all documents used to complete an Acid Rain permit application and any other
submission under the Acid Rain Program or to demonstrate compliance with the
requirements of the Acid Rain Program.

IV.F.2 The designated representative of each affected unit at the source shall submit the reports
and compliance certifications required under the Acid Rain Program, including those under
40 CFR Part 72 Subpart I and 40 CFR Part 75.

IV.G Excess Emissions Requirements.

IV.G.1 The designated representative of an affected unit that has excess emissions in any calendar
year shall submit a proposed offset plan to the Administrator, USEPA, as required under 40
CFR Part 77.

IV.G.2 The owners and operators of an affected unit that has excess emissions in any calendar year
shall:

IV.G.2.a Pay without demand the penalty required, and pay upon demand the interest on that
penalty, to the Administrator, USEPA, as required by 40 CFR Part 77; and

IV.G.2.b Comply with the terms of an approved offset plan, as required by 40 CFR Part 77.

45
IV.H Liability.

IV.H.1 Any person who knowingly violates any requirement or prohibition of the Acid Rain
Program, a complete Acid Rain permit application, an Acid Rain permit, or a written
exemption under R307-417, 40 CFR 72.7 or 40 CFR 72.8, including any requirement for
the payment of any penalty owed to the United States, shall be subject to enforcement
pursuant to section 113(c) of the Act.

IV.H.2 Any person who knowingly makes a false, material statement in any record, submission, or
report under the Acid Rain Program shall be subject to criminal enforcement pursuant to
section 113(c) of the Act and 18 U.S.C. 1001.

IV.H.3 No permit revision shall excuse any violation of the requirements of the Acid Rain
Program that occurs prior to the date that the revision takes effect.

IV.H.4 Each affected source and each affected unit shall meet the requirements of the Acid Rain
Program.

IV.H.5 Any provision of the Acid Rain Program that applies to an affected source (including a
provision applicable to the designated representative of an affected source) shall also apply
to the owners and operators of such source and of the affected units at the source.

IV.H.6 Any provision of the Acid Rain Program that applies to an affected unit (including a
provision applicable to the designated representative of an affected unit) shall also apply to
the owners and operators of such unit. Except as provided under 40 CFR 72.44 (Phase II
repowering extension plans) and 40 CFR 76.11 (NOx averaging plans), and except with
regard to the requirements applicable to units with a common stack under 40 CFR part 75
(including 40 CFR 75.16, 75.17, and 75.18), the owners and operators and the designated
representative of one affected unit shall not be liable for any violation by any other affected
unit of which they are not owners or operators or the designated representative and that is
located at a source of which they are not the owners and operators, owners or operators, or
the designated representative.

IV.H.7 Each violation of a provision of 40 CFR Parts 72, 73, 74, 75, 76, 77, and 78 by an affected
source or affected unit, or by an owner or operator or designated representative of such
source or unit, shall be a separate violation of the Act.

IV.H.8 The owners and operators of a unit governed by an approved early election plan shall be
liable for any violation of the plan or 40 CFR 76.8 at that unit. The owners and operators
shall be liable, beginning January 1, 2000, for fulfilling the obligations specified in 40 CFR
Part 77.

IV.I Effect on Other Authorities.

No provision of the Acid Rain Program, an Acid Rain permit application, an Acid Rain
permit, or a written exemption under 40 CFR 72.7 or 72.8 shall be construed as:

IV.I.1 Except as expressly provided in Title IV of the Act, exempting or excluding the owners and
operators and, to the extent applicable, the designated representative from compliance with
any other provision of the Act, including the provisions of Title I of the Act relating to
applicable National Ambient Air Quality Standards or the Utah State Implementation Plan;
46
IV.I.2 Limiting the number of allowances a unit can hold; provided, that the number of
allowances held by the unit shall not affect the source's obligation to comply with any other
provisions of the Act;

IV.I.3 Requiring a change of any kind in any State law regulating electric utility rates and
charges, affecting any State law regarding such State regulation, or limiting such State
regulation, including any prudence review requirements under such State law;

IV.I.4 Modifying the Federal Power Act or affecting the authority of the Federal Energy
Regulatory Commission under the Federal Power Act; or,

IV.I.5 Interfering with or impairing any program for competitive bidding for power supply in a
State in which such program is established.

Status: In compliance – The Acid Rain Annual Compliance Report is submitted as required.
The 2024 report will be submitted by February 2025. According to the Gadsby Power
Plant the facility has been subject to the Acid Rain Program since 1995.

MISSION INVENTORY: The 2023 Annual Emissions Inventory was submitted, to
the DAQ, on April 11, 2024.

47
PREVIOUS ENFORCEMENT
ACTIONS: None within the last five years.

COMPLIANCE ASSISTANCE: 1) Name change for annual emission fee invoice.

2) Experimental AO for sludge processing. See status of
condition II.A (item II.A.21).

3) Reduce black start engine’s idle time to < 30 minutes. See
status of condition II.B.9.g.

COMPLIANCE STATUS &
RECOMMENDATIONS: In compliance with the conditions of the Title V Operating
Permit 3500068006, dated January 30, 2024, and revised January
30, 2024, at time of the inspection.

HPV STATUS: N/A

RECOMMENDATION FOR
NEXT INSPECTION: Ten Year Review of AO DAQE-AN0103550015-09, is currently
in progress. Inspect as usual.

ATTACHMENTS: VEO Form
Correspondence
Joe Rockwell <[e-mail]>
PacifiCorp - Gadsby Plant Safety Orientation
2 messages
Tiberius, Leah (PacifiCorp) <[e-mail]>Thu, Nov 21, 2024 at 1:23 PM
To: "[e-mail]" <[e-mail]>
Hi Joe,

I have attached a pdf with a QR code that will link you to our safety video including a short quiz after the video. Please let
me know if you have any problems with the software.

Thank you,

Leah Tiberius
Environmental Analyst
1359 West North Temple - rear
Salt Lake City, Ut 84116
801-220-7708 Office
801-455-6715 Mobile

2024 SAFETY VIDEO LINK.pdf
79K
Joe Rockwell <[e-mail]>Thu, Nov 21, 2024 at 9:14 PM
To: "Tiberius, Leah (PacifiCorp)" <[e-mail]>
Hi Leah -
Watched the video and took and passed (26/27) the test.
See you on Tuesday November 26 @ 9:00 am for the inspection.
Thank you,
Joe Rockwell | Environmental Scientist
Phone: [phone]
11/27/24, 8:27 PM State of Utah Mail - PacifiCorp - Gadsby Plant Safety Orientation
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1816364982660454361&simpl=msg-f:18163649826604543…1/2

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]
11/27/24, 8:27 PM State of Utah Mail - PacifiCorp - Gadsby Plant Safety Orientation
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1816364982660454361&simpl=msg-f:18163649826604543…2/2
Joe Rockwell <[e-mail]>
10335 Pacificorp Gadsby Title V Inventory Payment
2 messages
David Beatty <[e-mail]>Tue, Nov 26, 2024 at 10:28 AM
To: "Lewis, Scarlet (PacifiCorp)" <[e-mail]>, Joe Rockwell <[e-mail]>
The payment for 2023 emissions inventory (FY2025 Fee) was received and credited on September 30, 2024 in the
amount of $22,098.67 (check #3872384)
--
David P. Beatty, P.E.
Manager | Operating Permits Section
Phone: [phone]
Emails to and from this email address may be considered public records and thus subject to Utah GRAMA
requirements.
Joe Rockwell <[e-mail]>Tue, Nov 26, 2024 at 10:31 AM
To: David Beatty <[e-mail]>
Thanks Dave!
[Quoted text hidden]
11/27/24, 8:23 PM State of Utah Mail - 10335 Pacificorp Gadsby Title V Inventory Payment
https://mail.google.com/mail/u/0/?ik=391b7b8965&view=pt&search=all&permthid=thread-f:1816807045085546456&simpl=msg-f:18168070450855464…1/1