DAQ-2025-001321

1
DAQC-187-25
Site ID 10034 (B1)

MEMORANDUM

TO: FILE – GREEN NATURAL GAS VENTURES, LLC (GNG) – Lisbon Valley
Helium Plant (Formerly Paradox Midstream)

THROUGH: Harold A. Burge, Major Source Compliance Section Manager

FROM: Joseph Randolph, Environmental Scientist

DATE: February 10, 2025

SUBJECT: FULL COMPLIANCE EVALUATION, Major, San Juan County,
FRS ID #UT0000004903700014
INSPECTION DATE: February 4-5, 2025. Records received February 6, 2025.

SOURCE ADDRESS: 7 Rankine Road, La Sal, UT 84530-0215. Approximately 35 miles south
of Moab, San Juan County; Take Highway 191 south out of Moab. Past
mile marker 96 take Wheeler road. Travel east on this road
approximately 4.5 miles and turn left again (north). The plant is 1.8 miles
up this road (County Road 111).

SOURCE CONTACT: Coy Young, PM: 435-631-2131, cell 970-739-3148
Ken Lapham GNG contact; 713-379-6305

Mailing address:
Jason Selch, Manager
Green Natural Gas Ventures, LLC
7 Rankine Road
La Sal, UT 84530-0215

OPERATING STATUS: Not Operating. Site was shut down December 5, 2024, when power was
turned off. The site has shut down both inlet and outlet lines. The site is
maintaining 40 psi of sweet gas in lines to keep values and pipes from
corroding. The site is using buy back gas from Williams to keep flare
pilot lights going (at about 20 Mscf per day). DOGM has indicated that
the well field leases have been cancelled and wells are shut in.

PROCESS DESCRIPTION:

Natural Gas Processing - The Lisbon Valley Helium Plant is a natural gas processing plant which extracts
natural gas and crude oil from the Lisbon Oil Field. The natural gas, crude oil, and produced water are
brought from the field into the plant by pipeline in three different pressure streams: the 150 pounds per
square inch (psi) system, the 400 psi system, and the 800 psi system. Sixty million standard cubic feet per
day of natural gas is the design inlet stream of the plant. In the process separation building, the products
from the inlet stream are separated into gas, crude oil, and produced water. The crude oil is stabilized in
the stabilizer tower, and then transferred to two 5,000-barrel (bbl) tanks. Once sold, the crude oil is
shipped via pipeline from this storage facility. This facility can produce up to 1,440 bbl of crude oil per 0 ( 8
2
day. Emissions from the two 5,000 bbl tanks are injected into the plant fuel gas system through a closed
duct system. The produced water flows to a separator where the majority of the water is separated out and
injected into a state approved water injection well. The remaining oil/water mixture is routed to a
secondary oil recovery tank (emission source E28) where it is heated by a natural gas-fired steam boiler
(emission source E27) and separated into oil and water. The oil from this tank is sent to storage and water
is also routed to the water injection well.

Inlet gas, after oil separation, flows through a low and high pressure methyldiethanolamine (MDEA)
system, which consists of liquid flowing down the contactor. The lean MDEA liquid, which has a high
affinity for hydrogen sulfide (H2S) and carbon dioxide (CO2), absorbs H2S and CO2 out of the gas stream.
The high concentrations of H2S and CO2 in the rich MDEA are released during the heating process, and
the rich MDEA is converted back to lean MDEA. Once regenerated, the lean MDEA is routed back to the
contactor for additional H2S and CO2 removal from the continuous inlet gas stream.

Gas from the MDEA regenerator (acid gas) either enters the Sulfur Recovery Unit (SRU), Sulfur
Enrichment and Injection Unit (SEI), or is deep well injected. The SRU and SEI are currently out of
service, and all gases from the MDEA are being deep well injected. The plant maintains the option to
utilize the SRU and SEI and associated incinerator.

In the SRU, the H2S in the acid gas is converted to liquid sulfur in a two-stage catalytic reaction involving
three converters - the Selectox converter and two Claus converters. The Selectox converter uses a
premium specialty catalyst appropriate for exceptionally lean acid gas streams. Averaging 4 percent H2S,
the acid gas entering the Selectox converter is reduced to a composition of approximately 1 percent H2S.
The acid gas then goes through two conventional Claus converters where additional H2S is removed.
Conversion efficiency across the Claus converters is unusually low because the acid gas concentration is
at the lower limit of application for Claus catalyst technology. The liquid sulfur from all three converters
runs into storage tanks where the temperature is maintained above 250o F until trucks can move the
product to market.

The SEI uses the compound Flexsorb® SE to scrub H2S from the H2S + CO2 gas stream. The gas stream
entering the SEI from the MDEA is approximately 4% H2S and 96% CO2. Following the use of
Flexsorb® SE, the gas is separated into two streams. The first is roughly a 50/50 mixture of H2S and
CO2. The second is mainly CO2 with trace amounts of H2S. The 50/50 mixture is deep well injected and
the second stream is tail gas.

Tail gas leaving the Claus reactors or SEI flows to the incinerator which operates at approximately
1500o F. At this temperature, sulfur compounds are oxidized to form SO2. The hot gas is then cooled in a
steam boiler, producing a significant portion of the Lisbon Gas Plant’s steam supply. After being cooled,
the exhaust gas is vented to the atmosphere.

The facility has several compressors which compress the natural gas to increase flow through the pipeline.
All the compressors run on well quality natural gas. There are also two natural gas fired steam boilers to
provide steam to the distillation process. The company has two diesel fired generators which are used to
power fire water pumps and to provide electrical power in case of emergencies. These are not used as part
of any processes on site.

3
APPLICABLE
REGULATIONS: Title V Operating Permit # 3700014004, dated November 23, 2021
40 CFR 60 Subpart Dc – Small Industrial steam generating units
40 CFR 60, Subpart KKK – Equipment leaks of VOC on shore NG processing
plant
40 CFR 60, Subpart LLL – Onshore NG processing
40 CFR 60, Subpart OOOO – Crude oil/NG production, Transmission,
Distribution
40 CFR 63, Subpart HH – HAPS from NG production facilities
40 CFR 63, subpart ZZZZ – RICE
40 CFR 64 – Compliance Assurance Monitoring
State Rules.

SOURCE INSPECTION
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: Not evaluated. 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:

See status below.
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))

4
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: Not in compliance. GNG did comply with all conditions of its permit. See below.

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:

The current permit expires November 23, 2026. Renewal Application is due May 23, 2026.
Company is aware of the dates.

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:

The current permit expires November 23, 2026. Renewal application is due May 23, 2026.

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: There have been no challenges to any portion of this permit. All conditions are valid and in force. 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))
5
I.G.2 The emission fee shall be due on October 1 of each calendar year or 45 days after the source
receives notice of the amount of the fee, whichever is later. (R307-415-9(4)(a))

Status: In compliance. Emission fees have been paid as invoiced. GNG took this site over on March 1,
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))

Not evaluated. 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))

Not evaluated. This is statement of fact and not an inspection item.
I.J Inspection and Entry.

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

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

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

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

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

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

Status: In compliance. Access to the facility was granted for inspection. Available records were
provided upon request. No samples were taken. No claims of confidentiality were made.

6
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. Last records submitted by GNG had statement and signature. Most required
records have not been submitted since October 2024.

I.L Compliance Certification.

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

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

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

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

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

7
I.L.2 The permittee shall also submit all compliance certifications to the EPA, Region VIII, at the
following address or to such other address as may be required by the Director: (R307-415-6c(5)(d))

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

Status: Not in compliance. GNG bought and took over operations on March 1, 2024 (using existing
Title V permit). The cert was due September 30, 2024. No certification has been submitted to
date. Numerous calls to listed company officials have not been returned. The on-site contact
has indicated he does not do this report.

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))

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

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

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

Status: Permit shields are listed in section III below, if applicable.

8
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))

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:

No emergencies have been reported since GNG took over March 1, 2024.
I.O Operational Flexibility.

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

Not evaluated. This is a statement of fact and not an inspection item.
I.P Off-permit Changes.

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

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

9
I.Q Administrative Permit Amendments.

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

Not evaluated. This is a statement of fact and not an inspection item.
I.R Permit Modifications.

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

Not evaluated. This is a statement of fact and not an inspection item.
I.S Records and Reporting.

I.S.1 Records.

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

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

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

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

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

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

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

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

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

I.S.2 Reports.

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

10
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

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

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

Status: Not in compliance. GNG bought and took over operations on March 1, 2024 (using existing
Title V permit). The cert and most recent semi-annual report were due September 30, 2024.
No certification or semi-annual reports have been submitted to date. Numerous calls to listed
company officials have not been returned. The on-site contact has indicated he does not do
this report. In addition, GNG has not filed any reports for the deviations noted in this
inspection memo.
11
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:

Not evaluated. This is a statement of fact and not an inspection item.
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. GNG bought and took over operations on March 1, 2024 (using existing Title
V permit). The 2023 inventory was due April 15, 2024, and submitted September 6, 2024. The
2024 inventory is not due at this time.

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:

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

12
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 Reciprocating Engine (E1)
900 bhp reciprocating internal combustion compressor engine (E1), natural gas fired, 3-way Non-
Selective Catalytic Reduction (NSCR) controlled (installed in 2005).

II.A.3 Reciprocating Engine (E3)
900 bhp reciprocating internal combustion compressor engines (E3), natural gas fired, Non-Selective
Catalytic Reduction (NSCR) controlled (installed in 2003).

II.A.4 Reciprocating Engines (E4A & E4B)
Two 1478 bhp reciprocating internal combustion compressor engines (E4A & E4B) (Replacement-in-kind
in 2014). E4A was manufactured in 1998 and E4B was manufactured in 1992. Both engines are natural
gas fired, Non-Selective Catalytic Reduction (NSCR) controlled, NSPS KKK.

II.A.5 Reciprocating Engines (E2, E4 & E5)
Three 900 bhp Reciprocating internal combustion compressor engines (E2, E4, & E5), natural gas fired,
pre-1969, existing non-emergency 4SRB without NSCR controls, 40 CFR 63 Subpart ZZZZ

II.A.6 NESHP ZZZZ non-emergency remote engine group
Includes Engines E1, E3, E4A, E4B, E2, E4, & E5, existing non-emergency 4SRB greater than 500 hp. 40
CFR 63 Subpart ZZZZ

II.A.7 Turbine Engines (E6 thru E11)
Six 850 bhp turbine compressor engines (E6, E7, E8, E9, E10, E11), natural gas fired, pre-1969. No unit-
specific applicable requirements.

II.A.8 Heat Medium Heater (E12)
47.54 MMBtu/hr, natural gas fired, a waste heat recovery system, recovers the exhaust heat from E8, E9,
E10, & E11. Exhaust from the heater passes through two stacks (E12A & E12B), pre-1969. No unit-
specific applicable requirements.

II.A.9 Boilers (E13 & E14)
Two natural gas fired boilers (E13 & E14) rated at 66.9 MMBtu/hr each, generates steam for process heat
throughout the plant, equipped with flue gas recirculation emissions control, NSPS Dc.

II.A.10 DGA polisher
The diglycolamine (DGA) polisher process removes minute amounts of H2S, COS, and CO2 which pass
through the MDEA system. No unit-specific applicable requirements.

II.A.11 TEG dehydrator (E21)
Triethylene glycol (TEG) dehydrator removes water from the gas stream. Emissions from the TEG
dehydrator are controlled by a condenser which vents to the atmosphere. 40 CFR 63 Subpart HH, Pre-
1969.

13
II.A.12 Molecular Sieve
The molecular sieve beds are heated with natural gas to absorb the water from the gas stream. No unit-
specific applicable requirements.

II.A.13 Dehydration Process Unit
Includes DGA polisher, TEG dehydrator, and Molecular Sieve. NSPS KKK. No unit-specific applicable
requirements.

II.A.14 Gas Sweetening Process Unit
Includes two methyldiethanolamine (MDEA) stages to absorb H2S and CO2 from the gas stream. Acid gas
released from MDEA liquid during MDEA regeneration process is routed to either the SRU (Emission
Unit #12) or SEI (Emission Unit #27). NSPS LLL and KKK.

II.A.15 Sulfur Recovery Unit
Two stage catalytic reaction using three converters (Selectox converter and two Claus converters) to
convert H2S to liquid sulfur, followed by the incinerator, NSPS LLL.

II.A.16 Sulfur Enrichment and Injection Unit (SEI)
SEI removes the H2S from the acid gas generated from the sweetening unit, compresses the H2S-rich off-
gas, then injects the off-gas into off-site wells. Some acid gas is routed to the incinerator.

II.A.17 Incinerator (E15)
Natural gas fired incinerator (76 MMBtu/hr) to control tailgas from the sulfur recovery unit, or absorber
acid gas from the sulfur enrichment unit. NSPS LLL.

II.A.18 Upset Flare (E16)
Emergency upset flare to control the acid gas from the MDEA regenerator during power failures and
breakdowns. The flare is also connected with the pressure relief valve system. The exhaust gas from DGA
process is also routed to the flare. NSPS A, KKK.

II.A.19 CRYO Process Unit
Liquefies and separates the natural gas liquids from nitrogen, helium, and a portion of methane. Includes

Chiller Separator/Nitrogen Rejection Unit (NRU), NRU Feed Tower, Demethanizer Tower, Nitrogen
Rectifier Columns, and Raw Mix Treater, NSPS KKK, No unit-specific applicable requirements.

II.A.20 40 CFR Part 60, Subpart KKK Applicable Equipment
A group of equipment defined in 40 CFR 60.631 includes Reciprocating Engines (E4A & E4B),
Dehydration Process Unit, Gas Sweetening Process Unit, Upset Flare, and CRYO Process Unit.

II.A.21 Emergency Fire Water Engine (E17)
300 bhp, diesel, provides emergency fire water pressure during emergency situations when electrical
power is not available to operate the fire water system. No unit-specific applicable requirements.

II.A.22 Emergency Generator (E18)
1575 bhp, diesel, provides lighting and power during emergency shutdowns or power failures. No unit-
specific applicable requirements.

II.A.23 Emergency Compressed Ignition ICE (E17&18)
Existing emergency compressed ignition internal combustion engines (ICE), includes Engines E17 and
E18, 40 CFR 63 Subpart ZZZZ.
14
II.A.24 Regenerative Gas Heater (E19)
3 MMBtu/hr, natural gas fired, used to regenerate molecular sieve bed located upstream of the cryogenic
process.

II.A.25 Regenerative Gas Heater (E20)
1.775 MMBtu/hr, natural gas fired, used to regenerate molecular sieve beds downstream of the
debutanizer when the fractionation process is in operation, pre-1969. No unit-specific applicable
requirements.

II.A.26 Fractionation Process Unit
Includes de-ethanizer, debutanizer, DGA, molecular sieve, and de-propanizer process units to produce
propane and butane. Pre-1969. No unit-specific applicable requirements.

II.A.27 Crude Oil/Condensate Tanks (E23)
Two storage tanks having 5,000 barrels capacity each (794 cubic meters). Emissions from the tank will be
routed either through Vapor Recovery Unit (VRU) or Flare (E29). Non-NSPS.

II.A.28 Vapor Recovery Unit (VRU)
Controls VOC emission from Crude Oil/Condensate Tanks (E23)

II.A.29 Flare/Combustor (E29)
2.1 MMBtu/hr combustor to control VOC emission from Crude Oil/Condensate Tanks (E23)

II.A.30 Natural gas fired heater (E26)
Circulates steam heat through two 10, 000 bbl fire water storage tanks, rated at 1.5 MMBtu/hr.

II.A.31 Gas fired steam boiler (E27)
Used to heat the secondary oil recovery tank, rated at 0.695 MMBtu/hr.

II.A.32 Secondary Oil Recovery Tank (E28)
Separates water from oil, 5,000 barrels. No unit-specific applicable requirements.

II.A.33 Loading Rack (E22)
Used to load truck trailers with propane and butane.

II.A.34 Pre-1969 equipment
Including Emission Units Reciprocating Engines (E2, E4 & E5), Turbine Engines, Heat Medium heater,
TEG dehydrator, Regenerative Gas Heater, and Fractionation Process Unit,

II.A.35 Storage Tank (SW1DOT)
One crude oil storage tank, 400 barrels (16,800 gallons).

II.A.36 Storage Tank (SW1BWT)
One waste water storage tank, 400 barrels (16,800 gallons).

Status: In compliance. During the 2024 inspection (September 4, 2024) the operational equipment with
permit specific requirements is: E4A, E4B, E5, non-emergency remote group engines, E14, TEG
dehydration (E21), Gas Sweetening Process Unit, E15, E16, CRYO Process Unit, E17, E18, E19,
E28, E26 (winter only), E22, and SW1BW. Remaining equipment is either replaced with electric,
out of service or no longer on-site. Currently: the site is shut down – see operating status above.

15
II.B Requirements and Limitations

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

II.B.1 Conditions on permitted source (Source-wide).

II.B.1.a Condition:

The natural gas processing rate for the Lisbon plant shall not exceed 65 MMSCF per day. [Origin:
DAQE-AN0100340024-16]. [R307-401-8]

II.B.1.a.1 Monitoring:

The daily volume of gas processed shall be determined by the use of gas flow meters and located
so that they can be read by an inspector at any time.

II.B.1.a.2 Recordkeeping:

The volume of natural gas processed shall be recorded daily in a log and shall be measured from
8:00 am of one day to 8:00 am of the following day during daylight savings periods and from
7:00 am of one to 7:00 am of the following day in the remainder of the year. Records shall be
maintained in accordance with Provision I.S.1 of this permit.

II.B.1.a.3 Reporting:

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

Status: In compliance. The natural gas processing rate is recorded daily as high and low pressure sides.
The processing rate until December 2024 was about 3-4 MMSCF/day on the low side and 2-3
MMSCF/day on the high side. Records review show this was average with no month sum over 14.2
MMSCF. As of December 5, 2024, the site is not producing with both inlet and outlet values shut.

II.B.1.b Condition:

A Risk Management Plan (RMP) developed in accordance with 40 CFR Part 68 shall be submitted to the
United States Environmental Protection Agency not later than the applicable date in 40 CFR 68 [Origin:
40 CFR 68.150(b)]. [40 CFR 68.150(b)]

II.B.1.b.1 Monitoring:

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

II.B.1.b.2 Recordkeeping:

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

16
II.B.1.b.3 Reporting:

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

Status: In compliance. The RMP has been developed and submitted as required. A copy is available onsite.
The most recent plan is dated February 20, 2023.

II.B.1.c Condition:

The permittee shall use only natural gas for all equipment except for emergency equipment which shall
use diesel fuel [Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.1.c.1 Monitoring:

A log shall be maintained which identifies any time fuel other than NG is used and the fuel type
used for each affected equipment.

II.B.1.c.2 Recordkeeping:

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

II.B.1.c.3 Reporting:

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

Status: In compliance. Only natural gas is used in the permitted equipment operated onsite, except for the
emergency units that operate on diesel. Records indicate that diesel is only burned in the emergency
equipment. No other fuel sources were noted. As of December 5, 2024, the site is using sweet gas at
40 psi to maintain lines with no production occurring.

II.B.1.d Condition:

At all times, including periods of startup, shutdown, and malfunction, the permittee shall, to the extent
practicable, maintain and operate any permitted plant equipment, including associated air pollution
control equipment, in a manner consistent with good air pollution control practice for minimizing
emissions. Determination of whether acceptable operating and maintenance procedures are being used
will be based on information available to the Director which may include, but is not limited to, monitoring
results, opacity observations, review of operating and maintenance procedures, and inspection of the
source. [[Origin: DAQE-AN0100340024-16]. [40 CFR 60.11(d), R307-401-8]

II.B.1.d.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.1.d.2 Recordkeeping:

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.

17
II.B.1.d.3 Reporting:

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

Status: In compliance. The facility appeared to be adequately and properly maintained at the time of the
inspection. Maintenance activities are tracked and recorded electronically through work orders
(MP2 computer software). As of December 5, 2024, the site is using sweet gas at 40 psi to maintain
lines with no production occurring.

II.B.2 Conditions on Reciprocating Engine E1.

II.B.2.a Condition:

Emissions of CO shall be no greater than 5.95 lbs/hr and 1105.0 ppm [Origin: DAQE- DAQE-
AN0100340024-16]. [R307-401-8]

II.B.2.a.1 Monitoring:

A. Stack Testing

The engine shall be tested at least once every 5 years, based on the date in which the most recent
stack test is performed. A pretest conference shall be held at least 30 days prior to the stack test if
directed by the Director and shall include the permittee, the tester, and the Director.

The following stack testing requirements shall be met:

(1) The emission sample point shall conform to the requirements of 40 CFR 60, Appendix A,
Method 1. In addition, Occupational Safety and Health Administration (OSHA) or Mine Safety
and Health Administration (MSHA) approved access shall be provided to the test location.

(2) Volumetric flow rate shall be determined using 40 CFR 60, Appendix A, Method 2.

(3) CO concentrations shall be determined using 40 CFR 60, Appendix A, Method 10.

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

(5) The operating load during testing shall be at least 90% of the maximum production in the
previous 3 year's operation.

B. Portable Analyzer Test

CO emissions testing shall be performed on each affected unit once every two years using a
portable analyzer or testing instrument capable of detecting emissions of the pollutant being
tested at the concentrations necessary to determine compliance. The tested unit shall be operated
under normal conditions and at a minimum of 90% of the maximum production or throughput
achieved since the last required test. A testing protocol shall be developed, documented, and used
for all tests. At a minimum, the following topics shall be addressed in the protocol:
18
(1) A description of sampling locations and sample gathering procedures that result in
representative and reproducible samples.

(2) Calibration and operation procedures for the analyzer.

(3) Methods used to determine the flow rate, temperature, and other parameters as necessary to
demonstrate compliance.

(4) Calculations and other information necessary to convert the analyzer output to the units of the
limitation.

The test protocol shall be made available to the Director upon request. If the Director determines
that the protocol does not adequately address the minimum requirements list above, or that the
protocol does not provide sufficient assurance that the test results are adequate for demonstrating
compliance with the limitation, the Director may require the permittee to modify the protocol.

II.B.2.a.2 Recordkeeping:

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

II.B.2.a.3 Reporting:

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

Status: Not evaluated. E1 was first reported as indefinitely out-of-service in memo DAQC-816-15.
Subsequent inspections confirm El was not operated. Prior to shut down, CO emissions testing
was performed once every two years using a portable analyzer. The results of the last test are:

Source Test Date Pollutant Result Limit
Unit El 8/01/12 CO 0.47 Ib/hr 5.95 Ib/hr

II.B.2.b Condition:

Visible emissions shall be no greater than 10 percent opacity. [Origin: DAQE-AN0100340024-16].
[R307-401-8]

II.B.2.b.1 Monitoring:

In lieu of opacity monitoring, the report required for this permit condition will serve as
monitoring.

II.B.2.b.2 Recordkeeping:

The report required for this permit condition will serve as recordkeeping. Records shall be
maintained in accordance with Provision I.S.1 of this permit.

19
II.B.2.b.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee shall
certify each annual certification report that only pipeline quality natural gas is used as fuel during
the reporting year.

Status: Not evaluated. Indefinitely out-of-service.

II.B.2.c Condition:

Emissions of NOx shall be no greater than 3.83 lbs/hr and 433.0 ppm. [Origin: DAQE-AN0100340024-
16]. [R307-401-8]

II.B.2.c.1 Monitoring:

(A) Stack Testing

Emissions shall be tested at least once every 5 years, based on the date in which the most recent
stack test is performed. A pretest conference shall be held at least 30 days prior to the stack test if
directed by the Director and shall include the permittee, the tester, and the Director.

The following stack testing requirements shall be met:

(1) The emission sample point shall conform to the requirements of 40 CFR 60, Appendix A,
Method 1. In addition, Occupational Safety and Health Administration (OSHA) or Mine Safety
and Health Administration (MSHA) approved access shall be provided to the test location.

(2) Volumetric flow rate shall be determined using 40 CFR 60, Appendix A, Method 2.

(3) NOx concentrations shall be determined using 40 CFR 60, Appendix A, Method 7e.

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

(5) The operating load during testing shall be at least 90% of the maximum production achieved
in the previous 3 year's operation.

(B) Temperature of exhaust gas into the catalyst and NOx emission, as measured by a portable
analyzer, shall be used as indicators to provide a reasonable assurance of compliance with the
NOx emission limitation as specified below:

(i) Temperature

(1) Measurement Approach: Exhaust gas temperature shall be monitored continuously using an
in-line thermocouple.

(2) Indicator Range: Temperature at the inlet of the catalyst shall be maintained between 750oF
and 1250oF. Excursions from this temperature range shall trigger an inspection and review of the
catalyst's performance as indicated by other parameters (to confirm if the temperature reading is
20
valid and to determine the catalyst operating deficiencies). If the excursion is the result of a
deficiency with the catalyst, then corrective actions and reporting are required.

(3) Performance Criteria:

(A) Data Representativeness: Temperature measurements made by a thermocouple sensor shall
provide a direct indicator of catalyst performance. A sensor shall be located at the inlet of the
catalyst. The minimum accuracy of the thermocouple is +/- 2%.

(B) QA/QC Practices and Criteria: Thermocouple is maintained per manufacturer's specifications.
It shall be tested semi-annually to ensure its accuracy.

(C) Monitoring Frequency: Temperature shall be monitored continuously when the engine is
operating.

(D) Data Collection Procedure: Temperature data shall be collected once per hour and recorded
on a log sheet when the engine is operating.

(E) Averaging Period: The temperature shall be recorded and reduced to 4-hour rolling averages
when the engine is operating.

(ii) Portable Analyzer Test

(1) Measurement Approach: NOx emission shall be measured using a portable hand-held Testo
analyzer during normal operating conditions.

(2) Indicator Range: Excursion from the NOx limit is defined as an emission rate of NOx at or
above 3.83 lbs/hr or 433.0 ppm. Excursions from this limit shall trigger an inspection and review
of the catalyst's performance as indicated by other parameters (to confirm if the result is valid and
to determine the catalyst operating deficiencies). If the excursion is the result of a deficiency with
the catalyst, then corrective actions and reporting are required.

(3) Performance Criteria:

(A) Data Representativeness: NOx emission shall be measured at the outlet of the catalyst.

(B) QA/QC Practices and Criteria: Testo analyzer shall be calibrated annually. A testing protocol
for performing a portable analyzer test shall be developed, documented, and used for all tests.

(C) Monitoring Frequency: NOx emission shall be analyzed semi-annually unless the stack testing
is performed at the same time or engine is not running.

(D) Data Collection Procedure: Records of calibration and testing shall be maintained in the
facilities computerized MP2. Also a strip chart of the result shall be kept in the engines' paper
files

(E) Averaging Period: NOx emission shall be calculated per the testing protocol developed in
accordance with II.B.2.c.1.B.(ii)(3)(B).

21
II.B.2.c.2 Recordkeeping:

In addition to the recordkeeping requirement described in Provision I.S.1 of this permit,

(a) The permittee shall maintain a file of all stack testing and all other information required by
permit provision I.S.1.

(b) The permittee shall maintain a file of continuous monitor measurements, including
performance testing measurements, all performance evaluations, all calibration checks, all
adjustments, and maintenance.

(c) The permittee shall maintain a file of the occurrence and duration of any excursion, corrective
actions taken, and any other supporting information required to be maintained under 40 CFR 64
(such as data used to document the adequacy of monitoring, or records of monitoring
maintenance or corrective actions). Instead of paper records, the permittee may maintain records
on alternative media, such as microfilm, computer files, magnetic tape disks, or microfiche,
provided that the use of such alternative media allows for expeditious inspection and review, and
does not conflict with other applicable recordkeeping requirements. (40 CFR 64.9(b)).

II.B.2.c.3 Reporting:

In addition to the reporting requirements described in Provision I.S.2 of this permit,

(a) The monitoring report required in Provision I.S.2 of this permit shall include, at a minimum,
the following information, as applicable:

(1) Summary information on the number, duration and cause (including unknown cause, if
applicable) of excursions or exceedances, as applicable, and the corrective actions taken;(40 CFR
64.9(a)(2)(i))

(2) Summary information on the number, duration and cause (including unknown cause, if
applicable) for monitor downtime incidents (other than downtime associated with zero and span
or other daily calibration checks, if applicable). (40 CFR 64.9(a)(2)(ii))

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

Status: Not evaluated. E1 was first reported as indefinitely out-of-service in memo DAQC-816-15.
Subsequent inspections confirm El was not operated. The results of the last test are:

Source Test Date Pollutant Result Limit
E1 10/5/10 NOx 1.77 1b/hr 3.83 Ib/hr

22
II.B.3 Conditions on Reciprocating Engine E3.

II.B.3.a Condition:

Emissions of CO shall be no greater than 5.95 lbs/hr and 1105.0 ppm
[Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.3.a.1 Monitoring:

A. CO emissions testing shall be performed on each affected unit once every two years using a
portable analyzer or testing instrument capable of detecting emissions of the pollutant being
tested at the concentrations necessary to determine compliance. The tested unit shall be operated
under normal conditions and at a minimum of 90% of the maximum production or throughput
achieved since the last required test. A testing protocol shall be developed, documented, and used
for all tests. At a minimum, the following topics shall be addressed in the protocol:

(1) A description of sampling locations and sample gathering procedures that result in
representative and reproducible samples.

(2) Calibration and operation procedures for the analyzer.

(3) Methods used to determine the flow rate, temperature, and other parameters as necessary to
demonstrate compliance.

(4) Calculations and other information necessary to convert the analyzer output to the units of the
limitation.

The test protocol shall be made available to the Director upon request. If the Director determines
that the protocol does not adequately address the minimum requirements list above, or that the
protocol does not provide sufficient assurance that the test results are adequate for demonstrating
compliance with the limitation, the Director may require the permittee to modify the protocol.

B. Stack testing to demonstrate compliance with CO limits shall be conducted at least once every
5 years. A pretest conference shall be held at least 30 days prior to the stack test if directed by the
Director and shall include the permittee, the tester, and the Director.

The following stack testing requirements shall be met:

(1) The emission sample point shall conform to the requirements of 40 CFR 60, Appendix A,
Method 1. In addition, Occupational Safety and Health Administration (OSHA) or Mine Safety
and Health Administration (MSHA) approved access shall be provided to the test location.

(2) Volumetric flow rate shall be determined using 40 CFR 60, Appendix A, Method 2.

(3) CO concentrations shall be determined using 40 CFR 60, Appendix A, Method 10.

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

23
(5) The operating load during testing shall be at least 90% of the maximum production achieved
in the previous 3 year's operation.

II.B.3.a.2 Recordkeeping:

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

II.B.3.a.3 Reporting:

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

Status: Not evaluated. Engine E3 was removed from service in 2019, after failed stack test. It may be
restarted in the future and the company is aware of the requirements if restarted.

II.B.3.b Condition:

Emissions of NOx shall be no greater than 3.83 lbs/hr and 433.0 ppm.
[Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.3.b.1 Monitoring:

(A) Stack testing to demonstrate compliance with NOx limits shall be conducted at least once
every 5 years when the affected unit is operating. A pretest conference shall be held at least 30
days prior to the stack test if directed by the Director and shall include the permittee, the tester,
and the Director.

The following stack testing requirements shall be met:

(1) The emission sample point shall conform to the requirements of 40 CFR 60, Appendix A,
Method 1. In addition, Occupational Safety and Health Administration (OSHA) or Mine Safety
and Health Administration (MSHA) approved access shall be provided to the test location.

(2) Volumetric flow rate shall be determined using 40 CFR 60, Appendix A, Method 2.

(3) NOx concentrations shall be determined using 40 CFR 60, Appendix A, Method 7e.

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

(5) The operating load during testing shall be at least 90% of the maximum production achieved
in the previous 3 year's operation.

(B) The temperature of exhaust gas into the catalyst and NOx emission, as measured by a portable
analyzer, shall be used as indicators to provide a reasonable assurance of compliance with the
NOx emission limitation as specified below:
24
(i) Temperature

(1) Measurement Approach: Exhaust gas temperature shall be monitored continuously using an
in-line thermocouple.

(2) Indicator Range: Temperature at the inlet of the catalyst shall be maintained between 750oF
and 1250oF. Excursions from this temperature range shall trigger an inspection and review of the
catalyst's performance as indicated by other parameters (to confirm if the temperature reading is
valid and to determine the catalyst operating deficiencies). If the excursion is the result of a
deficiency with the catalyst, then corrective actions and reporting are required.
(3) Performance Criteria:

(A) Data Representativeness: Temperature measurements made by a thermocouple sensor shall
provide a direct indicator of catalyst performance. A sensor shall be located at the inlet of the
catalyst. The minimum accuracy of the thermocouple is +/- 2%.

(B) QA/QC Practices and Criteria: Thermocouple shall be maintained per manufacturer's
specifications. It shall be tested semi-annually to ensure its accuracy.

(C) Monitoring Frequency: Temperature shall be monitored continuously when the engine is
operating.

(D) Data Collection Procedure: Temperature data shall be collected once per hour and recorded
on a log sheet when the engine is operating.

(E) Averaging Period: The temperature shall be recorded and reduced to 4-hour rolling averages
when the engine is operating.

(ii) Portable Analyzer Test

(1) Measurement Approach: NOx emission shall be measured using a portable hand-held Testo
analyzer during normal operating conditions.

(2) Indicator Range: Excursion from the NOx limit is defined as an emission rate of NOx at or
above 3.83 lbs/hr or 433.0 ppm. Excursions from this limit shall trigger an inspection and review
of the catalyst's performance as indicated by other parameters (to confirm if the result is valid and
to determine the catalyst operating deficiencies). If the excursion is the result of a deficiency with
the catalyst, then corrective actions and reporting are required.

(3) Performance Criteria:

(A) Data Representativeness: NOx emission shall be measured at the outlet of the catalyst.

(B) QA/QC Practices and Criteria: Testo analyzer shall be calibrated annually. A testing protocol
for performing a portable analyzer test shall be developed, documented, and used for all tests.

(C) Monitoring Frequency: NOx emission shall be analyzed semi-annually unless the stack testing
is performed at the same time or the engine is not running.

25
(D) Data Collection Procedure: Records of calibration and testing shall be maintained in the
facilities computerized MP2. Also a strip chart of the result shall be kept in the engines' paper
files

(E) Averaging Period: NOx emission shall be calculated per the testing protocol developed in
accordance with condition II.B.3.b.1.(B)(ii)(3)(B).

II.B.3.b.2 Recordkeeping:

In addition to the recordkeeping requirement described in Provision I.S.1 of this permit,

(a) The permittee shall maintain a file of all stack testing and all other information required by
permit provision I.S.1.

(b) The permittee shall maintain a file of continuous monitor measurements, including
performance testing measurements, all performance evaluations, all calibration checks, all
adjustments, and maintenance.

(c) The permittee shall maintain a file of the occurrence and duration of any excursion, corrective
actions taken, and any other supporting information required to be maintained under 40 CFR 64
(such as data used to document the adequacy of monitoring, or records of monitoring
maintenance or corrective actions). Instead of paper records, the permittee may maintain records
on alternative media, such as microfilm, computer files, magnetic tape disks, or microfiche,
provided that the use of such alternative media allows for expeditious inspection and review, and
does not conflict with other applicable recordkeeping requirements. (40 CFR 64.9(b)).

II.B.3.b.3 Reporting:

In addition to the reporting requirement described in Provision I.S.2 of this permit,

(a) The monitoring report required in Provision I.S.2 of this permit shall include, at a minimum,
the following information, as applicable:

(1) Summary information on the number, duration and cause (including unknown cause, if
applicable) of excursions or exceedances, as applicable, and the corrective actions taken;(40 CFR
64.9(a)(2)(i))

(2) Summary information on the number, duration and cause (including unknown cause, if
applicable) for monitor downtime incidents (other than downtime associated with zero and span
or other daily calibration checks, if applicable). (40 CFR 64.9(a)(2)(ii))

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

Status: Not evaluated. Engine E3 was removed from service in 2019, after failed stack test. It may be
restarted in the future and the company is aware of the requirements if restarted.

26
II.B.3.c Condition:

Visible emissions shall be no greater than 10 percent opacity [Origin: DAQE-AN0100340024-16].
[R307-401-8]

II.B.3.c.1 Monitoring:

In lieu of opacity monitoring, the report required for this permit condition will serve as
monitoring.

II.B.3.c.2 Recordkeeping:

The report required for this permit condition will serve as recordkeeping. Records shall be
maintained in accordance with Provision I.S.1 of this permit.

II.B.3.c.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee shall
certify each annual certification report that only pipeline quality natural gas is used as fuel during
the reporting year.

Status: Not evaluated. Engine E3 was removed from service in 2019, after failed stack test. It may be
restarted in the future and the company is aware of the requirements if restarted.

II.B.4 Conditions on Reciprocating Engines (E4A & E4B).

II.B.4.a Condition:

Emissions of CO shall be no greater than 4.88 lbs/hr and 964 ppmdv from each engine.
[Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.4.a.1 Monitoring:

(A) Initial compliance testing shall be performed as soon as possible and in no case later 180 days
after the startup of the new engines. After the initial testing, stack testing shall be conducted at
least once every 5 years. A pretest conference shall be held at least 30 days prior to the stack test
if directed by the Director and shall include the permittee, the tester, and the Director.

The following stack testing requirements shall be met:

(1) The emission sample point shall conform to the requirements of 40 CFR 60, Appendix A,
Method 1. In addition, Occupational Safety and Health Administration (OSHA) or Mine Safety
and Health Administration (MSHA) approved access shall be provided to the test location.

(2) Volumetric flow rate shall be determined using 40 CFR 60, Appendix A, Method 2.

(3) CO concentrations shall be determined using 40 CFR 60, Appendix A, Method 10.

(4) To determine mass emission rates (lb/hr, etc) the pollutant concentration as determined by the
appropriate methods above shall be multiplied by the volumetric flow rate and any necessary
conversion factors determined by the Director to give the results in the specified units of the
27
emission limitation.

(5) The operating load during testing shall be at least 90% of the maximum production achieved
in for the previous 3 year's operation.

(B) The temperature of exhaust gas into the catalyst, CO emissions measured by a portable
analyzer, and oxygen concentration at the engine exhaust shall be used as indicators to provide a
reasonable assurance of compliance with the CO emission limitation as specified below:

(i) Temperature

(1) Measurement Approach: Exhaust gas temperature shall be monitored continuously using an
in-line thermocouple.

(2) Indicator Range: Temperature at the inlet of the catalyst shall be maintained between 750oF
and 1250oF. Excursions from the temperature range shall trigger an inspection and review of the
catalyst’s performance as indicated by other parameters (to confirm if the temperature reading is
valid and to determine the catalyst operating deficiencies). If the excursion is the result of a
deficiency with the catalyst, then corrective actions and reporting are required.

(3) Performance Criteria:

(A) Data Representativeness: Temperature measurements made by a thermocouple sensor shall
provide a direct indicator of catalyst performance. A sensor shall be located at the inlet of the
catalyst. The minimum accuracy of the thermocouple is +/- 2%.

(B) QA/QC Practices and Criteria: Thermocouple is maintained per manufacturer's specifications.
It shall be tested semi-annually to ensure its accuracy.

(C) Monitoring Frequency: Temperature shall be monitored continuously when the engine is
operating.

(D) Data Collection Procedure: Temperature data shall be collected once per hour and recorded
on a log sheet when the engine is operating.

(E) Averaging Period: The temperature shall be recorded and reduced to 4-hour rolling averages
when the engine is operating.

(ii) Portable Analyzer Test

(1) Measurement Approach: CO emission shall be measured using a portable hand-held Testo
analyzer during normal operating conditions.

(2) Indicator Range: Excursion from the CO limit is defined as an emission rate of CO at or above
4.88 lbs/hr or 964 ppmdv. Excursions from this limit shall trigger an inspection and review of the
catalyst’s performance as indicated by other parameters (to confirm if the result is valid and to
determine the catalyst operating deficiencies). If the excursion is the result of a deficiency with
the catalyst, then corrective actions and reporting are required.

28
(3) Performance Criteria:

(A) Data Representativeness: CO emission shall be measured at the outlet of the catalyst.

(B) QA/QC Practices and Criteria: Testo analyzer shall be calibrated annually. A testing protocol
for performing a portable analyzer test shall be developed, documented, and used for all tests.
(C) Monitoring Frequency: CO emission shall be analyzed semi-annually unless the stack testing
is performed at the same time or the engine is not running.

(D) Data Collection Procedure: Records of calibration and testing shall be maintained in the
facilities computerized MP2. Also, a strip chart of the result shall be kept in the engines' paper
files

(E) Averaging Period: CO emission shall be calculated per the testing protocol developed in
accordance with II.B.4.a.1(B)(i)(3)(B).

(iii) Oxygen Concentration

(1) Measurement Approach: Oxygen concentration shall be measured through daily alarm light
monitoring to assure proper operation of the Air to Fuel Ration (AFR) controller. Alarm light
shall be triggered by a minivolt reading indicating when AFR is to rich or too lean. This occurs
when there is an excursion from the ideal oxygen concentration range.

(2) Indicator Range: Indicator range shall be based on Testo analyzer monitoring which follows
the sensor replacement. If the percent of oxygen deviates from this range, the AFR alarm light
will come on. Excursions shall trigger an inspection and review of the catalyst’s performance as
indicated by other parameters (to confirm if the oxygen reading is valid and to determine the
catalyst operating deficiencies). If the excursion is the result of a deficiency with the catalyst, then
corrective actions and reporting are required.

(3) Performance Criteria:

(A) Data Representativeness: The oxygen concentration shall be measured at the engine exhaust
while the engine is operating.

(B) QA/QC Practices and Criteria: Oxygen sensors shall be replaced, at a minimum, annually, or
more frequently as needed. Sensors shall be analyzed using a Testo portable analyzer following
replacement.

(C) Monitoring Frequency: The alarm light shall be monitored daily to ensure that oxygen
concentration is within the required range.

(D) Data Collection Procedure: Records shall be maintained to document alarmed events, sensor
replacement, indicator range, and required maintenance.

(E) Averaging Period: Not applicable.

29
II.B.4.a.2 Recordkeeping:

In addition to the recordkeeping requirement described in Provision I.S.1 of this permit,

(a) The permittee shall maintain a file of all stack testing and all other information required by
permit provision I.S.1.

(b) The permittee shall maintain a file of continuous monitor measurements, including
performance testing measurements, all performance evaluations, all calibration checks, all
adjustments, and maintenance.

(c) The permittee shall maintain a file of the occurrence and duration of any excursion, corrective
actions taken, and any other supporting information required to be maintained under 40 CFR 64
(such as data used to document the adequacy of monitoring, or records of monitoring
maintenance or corrective actions). Instead of paper records, the permittee may maintain records
on alternative media, such as microfilm, computer files, magnetic tape disks, or microfiche,
provided that the use of such alternative media allows for expeditious inspection and review, and
does not conflict with other applicable recordkeeping requirements. (40 CFR 64.9(b)).

II.B.4.a.3 Reporting:

In addition to the reporting requirement described in Provision I.S.2 of this permit,

(a) The monitoring report required in Provision I.S.2 of this permit shall include, at a minimum,
the following information, as applicable:

(1) Summary information on the number, duration and cause (including unknown cause, if
applicable) of excursions or exceedances, as applicable, and the corrective actions taken;(40 CFR
64.9(a)(2)(i))

(2) Summary information on the number, duration and cause (including unknown cause, if
applicable) for monitor downtime incidents (other than downtime associated with zero and span
or other daily calibration checks, if applicable). (40 CFR 64.9(a)(2)(ii))

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

30
Status:

Not in compliance. E4B stack test.

Unit E4A (company ID C8) was last tested on March 31, 2020. Results were 1.47 lbs/hr, 210 ppmdv
CO and 1.25 lbs/hr (see DAQC-653-20). The last portable test was done August 31, 2024, with CO
results of 180 ppm. Stack testing was not done in 2024 on any sources. This was confirmed by
on-site contact. This unit was taken offline in October 2024. Next stack test is due March 2025.

Unit E4B (company ID C9) was tested May 1, 2019 (see DAQC-264-20). Results were 1.98 lbs/hr,
281 ppmdv for CO and 2.03 lbs.hr . The last portable test was August 31, 2024, with CO results of
437 ppm. This unit stack test was due May 2024. Stack testing was not done in 2024 on any sources.
This was confirmed by on-site contact.

For CAM: Temperatures were monitored continuously until December 5, 2024, when the site was
shut down.

II.B.4.b Condition:

Visible emissions shall be no greater than 10 percent opacity [Origin: DAQE-AN0100340024-16].
[R307-401-8]

II.B.4.b.1 Monitoring:

In lieu of opacity monitoring, the report required for this permit condition will serve as
monitoring.

II.B.4.b.2 Recordkeeping:

The report required for this permit condition will serve as recordkeeping

II.B.4.b.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee should
certify each annual certification report that only pipeline quality natural gas is used as fuel during
the reporting year.

Status: In compliance. Only pipeline quality natural gas is used. As of December 5, 2024, the site is using
sweet gas at 40 psi to maintain lines with no production occurring.

II.B.4.c Condition:

Emissions of NOx shall be no greater than 3.26 lbs/hr and 392 ppmdv from each engine.
[Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.4.c.1 Monitoring:

(A) Initial compliance testing shall be performed as soon as possible and in no case later 180 days
after the startup of the new engines. After the initial testing, stack testing shall be conducted at
least once every 5 years when the affected unit is operating. A pretest conference shall be held at
least 30 days prior to the stack test if directed by the Director and shall include the permittee, the
tester, and the Director.

31
The following stack testing requirements shall be met:

(1) The emission sample point shall conform to the requirements of 40 CFR 60, Appendix A,
Method 1. In addition, Occupational Safety and Health Administration (OSHA) or Mine Safety
and Health Administration (MSHA) approved access shall be provided to the test location.

(2) Volumetric flow rate shall be determined using 40 CFR 60, Appendix A, Method 2.

(3) NOx concentrations shall be determined using 40 CFR 60, Appendix A, Method 7e.

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

(5) The operating load during testing shall be at least 90% of the maximum production achieved
in the previous 3 year's operation.

(B) The temperature of exhaust gas into the catalyst, NOx emission measured by a portable
analyzer, and oxygen concentration at the engine exhaust shall be used as indicators to provide a
reasonable assurance of compliance with the NOx emission limitation as specified below:

(i) Temperature

(1) Measurement Approach: Exhaust gas temperature shall be monitored continuously using an
in-line thermocouple.

(2) Indicator Range: Temperature at the inlet of the catalyst shall be maintained between 750oF
and 1250oF. Excursions from this temperature range shall trigger an inspection and review of the
catalyst’s performance as indicated by other parameters (to confirm if the temperature reading is
valid and to determine the catalyst operating deficiencies). If the excursion is the result of a
deficiency with the catalyst, then corrective actions and reporting are required.

(3) Performance Criteria:

(A) Data Representativeness: Temperature measurements made by a thermocouple sensor shall
provide a direct indicator of catalyst performance. A sensor shall be located at the inlet of the
catalyst. The minimum accuracy of the thermocouple is +/- 2%.

(B) QA/QC Practices and Criteria: Thermocouple shall be maintained per manufacturer's
specifications. It shall be tested semi-annually to ensure its accuracy.

(C) Monitoring Frequency: Temperature shall be monitored continuously when the engine is
operating.

(D) Data Collection Procedure: Temperature data shall be collected once per hour and recorded
on a log sheet when the engine is operating.

(E) Averaging Period: The temperature shall be recorded and reduced to 4-hour rolling averages
when the engine is operating.

32
(ii) Portable Analyzer Test

(1) Measurement Approach: NOx emission shall be measured using a portable hand-held Testo
analyzer during normal operating conditions.

(2) Indicator Range: Excursion from the NOx limit is defined as an emission rate of NOx at or
above 3.26 lbs/hr or 392 ppmdv. Excursions from this limit shall trigger an inspection and review
of the catalyst’s performance as indicated by other parameters (to confirm if the result is valid and
to determine the catalyst operating deficiencies). If the excursion is the result of a deficiency with
the catalyst, then corrective actions and reporting are required. (3) Performance Criteria: (A) Data Representativeness: NOx emission shall be measured at the outlet of the catalyst. (B) QA/QC Practices and Criteria: Testo analyzer shall be calibrated annually. A testing protocol for performing a portable analyzer test shall be developed, documented, and used for all tests. (C) Monitoring Frequency: NOx emission shall be analyzed semi-annually unless the stack testing is performed at the same time or the engine is not running. (D) Data Collection Procedure: Records of calibration and testing shall be maintained in the facilities computerized MP2. Also a strip chart of the result shall be kept in the engines' paper files (E) Averaging Period: NOx emission shall be calculated per the testing protocol developed in accordance with II.B.4.c.1.(B)(ii)(3)(B). (iii) Oxygen Concentration (1) Measurement Approach: Oxygen concentration shall be measured through daily alarm light monitoring to assure proper operation of the Air to Fuel Ration (AFR) controller. Alarm light shall be triggered by a minivolt reading indicating when AFR is to rich or too lean. This occurs when there is an excursion from the ideal oxygen concentration range. (2) Indicator Range: Indicator range shall be based on Testo analyzer monitoring which follows the sensor replacement. If the percent of oxygen deviates from this range, the AFR alarm light will come on. Excursions trigger an inspection and review of the catalyst performance as indicated by other parameters (to confirm if the oxygen reading is valid and to determine the catalyst operating deficiencies). If the excursion is the result of a deficiency with the catalyst, then corrective actions and reporting are required. (3) Performance Criteria: (A) Data Representativeness: The oxygen concentration shall be measured at the engine exhaust while the engine is operating. (B) QA/QC Practices and Criteria: Oxygen sensors shall be replaced, at a minimum, annually, or more frequently as needed. Sensors shall be analyzed using a Testo portable analyzer following replacement.
(C) Monitoring Frequency: The alarm light shall be monitored daily to ensure that oxygen
concentration is within the required range.

33
(D) Data Collection Procedure: Records shall be maintained to document alarmed events, sensor
replacement, indicator range, and required maintenance.

(E) Averaging Period: Not applicable.

II.B.4.c.2 Recordkeeping:

In addition to the recordkeeping requirement described in Provision I.S.1 of this permit,

(a) The permittee shall maintain a file of all stack testing and all other information required by
permit provision I.S.1.

(b) The permittee shall maintain a file of continuous monitor measurements, including
performance testing measurements, all performance evaluations, all calibration checks, all
adjustments, and maintenance.

(c) The permittee shall maintain a file of the occurrence and duration of any excursion, corrective
actions taken, and any other supporting information required to be maintained under 40 CFR 64
(such as data used to document the adequacy of monitoring, or records of monitoring
maintenance or corrective actions). Instead of paper records, the permittee may maintain records
on alternative media, such as microfilm, computer files, magnetic tape disks, or microfiche,
provided that the use of such alternative media allows for expeditious inspection and review, and
does not conflict with other applicable recordkeeping requirements. (40 CFR 64.9(b)).

II.B.4.c.3 Reporting:

In addition to the reporting requirement described in Provision I.S.2 of this permit,

(a) The monitoring report required in Provision I.S.2 of this permit shall include, at a minimum,
the following information, as applicable:

(1) Summary information on the number, duration and cause (including unknown cause, if
applicable) of excursions or exceedances, as applicable, and the corrective actions taken;(40 CFR
64.9(a)(2)(i))

(2) Summary information on the number, duration and cause (including unknown cause, if
applicable) for monitor downtime incidents (other than downtime associated with zero and span
or other daily calibration checks, if applicable). (40 CFR 64.9(a)(2)(ii))

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

Status:

Not in compliance. E4B stack test overdue.

Unit E4A (company ID C8) was last tested on March 31, 2020. Result was 109 ppmdv NOx (see
DAQC-653-20). Last portable was done August 31, 2024, with 56.3 ppm NOx. Stack testing was not
done in 2024 on any sources. This was confirmed by on-site contact. Next Stack test due May 2025.

34
Unit E4B (company ID C9) was tested May 1, 2019 (see DAQC-264-20). Result was 175 ppmdv for
NOx. The last portable test was August 31, 2024, with NOx results of 50.4 ppm. Stack test was due
May 2024. Stack testing was not done in 2024 on any sources. This was confirmed by on-site
contact.

For CAM: Temperatures were monitored continuously, until December 5, 2024, when the site was
shut down.

II.B.5 Conditions on NESHP ZZZZ non-emergency remote engine group

II.B.5.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. [Origin: 40 CFR 63.6595(a), 40 CFR 63.6605(b)].
[40 CFR 63 Subpart ZZZZ]

II.B.5.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.5.a.2 Recordkeeping:

The permittee shall keep 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.5.a.3 Reporting:

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.

Status: In compliance. A maintenance program (MP2) tracks all required maintenance related to
compliance with this condition.

35
II.B.5.b Condition:

(1) 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.

(2) The affected unit must meet the definition of remote stationary RICE in 40 CFR63.6675 on the initial
compliance date for the engine, October 19, 2013, in order to be considered a remote stationary RICE in
NESHP ZZZZ. The permittee shall evaluate the status of their RICE every 12 months. If the evaluation
indicates that the affected unit no longer meets the definition of remote stationary RICE in 40 CF63.6675,
the permit must comply with all of the requirements for existing non-emergency SI 4SRB stationary
RICE with a site rating of more than 500 HP located at area sources of HAP that are not remote stationary
RICE within 1 year of the evaluation.

(3) The permittee shall meet the following requirements at all times, except during periods of startup:
(a) Change oil and filter every 2,160 hours of operation or annually, whichever comes first.
(b) Inspect spark plugs every 2,160 hours of operation or annually, whichever comes first;
(c) Inspect all hoses and belts every 2,160 hours of operation or annually, whichever comes first, and
replace as necessary.

(4) 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(j) in order to extend the specified oil change
requirement in paragraph (3)(a) of this condition.

(5) During periods of startup the permittee must 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 limitation applies.

[Origin: 40 CFR 63.6595(a)(1), 40 CFR 63.6665, 40 CFR 63.6603(a), 40 CFR 63.6605(a), 40 CFR
63.6625(h), 40 CFR 63 Subpart ZZZZ Tables 2d (11), and 8]. [40 CFR 63 Subpart ZZZZ]

II.B.5.b.1 Monitoring:
(a) 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]
(b) The permittee shall operate and maintain 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.

(c) 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(j). [40 CFR 63.6625(e), 40
CFR 63.6640(a), 40 CFR 63 Subpart ZZZZ Table 6(9)]. [40 CFR 63 Subpart ZZZZ]

II.B.5.b.2 Recordkeeping:
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] (a) The permittee shall keep records of the initial and annual evaluation of the remote status of the engine.
36
(b) The permittee shall keep records of the initial and annual evaluation of the remote status of the engine.

(c) 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]

(d) 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)]

(e) Records shall be maintained in accordance with 40 CFR 63.6660 and Provision I.S.1 of this
permit.

II.B.5.b.3 Reporting:

The permittee shall comply with the applicable general provisions in 40 CFR 63.1-15 as
identified in 40 CFR 63, Subpart ZZZZ [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 report any failure to perform the management 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 2d Footnote 2]

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

Status:

In compliance. The remote status determination was completed on May 21, 2024, using Google
earth maps. A maintenance program (MP2) tracks all required maintenance related to compliance
with this condition. All required maintenance items are listed on work order. There are no
semi-annual reporting requirements under Subpart ZZZZ for remote engines

II.B.6 Conditions on Boilers (E13 & E14).

II.B.6.a Condition:

Emissions of CO shall be no greater than 2.53 lbs/hr and 78.0 ppm from each boiler [Origin: DAQE-
AN0100340024-16]. [R307-401-8]

II.B.6.a.1 Monitoring:

A. CO emissions testing shall be performed on each affected unit once every two years using a
portable analyzer or testing instrument capable of detecting emissions of the pollutant being
tested at the concentrations necessary to determine compliance. The tested unit shall be operated
under normal conditions and at a minimum of 90% of the maximum production or throughput
achieved since the last required test. A testing protocol shall be developed, documented, and used
for all tests. At a minimum, the following topics shall be addressed in the protocol:

(1) A description of sampling locations and sample gathering procedures that result in
representative and reproducible samples.

37
(2) Calibration and operation procedures for the analyzer.

(3) Methods used to determine the flow rate, temperature, and other parameters as necessary to
demonstrate compliance.

(4) Calculations and other information necessary to convert the analyzer output to the units of the
limitation.

The test protocol shall be made available to the Director upon request. If the Director determines
that the protocol does not adequately address the minimum requirements list above, or that the
protocol does not provide sufficient assurance that the test results are adequate for demonstrating
compliance with the limitation, the Director may require the permittee to modify the protocol.

B. Stack testing to demonstrate compliance with CO limits shall be conducted at least once every
5 years. A pretest conference shall be held at least 30 days prior to the stack test if directed by the
Director and shall include the permittee, the tester, and the Director.

The following stack testing requirements shall be met:

(1) The emission sample point shall conform to the requirements of 40 CFR 60, Appendix A,
Method 1. In addition, Occupational Safety and Health Administration (OSHA) or Mine Safety
and Health Administration (MSHA) approved access shall be provided to the test location.

(2) Volumetric flow rate shall be determined using 40 CFR 60, Appendix A, Method 2.

(3) CO concentrations shall be determined using 40 CFR 60, Appendix A, Method 10.

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

(5) The operating load during testing shall be at least 90% of the maximum production achieved
in the previous 3 year's operation.

II.B.6.a.2 Recordkeeping:

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

38
II.B.6.a.3 Reporting:

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

Status:

Not in compliance. E14 stack test overdue.

For portable testing: Unit E14 was last tested on February 1, 2023, with CO results of 4.65 ppm.
Unit E13 has been offline since 2021. Next portable test is due February 2025.

For stack testing: Units E13 and E14 were last tested on October 17 and 18, 2019 (see
DAQC-071-20). The results were:

The next test was due in November 2024. Stack testing was not done in 2024 on any sources. This
was confirmed by on-site contact.

II.B.6.b Condition:

Visible emissions shall be no greater than 5 percent opacity from each boiler [Origin: DAQE-
AN0100340024-16]. [R307-401-8]

II.B.6.b.1 Monitoring:

In lieu of opacity monitoring, the report required for this permit condition will serve as
monitoring.

II.B.6.b.2 Recordkeeping:

The report required for this permit condition will serve as recordkeeping

39
II.B.6.b.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee shall
certify each annual certification report that only pipeline quality natural gas is used as fuel during
the reporting year.

Status: In compliance. Only pipeline quality natural gas is used. As of December 5, 2024, the site is using
sweet gas at 40 psi to maintain lines with no production occurring.

II.B.6.c Condition:

The permittee shall keep daily records of the amounts of each fuel combusted each day [Origin: 40 CFR
60 Subpart Dc]. [40 CFR 60.48c(g)]

II.B.6.c.1 Monitoring:

Fuel consumption for each affected emission unit shall be determined by a fuel meter, vendor
supplied information, or other method approved by the Director.

II.B.6.c.2 Recordkeeping:

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

II.B.6.c.3 Reporting:

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

Status: In compliance. Fuel meters are used to confirm compliance. As of December 5, 2024, the site is
using sweet gas at 40 psi to maintain lines with no production occurring.

II.B.6.d Condition:

Emissions of NOx shall be no greater than 3.35 lbs/hr and 63.0 ppm from each boiler [Origin: DAQE-
AN0100340024-16]. [R307-401-8]

II.B.6.d.1 Monitoring:

A. NOx emissions testing shall be performed on each affected unit once every two years when the
affected unit is operating, using a portable analyzer or testing instrument capable of detecting
emissions of the pollutant being tested at the concentrations necessary to determine compliance.
The tested unit shall be operated under normal conditions and at a minimum of 90% of the
maximum production or throughput achieved since the last required test. A testing protocol shall
be developed, documented, and used for all tests. At a minimum, the following topics shall be
addressed in the protocol:

(1) A description of sampling locations and sample gathering procedures that result in
representative and reproducible samples.

(2) Calibration and operation procedures for the analyzer.

40
(3) Methods used to determine the flow rate, temperature, and other parameters as necessary to
demonstrate compliance.

(4) Calculations and other information necessary to convert the analyzer output to the units of the
limitation.

The test protocol shall be made available to the Director upon request. If the Director determines
that the protocol does not adequately address the minimum requirements list above, or that the
protocol does not provide sufficient assurance that the test results are adequate for demonstrating
compliance with the limitation, the Director may require the permittee to modify the protocol.
B. Stack testing to demonstrate compliance with NOx limits shall be conducted at least once
every 5 years when the affected unit is operating. A pretest conference shall be held at least 30
days prior to the stack test if directed by the Director and shall include the permittee, the tester,
and the Director.

The following stack testing requirements shall be met:

(1) The emission sample point shall conform to the requirements of 40 CFR 60, Appendix A,
Method 1. In addition, Occupational Safety and Health Administration (OSHA) or Mine Safety
and Health Administration (MSHA) approved access shall be provided to the test location.

(2) Volumetric flow rate shall be determined using 40 CFR 60, Appendix A, Method 2.

(3) NOx concentrations shall be determined using 40 CFR 60, Appendix A, Method 7e.

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

(5) The operating load during testing shall be at least 90% of the maximum production achieved
in the previous 3 year's operation.

II.B.6.d.2 Recordkeeping:

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

41
II.B.6.d.3 Reporting:

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

Status:

Not in compliance. E14 stack test overdue.

For portable testing: Unit E14 was last tested on February 1, 2023, with NOx results of 34.6 ppm.
Unit E13 has been offline since 2021. Next portable test is due February 2025.

For stack testing: Units E13 and E14 were last tested on October 17 and 18, 2019 (see
DAQC-071-20). The results were:

The next test was due in 2024. Stack testing was not done in 2024 on any sources. This was
confirmed by on-site contact. Both units are scheduled to be replaced (Replacement-In-Kind
(RIK)).

II.B.7 Conditions on TEG dehydrator (E21)

II.B.7.a Condition:

The permittee shall operate the TEG dehydration unit such that the actual glycol circulation rate does not
exceed the optimum glycol circulation rate of 306 gallons/hr. If operation conditions change, the
permittee shall determine a new optimum glycol circulation rate in accordance with 40 CFR 63.764(d)(2).
[Origin: 40 CFR 63.764(d)(2)(ii)]. [40 CFR 63 Subpart HH]

II.B.7.a.1 Monitoring:

The permittee shall install and operate a continuous monitoring system to monitor glycol
circulation rate. The monitoring system shall be installed, calibrated, operated, and maintained in
accordance with the manufacturer's specifications or other written procedures that provide
reasonable assurance that the monitoring equipment is operating properly.

42
II.B.7.a.2 Recordkeeping:

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

(b) The permittee shall keep a record of the calculation used to determine the optimum glycol
circulation rate in accordance with 40 CFR 63.764(d)(2)(i).

II.B.7.a.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee shall
prepare a new determination and submit the information specified in accordance with 40
CFR63.775(c)(7)(ii) through (v) if operating conditions change and a modification to the
optimum glycol circulation rate is required.

Status: In compliance. A continuous monitor system is installed to measure the glycol circulation rate. The
set point is 4.2 gallons/minute or 252 gallons/hour.

II.B.7.b 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. [Origin: 40 CFR 63.764(j). [40 CFR 63 Subpart HH]

II.B.7.b.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.7.b.2 Recordkeeping:

The permittee shall keep the records described in 40 CFR 63.774(b)(1) and (2) as applicable. 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.7.b.3 Reporting:

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

Status: In compliance. The unit is monitored in the control system with alarm limits set. This unit is
tracked on the maintenance system for routine maintenance.

43
II.B.8 Conditions on Gas Sweetening Process Unit.

II.B.8.a Condition:

All acid gas from the sweetening unit shall be routed to either the sulfur recovery plant or the sulfur
enrichment and injection unit [Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.8.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.8.a.2 Recordkeeping:

The destination of exhaust from the sweetening unit shall be logged on daily basis. Records shall
be maintained in accordance with Provision I.S.1 of this permit.

II.B.8.a.3 Reporting:

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

Status: In compliance. The gas sweetening process unit is operational. Exit gases are routed to the SEI unit
when there is enough volume and routed to injection wells if volume is low. Records are maintained
to confirm compliance. The SRU is no longer in use.

II.B.8.b Condition:

The sulfur dioxide reduction efficiency shall be 74% or greater [Origin: 40 CFR 60.642(b)].
[40 CFR 60 Subpart LLL]

II.B.8.b.1 Monitoring:

(A) The sulfur reduction efficiency achieved shall be calculated for each 24-hour period as
specified in either (1) or (2) of this section:

(1) When the sulfur recovery unit is operating, the sulfur reduction shall be calculated in
accordance with procedures and requirements of 40 CFR 60.646(d).

R= (100 S)/(S+E) (40 CFR 60.644 c(1))

(2) When the sulfur enrichment and inject unit is operating the sulfur reduction efficiency shall be
calculated by the equation as:

R=100(X-E)/X

Or the permittee may submit the alternative method to calculate the sulfur reduction efficiency for
approval.

44
Where:
R= the sulfur dioxide reduction efficiency achieved during the 24-hour period, in percent;
S= the sulfur production rate from the sulfur recovery plant during the 24-hour period, kg/hr; and
E= the sulfur emission rate from the incinerator expressed as elemental sulfur, kg/hr (equal to
50% of the SO2 emission rate (kg/hr) determined from the CEMs in the incinerator)
X= the average sulfur production rate (kg/hr) from the gas sweetening process expressed as
elemental sulfur during 24-hour period.

(B) The permittee shall calibrate, maintain, and operate monitoring devices to collect the
following operational information on a daily basis when the affected unit is operating:
(1) Amount of sulfur product determined in accordance with 40 CFR 60.646 a(1)(only when
sulfur recovery unit is operating) ;
(2) H2S concentration in acid gas from sweetening unit determined in accordance with 40 CFR
60.646 a(2);
(3) Average acid gas flow rate from sweetening unit determined in accordance with 40 CFR
60.646 a(3);
(4) Sulfur feed rate determined in accordance with 40 CFR 60.646 a(4);
(5) Required sulfur dioxide emission reduction efficiency for each 24-hour period, determined in
accordance with 40 CFR 60.646(a)(5).

II.B.8.b.2 Recordkeeping:

Results of monitoring shall be recorded and maintained as required in 40 CFR 60.647(a) and as
described in Provision I.S.1 of this permit.

II.B.8.b.3 Reporting:

In addition to reporting provisions contained in Section I of this permit, the permittee shall submit
a written report of excess emissions to the Director semiannually. For the purpose of these
reports, excess emissions are defined as in 40 CFR 60.647(b)(1).

Status:

Not applicable. Sulfur reduction occurs in the SRU. The SRU is no longer in use.
II.B.9 Conditions on Sulfur Recovery Unit.

II.B.9.a Condition:

All acid gas from the sulfur recovery area shall be routed through the incinerator before being vented to
the atmosphere, except during emergency or unavoidable breakdown, when the acid gas shall be routed to
the upset flare. [Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.9.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.9.a.2 Recordkeeping:

The destination of exhaust from the sulfur recovery area shall be logged during emergency or
unavoidable breakdown. Records shall be maintained in accordance with Provision I.S.1 of this
permit.

45
II.B.9.a.3 Reporting:

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

Status: Not applicable. The SRU is no longer in use.

II.B.10 Conditions on Sulfur Enrichment and Injection Unit (SEI).

II.B.10.a Condition:

The residual CO2-rich gas stream from the SEI unit shall be routed to the tail gas incinerator for control of
H2S emissions before being vented to the atmosphere, except during emergency or unavoidable
breakdown, when the acid gas shall be routed to the upset flare. Acid gas routed to the injection well may
be routed to the upset flare during emergency or unavoidable breakdowns and during semi-annual
maintenance of the injection system. [Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.10.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.10.a.2 Recordkeeping:

The destination of exhaust from SEI unit shall be logged during emergency or unavoidable
breakdown. Records shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.10.a.3 Reporting:

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

Status: Not evaluated. H2S from the gas sweetening unit is controlled by the SEI. The SEI uses
FLEXSORB amine solvent to separate H2S from the acid gas along with CO2. This gas is
compressed and routed to off-site injection wells. Any residue acid gas is routed to the incinerator
(E15). The SEI has not operated since 2016 due to low volume.

II.B.11 Conditions on Incinerator (E15).

II.B.11.a Condition:

Emissions of NOx shall be no greater than 7.56 lbs/hr and 184.96 ppm from the incinerator [Origin:
DAQE-AN0100340024-16]. [R307-401-8]

II.B.11.a.1 Monitoring:

A. NOx emissions testing shall be performed on each affected unit once every two years when the affected unit is operating, using a portable analyzer or testing instrument capable of detecting emissions of the pollutant being tested at the concentrations necessary to determine compliance. The tested unit shall be operated under normal conditions and at a minimum of 90% of the maximum production or throughput achieved since the last required test. A testing protocol shall be developed, documented, and used for all tests. At a minimum, the following topics shall be addressed in the protocol:
46
(1) A description of sampling locations and sample gathering procedures that result in representative and reproducible samples.

(2) Calibration and operation procedures for the analyzer.
(3) Methods used to determine the flow rate, temperature, and other parameters as necessary to
demonstrate compliance.
(4) Calculations and other information necessary to convert the analyzer output to the units of the
limitation.
The test protocol shall be made available to the Director upon request. If the Director determines
that the protocol does not adequately address the minimum requirements list above, or that the protocol does not provide sufficient assurance that the test results are adequate for demonstrating
compliance with the limitation, the Director may require the permittee to modify the protocol.

B. Stack testing to demonstrate compliance with NOx limits shall be conducted at least once
every 5 years when the affected unit is operating. A pretest conference shall be held at least 30
days prior to the stack test if directed by the Director and shall include the permittee, the tester,
and the Director.

The following stack testing requirements shall be met:

(1) The emission sample point shall conform to the requirements of 40 CFR 60, Appendix A,
Method 1. In addition, Occupational Safety and Health Administration (OSHA) or Mine Safety
and Health Administration (MSHA) approved access shall be provided to the test location.

(2) Volumetric flow rate shall be determined using 40 CFR 60, Appendix A, Method 2.

(3) NOx concentrations shall be determined using 40 CFR 60, Appendix A, Method 7e.

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

(5) The operating load during testing shall be at least 90% of the maximum production achieved
in the previous 3 year's operation.

II.B.11.a.2 Recordkeeping:

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

II.B.11.a.3 Reporting:

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

Status:

Not evaluated. The incinerator is offline. Testing was completed on May 6, 2015, with NOx results
of 1.22 lb/hr (see DAQC-963-15). The stack test was not completed within the following five-year
cycle because the plant shut down on October 31, 2016.

47
II.B.11.b Condition:

Emissions of SOx shall be no greater than 600.00 lbs/hr (3-hour rolling average) and 14679.4 ppm, and no
greater than 1,593 tons per calendar year from the incinerator [Origin: DAQE-AN0100340024-16].
[R307-401-8]

II.B.11.b.1 Monitoring:

The permittee shall calibrate, maintain and operate a continuous monitoring system on the
incinerator stack as per 40 CFR 60.646(b)(1) for measuring the emissions of sulfur dioxide (SO2)
concentration when the affected unit is operating. The monitoring system shall comply with all
applicable sections of UAC R307-170, 40 CFR 60.13, and 40 CFR 60, Appendix B, Specification
2 - SO2. Hourly emissions and 3-hour rolling average emissions shall be calculated on an hourly
basis. Within the first 20 days of every year, SO2 emissions total shall be calculated for previous
calendar year.

II.B.11.b.2 Recordkeeping:

Results of SO2 monitoring shall be recorded and maintained as required in R307-170, 40 CFR
60.647(a), and as described in Provision I.S.1 of this permit.

II.B.11.b.3 Reporting:

The permittee shall comply with the reporting provisions in R307-170-9, 40 CFR 60.647(b), and
any additional reporting provisions contained in Section I of this permit.

Status:

Not evaluated. The incinerator has been offline since 2016. No reports have been submitted for the
incinerator in past two-year period.

II.B.11.c Condition:

The permittee shall measure the temperature within the secondary chamber of the incinerator and operate
the chamber, according to procedures and requirements provided in NSPS Subpart LLL. [Origin: DAQE-
AN0100340024-16]. [40 CFR 60.646(b)(2)]

II.B.11.c.1 Monitoring:

Permittee shall calibrate, maintain, and operate a monitoring device for the continuous
measurement of the temperature within the secondary chamber of the incinerator when the
affected unit is operating, according to procedures and requirement provided in 40 CFR Part
60.646 (b)(2)

II.B.11.c.2 Recordkeeping:

Results of monitoring shall be recorded and maintained as required in 40 CFR 60.647(a) and as
described in Provision I.S.1 of this permit.

48
II.B.11.c.3 Reporting:

In addition to reporting provisions contained in Section I of this permit, the permittee shall submit
a written report of excess emissions to the Director semiannually. For the purpose of these
reports, excess emissions are defined as in 40 CFR 60.647(b)(2).

Status:

Not evaluated. The incinerator has been offline since 2016. No reports have been submitted for the
incinerator in past two-year period.

II.B.12 Conditions on Upset Flare (E16).

II.B.12.a Condition:

The flare shall be designed and operated in accordance with 40 CFR 60.18 (c) through (f). The flare shall
be operated with no visible emissions, except for periods not to exceed a total of 5 minutes during any 2
consecutive hours [Origin: DAQE-AN0100340024-16]. [40 CFR 60.18, 40 CFR 60.633(g)]

II.B.12.a.1 Monitoring:

A visual determination of each affected emission unit shall be conducted on a monthly basis using
40 CFR 60, Appendix A, Method 22.

II.B.12.a.2 Recordkeeping:

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

II.B.12.a.3 Reporting:

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

Status: In compliance. The flare was on standby during the inspection. Monthly visible emissions
observations are completed by on-site staff. Records are maintained that confirm compliance.
Records show no exceedances. As of December 5, 2024, the site is using sweet gas at 40 psi to
maintain lines with no production occurring. The site uses by back gas from Northwest pipeline
(about 14 MSCF/day) to keep flare pilot lite.

II.B.12.b Condition:

Hours of operation for maintenance shall not exceed 200 hours per rolling 12-month period unless
otherwise specified. [Origin: DAQE-AN0100340024-16]. [R307-401-8

II.B.12.b.1 Monitoring:

Within 20 days of the end of each month, and as of the last day of the previous month, a new 12-
month total of hours operated shall be calculated using the previous 12 months data.

49
II.B.12.b.2 Recordkeeping:

Hours of operation for maintenance shall be recorded on a monthly basis in an operation and
maintenance log. Results of monitoring shall be maintained as described in Provision I.S.1 of this
permit.

II.B.12.b.3 Reporting:

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

Status: In compliance. The 12-month rolling total for the period ending December 31, 2024, was 0.7 hours.

II.B.13 Conditions on 40 CFR Part 60, Subpart KKK Applicable Equipment (E25)

II.B.13.a Condition:

I. Standards for pumps in light liquid service.

For each pump in light liquid service, the permittee shall comply with the requirements as provided in the
paragraphs (a) through (g) of this section or demonstrate that the pump is neither in VOC service nor in
wet gas service.

(a) (1) If an instrument reading of 10,000 ppm or greater is measured, a leak is detected.
(2) If there are indications of liquids dripping from the pump seal, a leak is detected.

(b) (1) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar
days after it is detected, except as provided in Standard VII (Delay of Repair) of this permit condition.
(2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.

(c) Each pump equipped with a dual mechanical seal system that includes a barrier fluid system is exempt
from the monitoring requirements of Monitoring Provision II(a) of this permit condition, Provided the
following requirements are met:
(1) Each dual mechanical seal system is-
(i) Operated with the barrier fluid at a pressure that is at all times greater than the pump stuffing box
pressure; or
(ii) Equipped with a barrier fluid degassing reservoir that is routed to a process or fuel gas system or
connected by a closed vent system to a control device that complies with the requirements of Standard
VIII of this permit condition; or
(iii) Equipped with a system that purges the barrier fluid into a process stream with zero VOC emissions
to the atmosphere.
(2) The barrier fluid system is in heavy liquid service or is not in VOC service.
(3) Each barrier fluid system is equipped with a sensor that will detect failure of the seal system, the
barrier fluid system, or both.
(4) Each pump is checked by visual inspection, each calendar week, for indications of liquids dripping
from the pump seals.
(5) (i) Each sensor as described in paragraph (c)(3) of this section is checked daily or is equipped with an
audible alarm, and
(ii) The permittee determines, based on design considerations and operating experience, a criterion that
indicates failure of the seal system, the barrier fluid system, or both.
(6) (i) If there are indications of liquids dripping from the pump seal or the sensor indicates failure of the
50
seal system, the barrier fluid system, or both based on the criterion determined in paragraph (c)(5)(ii) of
this section, a leak is detected.
(ii) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar days
after it is detected, except as provided in Standard VII (Delay of Repair) of this permit condition.
(iii) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.

(d) Any pump that is designated, as described in Recordkeeping Provision I(e)(1) and I(e)(2) of this
permit condition, for no detectable emission, as indicated by an instrument reading of less than 500 ppm
above background, is exempt from the requirements of Monitoring Provision II(a) of this permit
condition, paragraphs (b), and (c) of the this section if the pump:
(1) Has no externally actuated shaft penetrating the pump housing,
(2) Is demonstrated to be operating with no detectable emissions as indicated by an instrument reading of
less than 500 ppm above background as measured by the methods specified Monitoring Provision I(c) of
this permit condition, and
(3) Is tested for compliance with paragraph (d)(2) of this section initially upon designation, annually, and
at other times requested by the Director.

(e) If any pump is equipped with a closed vent system capable of capturing and transporting any leakage
from the seal or seals to a process or to a fuel gas system or to a control device that complies with the
requirements of Standard VIII of this permit condition, it is exempt from Monitoring Provision II(a) of
this permit condition, and paragraphs (a) through (d) of this section.

(f) Any pump that is designated, as described in Recordkeeping Provision (f)(1) of this permit condition,
as an unsafe-to-monitor pump is exempt from the monitoring and inspection requirements of Monitoring
Provision II(a) of this permit condition, and paragraphs (c)(4) through (c)(6) of this section if:
(1) The permittee of the pump demonstrates that the pump is unsafe-to-monitor because monitoring
personnel would be exposed to an immediate danger as a consequence of complying Monitoring
Provision II(a) of this permit condition; and
(2) The permittee of the pump has a written plan that requires monitoring of the pump as frequently as
practicable during safe-to-monitor times but not more frequently than the periodic monitoring schedule
otherwise applicable, and repair of the equipment according to the procedures in paragraph (b) of this
section if a leak is detected.

(g) Any pump that is located within the boundary of an unmanned plant site is exempt from the weekly
visual inspection requirement of Monitoring Provision II(a)(2) of this permit condition, and paragraph
(c)(4) of this section, and the daily requirements of paragraph (c)(5) of this section, provided that each
pump is visually inspected as often as practicable and at least monthly.
(40 CFR 60.482-2(b) through (h))

II. Standards for compressor

For each compressor, the permittee shall comply with the requirement as provided in paragraphs (a)
through (j) of this section or demonstrate that the compressor is neither in VOC service nor in wet gas
service or is a reciprocating compressor in wet gas service (40 CFR 60.633(f)).
(a) Each compressor shall be equipped with a seal system that includes a barrier fluid system and that
prevents leakage of VOC to the atmosphere, except as provided in 40 CFR 60.634 and paragraphs (h) and
(i) of this section.

(b) Each compressor seal system as required in paragraph (a) of this section shall be:
(1) Operated with the barrier fluid at a pressure that is greater than the compressor stuffing box pressure;
or
51
(2) Equipped with a barrier fluid system degassing reservoir that is routed to a process or fuel gas system
or connected by a closed vent system to a control device that complies with the requirements of Standard
VIII of this permit condition; or
(3) Equipped with a system that purges the barrier fluid into a process stream with zero VOC emissions
to the atmosphere.

(c) The barrier fluid system shall be in heavy liquid service or shall not be in VOC service.

(d) Each barrier fluid system as described in paragraph (a) of this section shall be equipped with a sensor
that will detect failure of the seal system, barrier fluid system, or both.

(e) (1) Each sensor as required in paragraph (d) of this section shall be checked daily or shall be equipped
with an audible alarm.
(2) The permittee shall determine, based on design considerations and operating experience, a criterion
that indicates failure of the seal system, the barrier fluid system, or both.

(f) If the sensor indicates failure of the seal system, the barrier system, or both based on the criterion
determined under paragraph (e)(2) of this section, a leak is detected.

(g) (1) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar
days after it is detected, except as provided in Standard VII (Delay of Repair) of this permit condition.
(2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.

(h) A compressor is exempt from the requirements of paragraphs (a) and (b) of this section, if it is
equipped with a closed vent system capable of capturing and transporting any leakage from the seal to a
control device that complies with the requirements of Standard VIII of this permit condition, except as
provided in paragraph (i) of this section.

(i) Any compressor that is designated, as described in Recordkeeping Provision I(e)(1) and I(e)(2) of this
permit condition, for no detectable emissions, as indicated by an instrument reading of less than 500 ppm
above background, is exempt from the requirements of paragraphs (a) through (h) of this section if the
compressor:
(1) Is demonstrated to be operating with no detectable emissions, as indicated by an instrument reading of
less than 500 ppm above background, as measured by the methods specified in Monitoring Provision I(c)
of this permit condition; and
(2) Is tested for compliance with paragraph (i)(1) of this section initially upon designation, annually, and
at other times requested by the Director.

(j) Any existing reciprocating compressor in a process unit which becomes an affected facility under
provisions of 40 CFR 60.14 or 40 CFR 60.15 is exempt from paragraphs (a), (b), (c), (d), (e), and (h) of
this section, provided the permittee demonstrates that recasting the distance piece or replacing the
compressor are the only options available to bring the compressor into compliance with these standards.
(40 CFR60.482-3)

III. Standards for pressure relief devices in gas/vapor service.

For each pressure relief device in gas/vapor service, the permittee shall comply with the requirements as
provided in paragraphs (a) through (d) or paragraphs (e)(1) through (e)(4) of this section or demonstrate
that the pressure relief device is neither in VOC service nor in wet gas service.

52
(a) Except during pressure releases, each pressure relief device in gas/vapor service shall be operated with
no detectable emissions, as indicated by an instrument reading of less than 500 ppm above background, as
determined by the methods specified in Monitoring Provision I(c) of this permit condition.

(b) (1) After each pressure release, the pressure relief device shall be returned to a condition of no
detectable emissions, as indicated by an instrument reading of less than 500 ppm above background, as
soon as practicable, but no later than 5 calendar days after the pressure release, except as provided in
Section VII (Delay of Repair) of this permit condition.
(2) No later than 5 calendar days after the pressure release, the pressure relief device shall be monitored to
confirm the conditions of no detectable emissions, as indicated by an instrument reading of less than 500
ppm above background, by the methods Monitoring Provision I(c) of this permit condition.

(c) Any pressure relief device that is routed to a process or fuel gas system or equipped with a closed vent
system capable of capturing and transporting leakage through the pressure relief device to a control device
as described in Section VIII of this condition is exempted from the requirements of paragraphs (a) and (b)
of this section.

(d) (1) Any pressure relief device that is equipped with a rupture disk upstream of the pressure relief
device is exempt from the requirements of paragraphs (a) and (b) of this section, provided the Permittee
complies with the requirements in paragraph (d)(2) of this section.
(2) After each pressure release, a new rupture disk shall be installed upstream of the pressure relief
device as soon as practicable, but no later than 5 calendar days after each pressure release, except as
provided in Section VII (Delay of Repair) of this condition.
[40 60.482-4]

(e) (1) Each pressure relief device in gas/vapor service may be monitored within 5 days after each
pressure release to detect leaks by the methods specified in Monitoring Provision I(b) of this permit
condition, except as provided in 40 CFR 60.634, paragraph (e)(4), and paragraphs (a) through (c) of this
section.
(2) If an instrument reading of 10,000 ppm or greater is measured, a leak is detected.
(3) (i) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 calendar
days after it is detected, except as provided in Section VII (Delay of Repair) of this permit condition.
(ii) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.
(4) (i) Any pressure relief device that is located in a nonfractionating plant that is monitored only by
nonplant personnel may be monitored after a pressure release the next time the monitoring personnel are
on site, instead of within 5 days as specified in paragraphs (e)(1) and (b)(1) of this section.
(ii) No pressure relief device described in paragraph (e)(4)(i) of this section shall be allowed to operate for
more than 30 days after a pressure release without monitoring.
(40 CFR 60.633(b))
IV. Standards for open-ended valves or lines.

For each open-ended valve or line, the permittee shall comply with the requirements as provided in
paragraphs (a) through (e) of this section or demonstrate that the open-ended valve or line is neither in
VOC service nor in wet gas service.

(a) (1) Each open-ended valve or line shall be equipped with a cap, blind flange, plug, or a second valve,
except as provided in 40 CFR 60.634.
(2) The cap, blind flange, plug, or second valve shall seal the open end at all times except during
operations requiring process fluid flow through the open-ended valve or line.

53
(b) Each open-ended valve or line equipped with a second valve shall be operated in a manner such that
the valve on the process fluid end is closed before the second valve is closed.

(c) When a double block-and-bleed system is being used, the bleed valve or line may remain open during
operations that require venting the line between the block valves but shall comply with paragraph (a) of
this section at all other times.

(d) Open-ended valves or lines in an emergency shutdown system which are designed to open
automatically in the event of a process upset are exempt from the requirements of paragraphs (a), (b) and
(c) of this section.

(e) Open-ended valves or lines containing materials which would autocatalytically polymerize or would
present an explosion, serious overpressure, or other safety hazard if capped or equipped with a double
block and bleed system as specified in paragraphs (a) through (c) of this section are exempt from the
requirements of paragraphs (a) through (c) of this section. [40 CFR 60.482-6]

V. Standards for valves in gas/vapor service in light liquid service.

(a) Each valve shall comply with paragraphs (b) through (d) of this section, except as provided in
paragraphs (e), (f), and (g) of this section, Standards IX, X of this permit condition, and 40 CFR 60.634,
or demonstrate that the open-ended valve or line is neither in VOC service nor in wet gas service.

(b) If an instrument reading of 10,000 ppm or greater is measured, a leak is detected.

(c) (1) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 calendar
days after the leak is detected, except as provided in Section VII (Delay of Repair) of this condition.
(2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.

(d) First attempts at repair include, but are not limited to, the following best practices where practicable:
(1) Tightening of bonnet bolts;
(2) Replacement of bonnet bolts;
(3) Tightening of packing gland nuts;
(4) Injection of lubricant into lubricated packing.

(e) Any valve that is designated, as described in Recordkeeping Provision I(e)(2) of this permit condition,
for no detectable emissions, as indicated by an instrument reading of less than 500 ppm above
background, is exempt from the requirements of monthly monitoring in Monitoring Provision IV(a) of
this permit condition if the valve:
(1) Has no external actuating mechanism in contact with the process fluid,
(2) Is operated with emissions less than 500 ppm above background as determined by the method
specified in Monitoring Provision I(c) of this permit condition, and
(3) Is tested for compliance with paragraph (e)(2) of this section initially upon designation, annually, and
at other times requested by the Director.

(f) Any valve that is designated, as described in Recordkeeping Provision I(f)(1) of this permit condition,
as an unsafe-to-monitor valve is exempt from the requirements of monthly monitoring in Monitoring
Provision IV(a) of this permit condition if:
(1) The permittee of the valve demonstrates that the valve is unsafe to monitor because monitoring
personnel would be exposed to an immediate danger as a consequence of complying with monthly
monitoring requirement specified in Monitoring Provision IV(a) of this permit condition and

54
(2) The permittee of the valve adheres to a written plan that requires monitoring of the valve as frequently
as practicable during safe-to-monitor times.

(g) Any valve that is designated, as described in Recordkeeping Provision I(f)(2) of this permit condition,
as a difficult-to-monitor valve is exempt from the requirements of monthly monitoring in Monitoring
Provision IV(a) of this permit condition if:
(1) The permittee of the valve demonstrates that the valve cannot be monitored without elevating the
monitoring personnel more than 2 meters above a support surface.
(2) The process unit within which the valve is located either becomes an affected facility through 40 CFR
60.14 or 40 CFR 60.15or the permittee designates less than 3.0 percent of the total number of valves as
difficult-to-monitor, and
(3) The permittee of the valve follows a written plan that requires monitoring of the valve at least once per
calendar year.
(40 CFR 60.482-7 (a), (b), (d), (e), (f), (g))

VI. Standards for pumps and valves in heavy liquid service, pressure relief devices in light liquid or heavy
liquid service, and connectors

For each pumps and valve in heavy liquid service, pressure relief device in light liquid or heavy liquid
service, and connector, the permittee shall comply with the following requirements or demonstrate that
the open-ended valve or line is neither in VOC service nor in wet gas service.

(a) If evidence of a potential leak is found by visual, audible, olfactory, or any other detection method at
pumps and valves in heavy liquid service, pressure relief devices in light liquid or heavy liquid service,
and connectors, the permittee shall follow either one of the following procedures:
(1) The permittee shall monitor the equipment within 5 days by the method specified in Monitoring
Provision I(b) of this permit condition and shall comply with the requirements of paragraphs (b) through
(d) of this section

(2) The permittee shall eliminate the visual, audible, olfactory, or other indication of a potential leak.

(b) If an instrument reading of 10,000 ppm or greater is measured, a leak is detected.

(c) (1) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar
days after it is detected, except as provided in Section VII (Delay of Repair) under this condition.
(2) The first attempt at repair shall be made no later than 5 calendar days after each leak is detected.

(d) First attempts at repair include, but are not limited to, the best practices described in Standard V(d) of
this permit condition.

(40 CFR 60.482-8)

VII. Standards for delay of repair.

(a) Delay of repair of equipment for which leaks have been detected will be allowed if repair within 15
days is technically infeasible without a process unit shutdown. Repair of this equipment shall occur before
the end of the next process unit shutdown.

(b) Delay of repair of equipment will be allowed for equipment which is isolated from the process and
which does not remain in VOC service.

55
(c) Delay of repair for valves will be allowed if:
(1) The permittee demonstrates that emissions of purged material resulting from immediate repair are
greater than the fugitive emissions likely to result from delay of repair, and
(2) When repair procedures are effected, the purged material is collected and destroyed or recovered in a
control device complying with Standard VIII under this condition.

(d) Delay of repair for pumps will be allowed if:
(1) Repair requires the use of a dual mechanical seal system that includes a barrier fluid system, and
(2) Repair is completed as soon as practicable, but not later than 6 months after the leak was detected.

(e) Delay of repair beyond a process unit shutdown will be allowed for a valve, if valve assembly
replacement is necessary during the process unit shutdown, valve assembly supplies have been depleted,
and valve assembly supplies had been sufficiently stocked before the supplies were depleted. Delay of
repair beyond the next process unit shutdown will not be allowed unless the next process unit shutdown
occurs sooner than 6 months after the first process unit shutdown.

(f) When delay of repair is allowed for a leaking pump or valve that remains in service, the pump or valve
may be considered to be repaired and no longer subject to delay of repair requirements if two consecutive
monthly monitoring instrument readings are below the leak definition. (40.60.482-9)

VIII. Standards for closed vent systems and control devices.

(a) The permittee of closed vent systems and control devices used to comply with provisions of this
permit condition shall comply with the provisions of this section.

(b) Vapor recovery systems (for example, condensers and absorbers) shall be designed and operated to
recover the VOC emissions vented to them with an efficiency of 95 percent or greater, or to an exit
concentration of 20 parts per million by volume, whichever is less stringent.

(c) Enclosed combustion devices shall be designed and operated to reduce the VOC emissions vented to
them with an efficiency of 95 percent or greater, or to an exit concentration of 20 parts per million by
volume, on a dry basis, corrected to 3 percent oxygen, whichever is less stringent or to provide a
minimum residence time of 0.75 seconds at a minimum temperature of 816 °C.

(d) Flares used to comply with this permit condition shall comply with the requirements of 40 CFR 60.18.

(e) The permittee of control devices used to comply with the provisions of this permit condition shall
monitor these control devices to ensure that they are operated and maintained in conformance with their
designs.

(f) Leaks, as indicated by an instrument reading greater than 500 parts per million by volume above
background or by visual inspections, shall be repaired as soon as practicable except as provided in
paragraph (e) of this section.
(1) A first attempt at repair shall be made no later than 5 calendar days after the leak is detected.
(2) Repair shall be completed no later than 15 calendar days after the leak is detected.

(g) Delay of repair of a closed vent system for which leaks have been detected is allowed if the repair is
technically infeasible without a process unit shutdown or if the Permittee determines that emissions
resulting from immediate repair would be greater than the fugitive emissions likely to result from delay of
repair. Repair of such equipment shall be complete by the end of the next process unit shutdown.

56
(h) If a vapor collection system or closed vent system is operated under a vacuum, it is exempt from the
inspection requirements specified in Monitoring Provision VI(a)(1)(i) and VI(a)(2) of this permit
condition.

(i) Any parts of the closed vent system that are designated, as described in Recordkeeping Provision
IV(a)(1) of this permit condition., as unsafe to inspect are exempt from the inspection requirements as
specified in Monitoring Provision VI(a)(1)(i) and VI(a)(2) of this permit condition if they comply with the
requirements specified in paragraphs (g)(1) and (g)(2) of this section.

(1) The permittee determines that the equipment is unsafe to inspect because inspecting personnel would
be exposed to an imminent or potential danger as a consequence of complying with the inspection
requirements as specified in Monitoring Provision VI(a)(1)(i) and VI(a)(2) of this permit condition; and
(2) The permittee has a written plan that requires inspection of the equipment as frequently as practicable
during safe-to-inspect times.

(j) Any parts of the closed vent system that are designated, as described in Recordkeeping Provision
IV(a)(2) of this permit condition, as difficult to inspect are exempt from the inspection requirements as
specified in Monitoring Provision VI(a)(1)(i) and VI(a)(2) of this permit condition if they comply with the
requirements specified in paragraphs (h)(1) through (h)(3) of this section:
(1) The permittee determines that the equipment cannot be inspected without elevating the inspecting
personnel more than 2 meters above a support surface; and
(2) The process unit within which the closed vent system is located becomes an affected facility through
40 CFR 40 CFR 60.14 or 60.15, or the Permittee designates less than 3.0 percent of the total number of
closed vent system equipment as difficult to inspect; and
(3) The permittee has a written plan that requires inspection of the equipment at least once every 5 years.
A closed vent system is exempt from inspection if it is operated under a vacuum.

(k) Closed vent systems and control devices used to comply with provisions of this condition shall be
operated at all times when emissions may be vented to them.
[40 CFR 60.482-10(a, d, e, g, h, I, j, k, m)]

IX. Standard for alternative standards for valves-allowable percentage of valves leaking.

(a) The permittee may elect to comply with an allowable percentage of valves leaking of equal to or less
than 2.0 percent.

(b) The following requirements shall be met if permittee wishes to comply with an allowable percentage
of valves leaking:
(1) The permittee must notify the Director that the permittee has elected to comply with the allowable
percentage of valves leaking before implementing this alternative standard, as specified in Reporting
Provision I(d) of this permit condition.
(2) A performance test as specified in paragraph (c) of this section shall be conducted initially upon
designation, annually, and at other times requested by the Director.
(3) If a valve leak is detected, it shall be repaired in accordance with Standards V(c) and V(d) of this
permit condition.

(c) Performance tests shall be conducted in the following manner:
(1) All valves in gas/vapor and light liquid service within the affected facility shall be monitored within 1
week by the methods specified in Monitoring Provision I(b) of this permit condition.
(2) If an instrument reading of 10,000 ppm or greater is measured, a leak is detected.
57
(3) The leak percentage shall be determined by dividing the number of valves for which leaks are detected
by the number of valves in gas/vapor and light liquid service within the affected facility.

(d) The permittee who elect to comply with this alternative standard shall not have an affected facility
with a leak percentage greater than 2.0 percent.
(40CFR 60.483-1)

X. Standards for alternative standards for valves-skip period leak detection and repair.

(a) (1) The permittee may elect to comply with one of the alternative work practices specified in
paragraphs (b)(2) and (b)(3) of this section.
(2) The permittee must notify the Director before implementing one of the alternative work practices, as
specified in Reporting Provision I(d) of this permit condition.

(b) (1) The permittee shall comply initially with the requirements for valves in gas/vapor service and
valves in light liquid service, as described in Standard V of this permit condition.
(2) After 2 consecutive quarterly leak detection periods with the percent of valves leaking equal to or less
than 2.0, the permittee may begin to skip 1 of the quarterly leak detection periods for the valves in
gas/vapor and light liquid service.
(3) After 5 consecutive quarterly leak detection periods with the percent of valves leaking equal to or less
than 2.0, the permittee may begin to skip 3 of the quarterly leak detection periods for the valves in
gas/vapor and light liquid service.
(4) If the percent of valves leaking is greater than 2.0, the permittee shall comply with the requirements as
described in Standard V of this permit condition but can again elect to use this section.
(5) The percent of valves leaking shall be determined by dividing the sum of valves found leaking during
current monitoring and valves for which repair has been delayed by the total number of valves subject to
the requirements of this section.
(6) The permittee must keep a record of the percent of valves found leaking during each leak detection
period
(7) A valve that begins operation in gas/vapor service or light liquid service after the initial startup date
for a process unit following one of the alternative standards in this section must be monitored in
accordance with 40 CFR 60.482-7(a)(2)(i) or (ii) before the provisions of this section can be applied to
that valve.
[40CFR 60.483-2]. [Origin: DAQE-AN0100340024-16]. [40 CFR 60 Subpart KKK]

II.B.13.a.1 Monitoring:

I. General
The monitoring requirements under this section apply to all affected equipment. Compliance will
be determined by review of records and reports, review of performance test results, and
inspection using the methods and procedures specified in following paragraphs:
(a) In conducting the performance tests required in 40 CFR 60.8, the permittee shall use as
reference methods and procedures the test methods in appendix A of 40 CFR 60 or other methods
and procedures as specified in this section, except as provided in 40 CFR 60.8(b).

(b) The permittee shall determine compliance with the standards as follows:
(1) Method 21 shall be used to determine the presence of leaking sources. The instrument shall be
calibrated before use each day of its use by the procedures specified in Method 21. The following
calibration gases shall be used:
(i) Zero air (less than 10 ppm of hydrocarbon in air); and

58
(ii) A mixture of methane or n-hexane and air at a concentration of about, but less than, 10,000
ppm methane or n-hexane.

(c) The permittee shall determine compliance with the no detectable emission standards in
Standards I(d), II(i), III, V(e), and VIII(e) of this permit condition as follows:
(1) The requirements of paragraph (b) of this section shall apply.
(2) Method 21 shall be used to determine the background level. All potential leak interfaces shall
be traversed as close to the interface as possible. The arithmetic difference between the maximum
concentration indicated by the instrument and the background level is compared with 500 ppm for
determining compliance.

(d) The permittee shall test each piece of equipment unless he demonstrates that a process unit is
not in VOC service, i.e., that the VOC content would never be reasonably expected to exceed 10
percent by weight. For purposes of this demonstration, the following methods and procedures
shall be used:
(1) Each piece of equipment is presumed to be in VOC service or in wet gas service unless the
permittee demonstrates that the piece of equipment is not in VOC service or in wet gas service.
For a piece of equipment to be considered not in VOC service, it must be determined that the
VOC content can be reasonably expected never to exceed 10.0 percent by weight. For a piece of
equipment to be considered in wet gas service, it must be determined that it contains or contacts
the field gas before the extraction step in the process. For purposes of determining the percent
VOC content of the process fluid that is contained in or contacts a piece of equipment, procedures
that conform to the methods described in ASTM E169-63, 77, or 93, E168-67, 77, or 92, or E260-
73, 91, or 96 shall be used (40 CFR 60.632(f)).
(2) Organic compounds that are considered by the Director to have negligible photochemical
reactivity may be excluded from the total quantity of organic compounds in determining the VOC
content of the process fluid.
(3) Engineering judgment may be used to estimate the VOC content, if a piece of equipment had
not been shown previously to be in service. If the Director disagrees with the judgment,
paragraphs (d) (1) and (d)(2) of this section shall be used to resolve the disagreement.

(e) The permittee shall demonstrate that an equipment is in light liquid service by showing that
either the paragraphs (e)(1) through (e)(3) or paragraphs (e)(4) and (e)(5) of this section apply:
(1) The vapor pressure of one or more of the components is greater than 0.3 kPa at 20oC (1.2 in.
H20 at 68oF). Standard reference texts or ASTM D2879-83, 96, or 97 shall be used to determine
the vapor pressures.
(2) The total concentration of the pure components having a vapor pressure greater than 0.3 kPa
at 20oC (1.2 in. H20 at 68oF) is equal to or greater than 20 percent by weight.
(3) The fluid is a liquid at operating conditions.
(4) Equipment is in heavy liquid service if the weight percent evaporated is 10 percent or less at
150oC (302oF) as determined by ASTM Method D86-78, 82, 90, 95, or 96. [40 CFR 60.633(h)(1)]
(5) Equipment is in light liquid service if the weight percent evaporated is greater than 10 percent
at 150oC (302oF) as determined by ASTM Method D86-78, 82, 90, 95, or 96.
[40 CFR 60.633(h)(2)]
(f) Samples used in conjunction with paragraphs (d), (e), and (g) of this section shall be
representative of the process fluid that is contained in or contacts the equipment or the gas being
combusted in the flare.
(g) The permittee shall determine compliance with the standards of flares as follows:
(1) Method 22 shall be used to determine visible emissions.
(2) A thermocouple or any other equivalent device shall be used to monitor the presence of a pilot
flame in the flare.
59
(3) The maximum permitted velocity for air assisted flares shall be computed using the following
equation:

Vmax= K1 + K2*HT
Where:
Vmax = Maximum permitted velocity, m/sec (ft/sec)
HT = Net heating value of the gas being combusted, MJ/scm (Btu/scf).
K1 = 8.706 m/sec (metric units)
= 28.56 ft/sec (English units)
K2 = 0.7084 m4/(MJ-sec) (metric units)
= 0.087 ft4/(Btu-sec) (English units)

(4) The net heating value (HT) of the gas being combusted in a flare shall be computed using the
following equation:

Where:
K = Conversion constant, 1.740 x 10-7 (g-mole)(MJ)/ (ppm-scm-kcal) (metric units)
= 4.674 x 10-6 [(g-mole)(Btu)/(ppm-scf-kcal)] (English units)
Ci = Concentration of sample component "i," ppm
Hi = net heat of combustion of sample component "i" at 25oC and 760 mm Hg (77oF and 14.7
psi), kcal/g-mole
(5) Method 18 and ASTM D 2504-67, 77, or 88 (Reapproved 1993) shall be used to determine the
concentration of sample component "i."
(6) ASTM D 2382-76 or 88 or D4809-95 shall be used to determine the net heat of combustion of
component "i" if published values are not available or cannot be calculated.
(7) Method 2, 2A, 2C, or 2D, as appropriate, shall be used to determine the actual exit velocity of
a flare. If needed, the unobstructed (free) cross-sectional area of the flare tip shall be used.
(40 CFR60.485 & 40 CFR 60.632 (f)).

II. Pumps in light liquid services
In addition to general monitoring requirement specified in Monitoring Provision I of this permit
condition, the permittee shall comply with the following requirements pertaining to each pump in
light liquid services:
(a) A pump that begins operation in light liquid service after the initial startup date for the process
unit must be monitored for the first time within 30 days after the end of its startup period, except
for a pump that replaces a leaking pump and except as provided in 40 CFR 60.482-1(c) and (f)
and 40 CFR 60.482-2 (d), (e), and (f).
(b) (1) Each pump in light liquid service shall be monitored monthly to detect leaks by the
methods specified in Monitoring Provision I(b) of this permit condition, except as provided in 40
CFR 60.634 and Standards I(c), I(d), and I(e) of this permit condition.
(2) Each pump in light liquid service shall be checked by visual inspection each calendar week
for indications of liquids dripping from the pump seal.
(40 CFR 60.482-2 (a))

60
III. Pressure relief devices in gas/vapor service
In addition to general monitoring requirement specified in Monitoring Provision I of this permit
condition, the permittee shall comply with the following requirements pertaining to each pressure
relief device in gas/vapor service:
(a) (1) Each pressure relief device in gas/vapor service may be monitored quarterly to detect leaks
by the methods specified in Monitoring Provision I(b) of this permit condition, except as provided
in 40 CFR 60.634 and Standard III(e)(4) and Standards III(a) through (c) of this permit condition.
(40 CFR 60.633(b)(1))

IV. Valves in gas/vapor service in light liquid service.
In addition to general monitoring requirement specified in Monitoring Provision I of this permit
condition, the permittee shall comply with the following requirements pertaining to each valve in
gas/vapor service in light liquid service:
(a) A valve that begins operation in gas/vapor service or light liquid service after the initial
startup date for the process unit must be monitored according to paragraphs (a)(1) or (2) of this
section, except for a valve that replaces a leaking valve and except as provided in paragraphs (f),
(g), and (h) of 40 CFR 60.482-7, 40 CFR 60.482-1(c), and 40 CFR 60.483-1 and 60.483-2.

(1) Monitor the valve as in paragraph (a)(1) of this section. The valve must be monitored for the
first time within 30 days after the end of its startup period to ensure proper installation.
(2) If the valves on the process unit are monitored in accordance with § 60.483-1 or § 60.483-2,
count the new valve as leaking when calculating the percentage of valves leaking as described in
§ 60.483-2(b)(5). If less than 2.0 percent of the valves are leaking for that process unit, the valve
must be monitored for the first time during the next scheduled monitoring event for existing
valves in the process unit or within 90 days, whichever comes first.

(b) Each valve shall be monitored monthly to detect leaks by the methods specified in Monitoring
Provision I(b) of this permit condition.

(c) (1) Any valve for which a leak is not detected for 2 successive months may be monitored the
first month of every quarter, beginning with the next quarter, until a leak is detected.
(2) If a leak is detected, the valve shall be monitored monthly until a leak is not detected for 2
successive months.
(CFR 60.482-7 (a), (c)).

V. Pumps and valves in heavy liquid service, pressure relief devices in light liquid or heavy liquid
service, and connectors.
In addition to general monitoring requirement specified in Monitoring Provision I of this permit
condition, the permittee shall comply with the following requirements pertaining to each pump
and valve in heavy liquid service, pressure relief device in light liquid or heavy liquid service, and
connector:
(a) Each pump and valve in heavy liquid service, pressure relief device in light liquid or heavy
liquid service, and connector shall be checked by visual, audible, olfactory, or any other detection
method for a potential leak each calendar week.

VI. Closed vent systems and control devices.
In addition to general monitoring requirement specified in Monitoring Provision I of this permit
condition, each closed vent system shall be inspected according to the procedures and schedule
specified in paragraphs (a)(1) and (a)(2) of this section, except as provided in Standards VIII(h)
through VIII(j) of this permit condition.
61
(a) (1) If the vapor collection system or closed vent system is constructed of hard-piping, the
permittee shall comply with the requirements specified in paragraphs (a)(1)(i) and (a)(1)(ii) of
this section:
(i) Conduct an initial inspection according to the procedures in Monitoring I(b) of this permit
condition; and
(ii) Conduct annual visual inspections for visible, audible, or olfactory indications of leaks.

(2) If the vapor collection system or closed vent system is constructed of ductwork, the permittee
shall:
(i) Conduct an initial inspection according to the procedures in Monitoring Provision I(b) of this
permit condition; and
(ii) Conduct annual inspections according to the procedures in Monitoring Provision I(b) of this
permit condition.
(60.482-10(f)) (origin: NSPS Subpart KKK).

II.B.13.a.2 Recordkeeping:

The permittee shall maintain the records in accordance with the requirements of 40 CFR 60,
subpart A and Section I.S.1 of this permit, in addition to the following requirements:

I. General
(a) (1) The permittee subject to the provisions of this subpart shall comply with the
recordkeeping requirements of this section.
(2) The permittee of more than one affected facility subject to the provisions of this subpart may
comply with the recordkeeping requirements for these facilities in one recordkeeping system if
the system identifies each record by each facility.

(b) When each leak is detected as specified in Standards I, II, V, VI, and X of this permit
condition, the following requirements apply:
(1) A weatherproof and readily visible identification, marked with the equipment identification
number, shall be attached to the leaking equipment.
(2) The identification on a valve may be removed after it has been monitored for 2 successive
months as specified in Monitoring Provision IV(b)(1) this permit condition and no leak has been
detected during those 2 months.
(3) The identification on equipment except on a valve, may be removed after it has been repaired.

(c) When each leak is detected as specified in Standards I, II, V, VI and X of this permit
condition, the following information shall be recorded in a log and shall be kept for 2 years in a
readily accessible location:
(1) The instrument and operator identification numbers and the equipment identification number.
(2) The date the leak was detected and the dates of each attempt to repair the leak.
(3) Repair methods applied in each attempt to repair the leak.
(4) "Above 10,000" if the maximum instrument reading measured by the methods specified in
Monitoring Provision I(a) of this permit condition after each repair attempt is equal to or greater
than 10,000 ppm.
(5) "Repair delayed" and the reason for the delay if a leak is not repaired within 15 calendar days
after discovery of the leak.
(6) The signature of the permittee (or designate) whose decision it was that repair could not be
effected without a process shutdown.
(7) The expected date of successful repair of the leak if a leak is not repaired within 15 days.
(8) Dates of process unit shutdowns that occur while the equipment is unrepaired.
62
(9) The date of successful repair of the leak.

(d) The following information pertaining to the design requirements for closed vent systems and
control devices described in Standard VIII of the condition shall be recorded and kept in a readily
accessible location:
(1) Detailed schematics, design specifications, and piping and instrumentation diagrams.
(2) The dates and descriptions of any changes in the design specifications.
(3) A description of the parameter or parameters monitored, as required in Standard VIII(c) of
this condition, to ensure that control devices are operated and maintained in conformance with
their design and an explanation of why that parameter (or parameters) was selected for the
monitoring.
(4) Periods when the closed vent systems and control devices required in Standards I, II, and III
of this condition are not operated as designed, including periods when a flare pilot light does not
have a flame.
(5) Dates of startups and shutdowns of the closed vent systems and control devices required in
Standards I, II, and III of this permit condition.

(e) The following information pertaining to all equipment subject to the requirements in
Standards of this permit condition shall be recorded in a log that is kept in a readily accessible
location:
(1) A list of identification numbers for equipment subject to the requirements of this subpart.
(2) (i) A list of identification numbers for equipment that are designated for no detectable
emissions under the Standards I(d), II(i), and V(e) of this permit condition.
(ii) The designation of equipment as subject to the requirements of Standards I(d), II(i), and V(e)
of this permit condition shall be signed by the permittee.
(3) A list of equipment identification numbers for pressure relief devices required to comply with
Standard III of this permit condition.
(4) (i) The dates of each compliance test as required in Standards I(d), II(i), III, and V(e) of this
permit condition.
(ii) The background level measured during each compliance test.
(iii) The maximum instrument reading measured at the equipment during each compliance test.
(5) A list of identification numbers for equipment in vacuum service.
(6) A list of identification numbers for equipment that the permittee designates as operating in
VOC service less than 300 hr/yr in accordance with 40 CFR 60.482-1(e), a description of the
conditions under which the equipment is in VOC service, and rationale supporting the designation
that it is in VOC service less than 300 hr/yr.

(f) The following information pertaining to all valves subject to the requirements of Standards
V(f) and V(g) of this permit condition and to all pumps subject to the requirements of Standard
I(f) of this permit condition shall be recorded in a log that is kept in a readily accessible location:
(1) A list of identification numbers for valves and pumps that are designated as unsafe-to-
monitor, an explanation for each valve or pump stating why the valve or pump is unsafe-to-
monitor, and the plan for monitoring each valve or pump.
(2) A list of identification numbers for valves that are designated as difficult-to-monitor, an
explanation for each valve stating why the valve is difficult-to-monitor, and the schedule for
monitoring each value.

(g) The following information shall be recorded for valves complying with Standard X:
(1) A schedule of monitoring.
(2) The percent of valves found leaking during each monitoring period.

63
(h) The following information shall be recorded in a log that is kept in a readily accessible
location:
(1) Design criterion required in Standards I(c)(5) and II (e)(2) of this permit condition and
explanation of the design criterion; and
(2) Any changes to this criterion and the reasons for the changes.

(i) Information and data used to demonstrate that a piece of equipment is not in VOC service shall
be recorded in a log that is kept in a readily accessible location.

(j) The provisions of 40 CFR 60.7(b) and (d) do not apply to affected facilities subject to this
subpart.
(40 CFR 60.486(a) through (h), (j), and (k))

II. Compressor
In addition to general recordkeeping requirement specified in Section I of this permit condition,
the following information pertaining to the compressor described in Standard II of this permit
condition shall be recorded and kept in a readily accessible location:
(a) Information and date used to demonstrate that a reciprocating compressor is in wet gas service
to apply for the exemption in Standard II of this permit condition shall be recorded in a log that is
kept in a readily accessible location.
(40 CFR 60.635(c))

III. Pressure relief devices in gas/vapor service.
In addition to general recordkeeping requirement specified in Section I of this permit condition,
the following information pertaining to the Pressure relief devices in gas/vapor service described
in Standard III of this permit condition shall be recorded and.
kept in a readily accessible location:(a) The following recordkeeping requirements shall apply to
pressure relief devices subject to the requirements of Standard III(e)(1) and Monitoring Provision
III(a)(1) of this permit condition.
(1) When each leak is detected as specified in Standard III(e)(2) of this permit condition, a
weatherproof and readily visible identification, marked with the equipment identification number,
shall be attached to the leaking equipment. The identification on the pressure relief device may be
removed after it has been repaired.
(2) When each leak is detected as specified in Standard III(e)(2) of this permit condition, the
following information shall be recorded in a log and shall be kept for 2 years in a readily
accessible location:
(i) The instrument and operator identification numbers and the equipment identification number.
(ii) The date the leak was detected and the dates of each attempt to repair the leak.
(iii) Repair methods applied in each attempt to repair the leak.
(iv) "Above 10,000 ppm" if the maximum instrument reading measured by the methods specified
in Monitoring Provision I(a) of this permit condition after each repair attempt is 10,000 ppm or
greater.
(v) "Repair delayed" and the reason for the delay if a leak is not repaired within 15 calendar days
after discovery of the leak.
(vi) The signature of the permittee (or designate) whose decision it was that repair could not be
effected without a process shutdown.
(vii) The expected date of successful repair of the leak if a leak is not repaired within 15 days.
(viii) Dates of process unit shutdowns that occur while the equipment is unrepaired.
(ix) The date of successful repair of the leak.
(x) A list of identification numbers for equipment that are designated for no detectable emissions
under the provisions of Standard III(a) of this permit condition. The designation of equipment
64
subject to the provisions of Standard III(a) of this permit condition shall be signed by the
permittee.
(40 CFR 60.635(b))

IV. Closed vent systems and control devices.
In addition to general recordkeeping requirement specified in Recordkeeping Provision I of this
permit condition, the following information pertaining to the Closed vent systems and control
devices described in Standard VIII of this permit condition shall be recorded and kept in a readily
accessible location:
(a) The permittee shall record the information specified in paragraphs (a)(1) through (a)(5) of this
section.
(1) Identification of all parts of the closed vent system that are designated as unsafe to inspect, an
explanation of why the equipment is unsafe to inspect, and the plan for inspecting the equipment.
(2) Identification of all parts of the closed vent system that are designated as difficult to inspect,
an explanation of why the equipment is difficult to inspect, and the plan for inspecting the
equipment.
(3) For each inspection during which a leak is detected, a record of the information specified in
Recordkeeping Provision I(c) of this permit condition.
(4) For each inspection conducted in accordance with Monitoring Provision I(b) of this permit
condition during which no leaks are detected, a record that the inspection was performed, the date
of the inspection, and a statement that no leaks were detected.
(5) For each visual inspection conducted in accordance with Monitoring Provision VI(a)(1)(ii)
this permit condition during which no leaks are detected, a record that the inspection was
performed, the date of the inspection, and a statement that no leaks were detected.
[40 CFR 60.482-10(l)] (origin: NSPS Subpart KKK).

II.B.13.a.3 Reporting:

I. General
(a) The permittee subject to the provisions of this subpart shall submit semiannual reports to the
Director beginning six months after the initial startup date.

(b) The initial semiannual report, if applicable, to the Director shall include the following
information:
(1) Process unit identification.
(2) Number of valves subject to the requirements of Standard V of this permit condition,
excluding those valves designated for no detectable emissions under the provisions of Standard
V(e) of this permit condition.
(3) Number of pumps subject to the requirements of Standard I of this permit condition,
excluding those pumps designated for no detectable emissions under the provisions of Standard
I(d) of this permit condition and those pumps complying with Standard I(e) of this permit
condition.
(4) Number of compressors subject to the requirements of Standard II of this permit condition,
excluding those compressors designated for no detectable emissions under the provisions of
Standard II(i) of this permit condition and those compressors complying with Standard II(h) of
this permit condition.

(c) All semiannual reports to the Director shall include the following information, summarized
from the information in Recordkeeping requirement:
(1) Process unit identification.
(2) For each month during the semiannual reporting period,
65
(i) Number of valves for which leaks were detected as described in Standard V(b) or Standard X
of this permit condition,
(ii) Number of valves for which leaks were not repaired as required in Standard V(c)(1) of this
permit condition,
(iii) Number of pumps for which leaks were detected as described in Standards I(a) and I(c)(6)(i)
of this permit condition,
(iv) Number of pumps for which leaks were not repaired as required in Standards I(b)(1) and
I(c)(6)(ii) of this permit condition,
(v) Number of compressors for which leaks were detected as described in Standard II(f) of this
permit condition,
(vi) Number of compressors for which leaks were not repaired as required in Standard II(g)(1) of
this permit condition, and
(vii) The facts that explain each delay of repair and, where appropriate, why a process unit
shutdown was technically infeasible.
(3) Dates of process unit shutdowns which occurred within the semiannual reporting period.
(4) Revisions to items reported according to paragraph (b) of this section if changes have
occurred since the initial report or subsequent revisions to the initial report.

(d) The permittee electing to comply with the Standards IX and X of this permit condition shall
notify the Director of the alternative standard selected 90 days before implementing either of the
provisions.

(e) The permittee shall report the results of all performance tests in accordance with 40 CFR 60.8
of the General Provisions. The provisions of 40 CFR 60.8(d) do not apply to affected facilities
subject to the provisions of this subpart except that the permittee must notify the Director of the
schedule for the initial performance tests at least 30 days before the initial performance tests.
(40 CFR 60.487(a)-(e)).

II. Pressure relief devices in gas/vapor service.

In addition to the general reporting requirement specified in Reporting Provision I of this permit
condition, the permittee shall comply with the following requirements pertaining to the Pressure
relief devices in gas/vapor service described in Standard III of this permit condition:

(a) The permittee shall include the following information in the initial semiannual report if
applicable, in addition to the information required in Recordkeeping Provision I(b)(1)-(4) of this
permit condition: Number of pressure relief devices subject to the requirements in Standard III(e)
of this permit condition, except for those pressure relief devices designated for no detectable
emissions under the provisions of Standard III(a) and those pressure relief devices complying
with Standard III(c).

66
(b) The permittee shall include the following information in all semiannual reports in addition to
the information required in Recordkeeping Provision I(c)(2)(i) through (vi) of this permit
condition:
(1) Number of pressure relief devices for which leaks were detected as required in Standard
III(e)(2) of this permit condition and
(2) Number of pressure relief devices for which leaks were not repaired as required in Standard
III(e)(3) of this permit condition. (40 CFR 60.636(c)) (origin: NSPS KKK)

Status:

Not in compliance. GNG resumed the LDAR program in March 2024. It was completed by a
third-party company (Montrose Environmental). Montrose Environmental maintains the LDAR
records digitally. GNG emailed an emission detail report for all units on July 12, 2024 (email). A
pump monitor log was available on-site and shows pumps have been blocked out. AVOs are
monitored by plant personnel. The subpart KKK LDAR report for March 11, 2024, to June 30,
2024, was submitted on August 2, 2024 (mailed copy). No LDAR monitoring or reports have been
completed since the period ending June 30, 2024. The on-site contact confirmed no monitoring has
been done. Numerous calls to company contacts (with messages left) were not returned.

II.B.14 Conditions on Emergency Compressed Ignition ICE (E17&18)

II.B.14.a Condition:

Sulfur content of the diesel fuels combusted shall be no greater than 15 ppm [Origin: DAQE-
AN0100340024-16]. [R307-401-8]

II.B.14.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.14.a.2 Recordkeeping:

Fuel receipts shall be maintained to demonstrate usage of the following low-sulfur fuels having a
sulfur content less than 15 ppm: Grade Low Sulfur No. 1-D, Grade Low Sulfur No. 2-D, Grade
No. 1-D, Grade No. 2-D Records shall be maintained in accordance with Provision I.S.1 of this
permit.

II.B.14.a.3 Reporting:

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

Status: In compliance. GNG purchases ultra-low sulfur #2 diesel for fuel.

II.B.14.b Condition:

Visible emissions shall be no greater than 20 percent opacity [Origin: DAQE-AN0100340024-16].
[R307-401-8]

II.B.14.b.1 Monitoring:

Opacity observations of emissions shall be conducted annually in accordance with 40 CFR Part
60, Appendix A, Method 9.
67
II.B.14.b.2 Recordkeeping:

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

II.B.14.b.3 Reporting:

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

Status: In compliance. Annual visible emissions observations are completed by on site staff. Records are
maintained that confirm compliance. Records show no exceedances. Last VEO was done April 2,
2024, for both units.

II.B.14.c 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. [Origin: 40 CFR 63.6595(a)(1), 40 CFR 63.6605(b)].
[40 CFR 63 Subpart ZZZZ]

II.B.14.c.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.14.c.2 Recordkeeping:

The permittee shall keep the records described in 40 CFR 63.6655(a)(1)-(5) as applicable. 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.14.c.3 Reporting:

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

Status: In compliance. A maintenance program (MP2) tracks all required maintenance related to
compliance with this condition. These records confirm compliance.

68
II.B.14.d 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 paragraphs
(1)(a) through (1)(c). Any operation other than emergency operation, maintenance and testing, and
operation in non-emergency situations for 50 hours per calendar year, as described in 1.a through 1.c, is
prohibited. If the engine is not operated in accordance with paragraphs 1.a through 1.c, it will not be
considered an emergency engine and shall meet all requirements for non-emergency engines.

(a) There is no time limit on the use of emergency stationary RICE in emergency situations.

(b) Operation for any combination of the purposes specified in 40 CFR 63.6640(f)(2)(i) through (iii) is
limited to 100 hours per calendar year;

(c) The permittee may operate up to 50 hours per calendar year in non-emergency situations, but those 50
hours are counted towards the 100 hours per calendar year provided for maintenance and testing and shall
meet the requirements in 40 CFR 63.6640(f)(4)(iii). Except as provided in paragraphs 40 CFR
63.6640(f)(4)(ii), the 50 hours per calendar year for non-emergency situations cannot be used for peak
shaving or non-emergency demand response, or to generate income for a facility to an electric grid or
otherwise supply power as part of a financial arrangement with another entity.

(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.

(b) Inspect air cleaner every 1,000 hours of operation or annually, whichever comes first, and replace as
necessary;

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

(3) The permittee have the option to utilize an oil analysis program as described in 40 CFR 63.6625(j) in
order to extend the specified oil change requirement in paragraph (2)(a) of this condition.

(4) 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.

(5) The permittee shall comply with the applicable general provisions in 40 CFR 63.1-15 as identified in
Table 8 of 40 CFR 63 Subpart ZZZZ.
[Origin: 40 CFR 63.6595(a)(1), 40 CFR 636603(a), 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 2d (4), 40 CFR 63 Subpart ZZZZ Table
2d(footnote 1), 40 CFR 63 Subpart ZZZZ Table 8]. [40 CFR 63 Subpart ZZZZ]

69
II.B.14.d.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 management practice requirements on the required schedule or if
performing the management practice on the required schedule would otherwise pose an
unacceptable risk under Federal, State, or local law, the management practice can be delayed until
the emergency is over or the unacceptable risk under Federal, State, or local law has abated. The
management 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 2d Footnote 2]

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(9)]

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(j).

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.14.d.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(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(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]

70
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 40 CFR 63.6660 and Provision I.S.1 of this
permit.

II.B.14.d.3 Reporting:

The permittee shall report any failure to perform the management 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 2d Footnote 2]

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]

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

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

Status: In compliance. A maintenance program (MP2) tracks all required maintenance related to
compliance with this condition. For the 12-month period ending January 31, 2025, Unit E17 rolling
run hours were 13 and Unit E18 rolling run hours were 13.

II.B.15 Conditions on Regenerative Gas Heater (E19).

II.B.15.a Condition:

Visible emissions shall be no greater than 10 percent opacity [Origin: DAQE-AN0100340024-16].
[R307-401-8]

II.B.15.a.1 Monitoring:

In lieu of opacity monitoring, the report required for this permit condition will serve as
monitoring.

II.B.15.a.2 Recordkeeping:

The report required for this permit condition will serve as recordkeeping. Records shall be
maintained in accordance with Provision I.S.1 of this permit.

71
II.B.15.a.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee shall
certify each annual certification report that only pipeline quality natural gas is used as fuel during
the reporting year.

Status: In compliance. Only pipeline quality natural gas is used when this unit operates. As of December 5,
2024, the site is using sweet gas at 40 psi to maintain lines with no production occurring.

II.B.16 Conditions on Crude Oil/Condensate Tanks (E23).

II.B.16.a Condition:

The combined throughput to the two Crude Oil /Condensate Tanks shall not exceed 584,000 barrels per
12-month period [Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.16.a.1 Monitoring:

The oil throughput shall be measured by a certified calibrated LACT (Lease Automatic Custody
Transfer) meter. Within 10 days of the end of each month, and as of the last day of the previous
month, a new 12-month throughput total shall be calculated using the previous 12 months data.

II.B.16.a.2 Recordkeeping:

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

II.B.16.a.3 Reporting:

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

Status: Not evaluated. These units have been reported as not in use since 2016. The units have been drained
and purged.

II.B.16.b Condition:

The permittee shall keep the storage tank thief hatches closed and latched except during tank unloading or
other maintenance activities [Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.16.b.1 Monitoring:

The permittee shall inspect the thief hatches at least once every six months to ensure the thief
hatches are closed, latched and the associated gaskets, if any, are in good working condition.

II.B.16.b.2 Recordkeeping:

Records of thief hatch inspections shall include the date of the inspection and the status of the
thief hatches. Records shall be maintained in accordance with Provision I.S.1 of this permit.

72
II.B.16.b.3 Reporting:

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

Status:

Not evaluated. These units have been reported as not in use since 2016.
II.B.17 Conditions on Vapor Recovery Unit (VRU)

II.B.17.a Condition:

The vapor recovery system shall direct the VOC emissions from the two 5,000 barrel crude oil storage
tanks (E23) to the plant fuel gas system to be consumed by equipment in the Lisbon oil and gas field or at
the plant, or the VOC emissions from each crude oil tank shall be sent to the combustor unit for
combustion. [Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.17.a.1 Monitoring:

Records required for this permit condition will serve as monitoring.

II.B.17.a.2 Recordkeeping:

Records documenting compliance with the design requirements for each affected unit shall be
maintained in accordance with Provision I.S.1 of this permit.

II.B.17.a.3 Reporting:

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

Status: Not evaluated. This unit has been reported as not in use since 2016

II.B.18 Conditions on Flare/Combustor (E29)

II.B.18.a Condition:

The flare/Combustor shall be designed and operated in accordance with 40 CFR 60.18 (c) through (f).
The flare/Combustor shall be operated with no visible emissions, except for periods not to exceed a total
of 5 minutes during any 2 consecutive hours [Origin: DAQE-AN0100340024-16]. [40 CFR 60.18, 40
CFR 60.633(g)]

II.B.18.a.1 Monitoring:

A visual determination of each affected emission unit shall be conducted on a monthly basis using
40 CFR 60, Appendix A, Method 22.

II.B.18.a.2 Recordkeeping:

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

73
II.B.18.a.3 Reporting:

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

Status: Not evaluated. These units have been reported as not in use since 2016.

II.B.19 Conditions on Natural gas fired heater (E26)

II.B.19.a Condition:

Visible emissions shall be no greater than 10 percent opacity [Origin: DAQE-AN0100340024-16].
[R307-401-8]

II.B.19.a.1 Monitoring:

In lieu of opacity monitoring, the report required for this permit condition will serve as
monitoring.

II.B.19.a.2 Recordkeeping:

The report required for this permit condition will serve as recordkeeping

II.B.19.a.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee shall
certify each annual certification report that only pipeline quality natural gas is used as fuel during
the reporting year.

Status: In compliance. Only pipeline quality natural gas is used. This unit is used during winter months to
heat fire water lines. It is no longer used to heat condensate tanks as condensate circuits have been
shut down. This unit is off line as of December 25, 2024.

II.B.20 Conditions on Gas fired steam boiler (E27)

II.B.20.a Condition:

Visible emissions shall be no greater than 5 percent opacity [Origin: DAQE-AN0100340024-16].
[R307-401-8]

II.B.20.a.1 Monitoring:

In lieu of opacity monitoring, the report required for this permit condition will serve as
monitoring.

II.B.20.a.2 Recordkeeping:

The report required for this permit condition will serve as recordkeeping. Records shall be
maintained in accordance with Provision I.S.1 of this permit.

74
II.B.20.a.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee shall
certify each annual certification report that only pipeline quality natural gas is used as fuel during
the reporting year.

Status: Not evaluated. These units have not been in use since 2016 as condensate is no longer processed at
his site.

II.B.21 Conditions on Loading Rack

II.B.21.a Condition:

The permittee shall load the tanker trucks on site by the use of submerged loading
[Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.21.a.1 Monitoring:

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

II.B.21.a.2 Recordkeeping:

Records documenting compliance with the design requirements for the affected unit shall be
maintained in accordance with Provision I.S.1 of this permit.

II.B.21.a.3 Reporting:

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

Status:

Not applicable. The loading rack is used for natural gas and produced water loading. Submerged
fill loading is not applicable to these uses. This unit has not been used since December 5, 2024.

II.B.22 Conditions on Pre-1969 equipment

II.B.22.a Condition:

Visible emissions shall be no greater than 20 percent opacity [Origin: DAQE-AN0100340024-16].
[R307-401-8]

II.B.22.a.1 Monitoring:

In lieu of opacity monitoring, the report required for this permit condition will serve as
monitoring.

II.B.22.a.2 Recordkeeping:

The report required for this permit condition will serve as recordkeeping. Records shall be
maintained in accordance with Provision I.S.1 of this permit.

75
II.B.22.a.3 Reporting:

In addition to the reporting requirements specified in Section I of this permit, the permittee should
certify each annual certification report that only pipeline quality natural gas is used as fuel during
the reporting year.

Status: In compliance. Only pipeline quality natural gas is used. Some units have been replaced with
electric units as required by maintenance. No units operated except with NG or electric. These units
have not operated since December 5, 2024.

II.B.23 Conditions on Storage Tank (SW1DOT)

II.B.23.a Condition:

The permittee shall keep the storage tank thief hatches closed and latched except during tank unloading or
other maintenance activities [Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.23.a.1 Monitoring:

The permittee shall inspect the thief hatches at least once every six months to ensure the thief
hatches are closed, latched and the associated gaskets, if any, are in good working condition.

II.B.23.a.2 Recordkeeping:

Records of thief hatch inspections shall include the date of the inspection and the status of the
thief hatches. Records shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.23.a.3 Reporting:

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

Status:

Not evaluated. This tank is reported as no longer in service. It was shut down, drained, and purged
in 2019.

II.B.24 Conditions on Storage Tank (SW1BWT)

II.B.24.a Condition:

The permittee shall keep the storage tank thief hatches closed and latched except during tank unloading or
other maintenance activities [Origin: DAQE-AN0100340024-16]. [R307-401-8]

II.B.24.a.1 Monitoring:

The permittee shall inspect the thief hatches at least once every six months to ensure the thief
hatches are closed, latched and the associated gaskets, if any, are in good working condition.

76
II.B.24.a.2 Recordkeeping:

Records of thief hatch inspections shall include the date of the inspection and the status of the
thief hatches. Records shall be maintained in accordance with Provision I.S.1 of this permit.

II.B.24.a.3 Reporting:

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

Status:

In compliance. This is now a saltwater tank for injection services and contains no VOC products.
II.C Emissions Trading.

Not applicable to this source.

II.D Alternative Operating Scenarios.

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.

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 60 Subpart Kb (Standards of Performance for Volatile Organic Liquid Storage Vessels
(Including Petroleum Liquid Storage Vessels) for which Construction, Reconstruction, or
Modification Commenced After July 23, 1984)

This regulation is not applicable to the Crude Oil/Condensate Tanks (E23) for the following
reason(s): each tank has a design capacity less than 1,589.874 cubic meters used for storing
petroleum prior to custody transfer

III.B. 40 CFR Part 60 Subpart KKK (NSPS/ VOC leaks, Natural Gas Plants)

This regulation is not applicable to the Fractionation Process Unit for the following reason(s): this
process unit was constructed before January 20, 1984.

III.C. 40 CFR Part 60 Subpart KKK (NSPS/ VOC leaks, Natural Gas Plants)
This regulation is not applicable to the NESHP ZZZZ non-emergency remote engine group for the
following reason(s): this process unit was constructed before January 20, 1984.

77
III.D. 40 CFR Part 60 Subpart KKK (NSPS/ VOC leaks, Natural Gas Plants)

This regulation is not applicable to the Reciprocating Engine (E1) for the following reason(s): this
process unit was constructed before January 20, 1984. Adding the catalyst control in 2003 did not
constitute a modification.

III.E. 40 CFR Part 60 Subpart KKK (NSPS/ VOC leaks, Natural Gas Plants)

This regulation is not applicable to the Reciprocating Engine (E3) for the following reason(s): this
process unit was constructed before January 20, 1984. Adding the catalyst control in 2003 did not
constitute a modification.

EMISSIONS INVENTORY: The 2023 emissions inventory emissions are:

Polluant Tons/yr
PM10 ................................. 21.40
PM2.5 ................................. 20.92
SOx ................................... 0.09
NOx ................................. 50.43
CO ................................. 74.14
VOC ................................. 31.87
NH3 ………………………1.99
CH2O …………………….1.76

PREVIOUS ENFORCEMENT
ACTIONS:
August 9, 2019 - NOV for failure to demonstrate compliance with the
CO and NOx concentration limits in Conditions II.B.3.a and II.B.3.b.
The signed Administrative Settlement Agreement was received October
29, 2019. Engine E3 has been removed from service.

January 5, 2016 - NOV for failure to demonstrate compliance with the
NOx concentration limit in Condition II.B.4.c. The administrative
settlement for $21,300 was signed on October 1, 2017. Payment was
received on October 18, 2017. Resolved.

June 6, 2023 – NOV for failure to complete LDAR per Condition
II.B.13.

July 31, 2023 – State of Utah, Division of Air Quality filed bankruptcy
Proof of Claim (attached)

All of the above violations occurred prior to GNG taking over on March
1, 2024.

78
COMPLIANCE STATUS &
RECOMMENDATIONS: Non-compliance with the following conditions of the Title V permit
dated November 23, 2021:

I.C.1 – Failure to comply with all the Permit conditions.

I.L.1 – Failure to submit the Title V Certification. Certification due
September 30, 2024, has not been submitted to date.

I.S.2.a – Failure to submit the six-month report due September 2024. No
monitoring reports have been submitted since March 2024, when GNG
took over operations.

I.S.2.c – Failure to submit deviation reports for these Permit deviations.

II.B.4.a – E4B stack test for CO overdue. The stack test was due May
2024, and no testing has occurred.

II.B.4.c – E4B stack test for NOx overdue. The stack test was due May
2024, and no testing has occurred.

II.B.6.a – E14 stack test for CO overdue. The stack test was due October
2024, and no testing has occurred.

II.B.6.b – E14 stack test for NOx overdue. The stack test was due
October 2024, and no testing has occurred.

II.B.13 – subpart KKK requirements not completed. No monitoring or
reporting of LDAR requirements have been done since June 30, 2024.

Issue attached NOV.

HPV STATUS: Yes

COMPLIANCE
ASSISTANCE: Discussions on stack test requirements and missed or out of compliance
requirements.

RECOMMENDATION FOR
NEXT INSPECTION: Site is not manned continuously. Contact company for inspection access.

ATTACHMENTS: VEO form
NOV