DAQ-2024-011888

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DAQC-1182-24
Site ID 10124 (B1)

MEMORANDUM

TO: FILE – SILVER EAGLE REFINING – Woods Cross Inc. – Petroleum Products
Refining

THROUGH: Harold Burge, Major Source Compliance Section Manager

FROM: Robert Haynes, Environmental Scientist

DATE: November 26, 2024

SUBJECT: FULL COMPLIANCE EVALUATION, SM-80, FRS# UT0000004901100019,
Davis County

INSPECTION DATE: November 13, 2024, inspection.
October 15, 2024, observation of disconnect at loading rack.

SOURCE LOCATION: 2355 South 1100 West
Woods Cross, UT 84087

SOURCE CONTACTS: Blaine Zwahlen, contract Environmental Engineer: [phone] x128,
435-319-6861, [e-mail], cell 801-597-9229
Gigi Camarena, Environmental Assistant

OPERATING STATUS: Operating normally at time of inspection.

PROCESS DESCRIPTION: Waxy crude oil is delivered by truck to the refinery, unloaded on the north
side, and stored in aboveground storage tanks on the north side. The
company refines about 10,000 barrels of crude per day.

Crude oil is heated with boilers, furnaces, and heaters. Hot oil is sent
through various processes to separate out components. Units boil and
separates the hydrocarbons into their different boiling point materials, one
unit uses lower pressure. Products include heavy naphtha, light naphtha,
and heavy vacuum gas oil (wax). Light naphtha is sent off-site by truck for
further refining into gasoline. Heavy naphtha is processed into diesel by
blending and sulfur removal.

Fuel gas and H2S are sent to the Low-Pressure NaSH Unit where the H2S
is converted into sodium hydrosulfide (NaSH). From storage NaSH is
transported by truck to third-party customers.

The refinery has two flares; the north and south flares. The north flare was
not in use. The flares combust any hydrocarbons that are released in the
event of a process upset. Most of the refineries emergency relief valves are
vented to the flares. Excess refinery plant gas may also be combusted in the
flares. Pilot lights burn continuously on the flares.
Two cooling towers cool heated water from the process streams in a
non-contact cooling water loop. Multiple storage tanks are used to store
petroleum products, blend products, or finished products for shipping. The

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company has fixed roof tanks, fixed roof with internal floating roofs, but
no external floating roofs. The floating roof tanks have single or double
seals according to service.

The loading rack is controlled by a two stage VRU unit with one side on
line and one side in recovery. All emissions are ducted to the plant gas
system during recovery. All units have vapor recovery lines which must be
connected prior to loading. Transfer trucks must have Vapor Test
Certifications and these must be current in the system to allow loading.

The wastewater system of the refinery includes drain boxes throughout the
refinery plus drains and ducts from a tank farm. Each drain is equipped
with water seal controls. All VOC wastewater ducts converge into a single
API separator that has multiple cells and a skimmer. The sewer lines and
feed lines to the API separator are buried except at the first openings that
are enclosed. No vent pipes are used. Wastewater and storm water are
eventually discharged from the plant into the city industrial sewer system
once it passes through an on-site bacterial aerator.

APPLICABLE
REGULATIONS: Approval Order (AO) DAQE-AN101240030-16 dated November 9, 2016
NSPS (Part 60), A: General Provisions
NSPS (Part 60), J: Standards of Performance for Petroleum Refineries
NSPS (Part 60), Ja: Standards of Performance for Petroleum Refineries for
Which Construction, Reconstruction, or Modification Commenced After
May 14, 2007
NSPS (Part 60), K: Standards of Performance for Storage Vessels for
Petroleum Liquids for Which Construction, Reconstruction, or
Modification Commenced After June 11, 1973, and Prior to May 19, 1978
NSPS (Part 60), Ka: Standards of Performance for Storage Vessels for
Petroleum Liquids for Which Construction, Reconstruction, or
Modification Commenced After May 18, 1978, and Prior to July 23, 1984
NSPS (Part 60), 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
NSPS (Part 60), GGG: Standards of Performance for Equipment Leaks of
VOC in Petroleum Refineries for which Construction, Reconstruction, or
Modification Commenced After January 4, 1983, and on or Before
November 7, 2006
NSPS (Part 60), QQQ: Standards of Performance for VOC Emissions from
Petroleum Refinery Wastewater Systems
NSPS (Part 60), IIII: Standards of Performance for Stationary Compression
Ignition Internal Combustion Engines
MACT (Part 63), A: General Provisions
MACT (Part 63), ZZZZ: National Emissions Standards for Hazardous Air
Pollutants for Stationary Reciprocating Internal Combustion Engines
MACT (Part 63), BBBBBB: National Emission Standards for Hazardous
Air Pollutants for Source Category: Gasoline Distribution Bulk Terminals,
Bulk Plants, and Pipeline Facilities

SOURCE EVALUATION: Approval Order (AO) DAQE-AN101240030-16 dated November 9, 2016

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Section I: GENERAL PROVISIONS

I.1 All definitions, terms, abbreviations, and references used in this AO conform to those used in
the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AO conditions
refer to those rules. [R307-101]

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

I.3 Modifications to the equipment or processes approved by this AO that could affect the
emissions covered by this AO must be reviewed and approved. [R307-401-1]

Status: Informational Item.

I.4 All records referenced in this AO or in other applicable rules, which are required to be kept
by the owner/operator, shall be made available to the Director or Director's representative
upon request, and the records shall include the two-year period prior to the date of the
request. Unless otherwise specified in this AO or in other applicable state and federal rules,
records shall be kept for a minimum of five (5) years. [R307-415-6a]

I.5 At all times, including periods of startup, shutdown, and malfunction, owners and operators
shall, to the extent practicable, maintain and operate any equipment approved under this AO
including associated air pollution control equipment in a manner consistent with good air
pollution control practice for minimizing emissions. Determination of whether acceptable
operating and maintenance procedures are being used will be based on information available
to the Director which may include, but is not limited to, monitoring results, opacity
observations, review of operating and maintenance procedures, and inspection of the source.
All maintenance performed on equipment authorized by this AO shall be recorded.
[R307-401-4]

Status: Records are electronic and kept for 5 years. The source has implemented operating
requirements and protocols to operate as efficiently as possible. Requested
documentation was provided upon request. In compliance.

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

I.7 The owner/operator shall comply with UAC R307-150 Series. Emission Inventories.
[R307-150]

Status: No reportable breakdowns identified for the past two years. The source sent in their
emission inventories as required. In Compliance.

Section II: SPECIAL PROVISIONS

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

II.A.1 Refinery
Source Wide

II.A.2 BenSat Furnace
12 MMBtu/hr furnace, fired on plant gas and/or natural gas

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II.A.3 F-231: Crude Unit #1 Furnace
30 MMBtu/hr furnace, fired on plant gas and/or natural gas

II.A.4 HT: Hydrotreater Unit
Fired with two furnaces, controlled with existing flares

II.A.5 HT Charge Furnace
19.55 MMBtu/hr furnace with low-NOx burners, fired on plant gas

II.A.6 HT Fractionator Furnace
27.6 MMBtu/hr furnace with low-NOx burners, fired on plant gas

II.A.7 H-104: MDDW Heater
27 MMBtu/hr furnace with low-NOx burners, fired on natural gas or plant gas

II.A.8 H-103: MDDW Reboiler Heater
10 MMBtu/hr heater, fired on natural gas or plant gas

II.A.9 F-501: Vacuum Furnace
11 MMBtu/hr furnace, fired on plant gas and/or natural gas

II.A.10 B-1: Boiler #1
23,000 lbs/hr steam furnace, fired on plant gas and/or natural gas

II.A.11 B-2: Boiler #2
23,000 lbs/hr steam furnace, fired on plant gas and/or natural gas

II.A.12 Distillate Dewaxing Unit (MDDW)

II.A.13 Vacuum Distillation Unit (VDU)

II.A.14 Cooling Towers
Two (2) cooling towers

II.A.15 Sulfur Recovery Unit (NASH Unit)

II.A.16 Two Railcar Loading Terminals
North and South Loading Terminals

II.A.17 Finished Products and Intermediates Loading Rack
Submerged Loading Normal Service

II.A.18 Vapor Recovery Unit (VRU)
Vapor Recovery Unit on Gasoline Loading Rack

II.A.19 North Flare
Flare for combusting gases from process relief valves and excess plant gas

II.A.20 South Flare
Flare for combusting gases from process relief valves and excess plant gas

II.A.21 Isomerization Furnaces
Two (2) Isomerization Unit Process Furnaces
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II.A.22 HTR-50401
Isomerization Unit Hot Oil Heater (1.5 MMBtu/hr)

II.A.23 HTR-50402
Isomerization Unit Stabilizer Heater (10 MMBtu/hr)

II.A.24 Emergency Equipment
Two (2) diesel fired emergency firewater pumps: 460 hp & 300 hp
One (1) diesel fired emergency generator: 369 hp

II.A.25 Naphtha Railcar Loading System

II.A.26 Tank Farms Process Drains

II.A.27 Tank 00: Storage vessel - API Separator Wastewater
9,038 barrel storage vessel with fixed roof

II.A.28 Tank 1: yellow wax crude
61,668 barrel storage vessel with internal floating roof

II.A.29 Tank 2: Storage vessel - yellow wax crude
28,409 barrel storage vessel with floating roof

II.A.30 Tank 3: Storage vessel - vacuum tower bottoms
9,916 barrel storage vessel with fixed roof

II.A.31 Tank 9: residual oil #6
4,979 barrel storage vessel with vertical fixed roof

II.A.32 Tank 10: Storage vessel - HT distillate
4,849 barrel storage vessel with fixed roof

II.A.33 Tank 11: Storage vessel - gas oil
4,874 barrel storage vessel with fixed roof

II.A.34 Tank 12: Storage vessel - gas oil
4,991 barrel storage vessel with fixed roof

II.A.35 Tank 15: yellow wax crude
30,598 barrel storage vessel with internal floating roof

II.A.36 Tank 16: light to heavy distillates
9,918 barrel storage vessel with vertical fixed roof

II.A.37 Tank 17: light to heavy distillates
9,738 barrel storage vessel with vertical fixed roof

II.A.38 Tank 18: Storage vessel - yellow wax crude
33,409 barrel storage vessel with floating roof

II.A.39 Tank 19: refinery stormwater surge
11,207 barrel storage vessel with vertical fixed roof

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II.A.40 Tank 20: Storage vessel - heavy vacuum gas oil
11,207 barrel storage vessel with fixed roof

II.A.41 Tank 23: Storage vessel - petroleum liquids
33,391 barrel storage vessel with floating roof

II.A.42 Tank 24: Storage vessel - yellow wax crude
33,391 barrel storage vessel with floating roof

II.A.43 Tank 25: light to heavy distillates
6,658 barrel storage vessel with vertical fixed roof

II.A.44 Tank 26: petroleum liquids
6,463 barrel storage vessel with internal floating roof

II.A.45 Tank 27: distillates
10,979 barrel storage vessel with internal floating roof

II.A.46 Tank 28: distillates
10,990 barrel storage vessel with internal floating roof

II.A.47 Tank 29: distillates
9,800 barrel storage vessel with vertical fixed roof

II.A.48 Tank 31: Storage vessel - diesel additive
200 barrel storage vessel with fixed roof

II.A.49 Tank 41: distillates
4,162 barrel storage vessel with internal floating roof

II.A.50 Tank 42: distillates
5,260 barrel storage vessel with internal floating roof

II.A.51 Tank 43: distillates
1,523 barrel storage vessel with internal floating roof

II.A.52 Tank 47: light distillates
627 barrel storage vessel with internal floating roof

II.A.53 Tank 48: light distillates
627 barrel storage vessel with internal floating roof

II.A.54 Tank 61: petroleum liquids
9,905 barrel storage vessel with fixed roof

II.A.55 Tank 62: recovered slop oil
246 barrel storage vessel with fixed roof

II.A.56 Tank 81: NASH
2,604 barrel storage vessel with fixed roof

II.A.57 Tank 83: caustic
808 barrel storage vessel with fixed roof
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II.A.58 Tank 84: caustic
120 barrel storage vessel with fixed roof

II.A.59 Tank 85: caustic
271 barrel storage vessel with fixed roof

II.A.60 Tank 86: caustic
977 barrel storage vessel with fixed roof

II.A.61 Tank 101: petroleum liquids
33,634 barrel storage vessel with floating roof

II.A.62 Tank 102: petroleum liquids
22,157 barrel storage vessel with internal floating roof

II.A.63 Tank 103: petroleum liquids
33,580 barrel storage vessel with floating roof

II.A.64 Tank 104: petroleum liquids
33,508 barrel storage vessel with floating roof

II.A.65 Tank 105: petroleum liquids
15,887 barrel storage vessel with floating roof

II.A.66 Tank 106: petroleum liquids
15,848 barrel storage vessel with internal floating roof

Status: The source indicated the following:
II.A.2 BenSat Furnace not in service.
II.A.4 HT: Hydrotreater Unit, II.A.5 HT Charge Furnace, and II.A.6 HT Fractionator
Furnace had not been installed yet.
Item II.A.9 Vacuum Furnace has a new, Low NOx unit.
Item II.A.25 (Naptha Railcar Loading) not in use.
Item II.A.19 The North flare has not been operating.
Item II.A.32 Tank 10 is no longer in service (has been demolished).
II.A.48 Tank 31: Storage vessel-diesel additive, II.A.49 Tank 41: distillates, and II.A.51
Tank 43: distillates are currently out of service but may be used in the future.

Equipment appeared consistent with AO. No unapproved equipment noted. In
compliance.

II.B Requirements and Limitations

II.B.1 The Refinery

II.B.1.a Visible emissions from the following emission points shall not exceed the following values:

1. Point or fugitive emissions associated with the installation or control facilities from
combustion sources shall not exceed 10% opacity.

2. Diesel combustion shall not exceed 20% opacity.

3. Fugitive emissions shall not exceed 15% opacity, except fugitive dust.
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4. Fugitive dust emissions shall not exceed 20% opacity and 10% at the property boundary.

5. Flares shall produce no visible emissions except for periods not to exceed five minutes
during any two consecutive hours.

6. All other emission points shall not exceed 20% opacity.

Opacity observations of emissions from stationary sources (other than the flares) shall be
conducted according to 40 CFR 60, Appendix A, Method 9 or as directed by the Director.

Visible fugitive dust emissions from haul-road traffic and mobile equipment in operational
areas shall not exceed 20% opacity at any point. Visible emission determinations shall use
procedures similar to Method 9. The normal requirement for observations to be made at 15-
second intervals over a six-minute period, however, shall not apply. Visible emissions shall
be measured at the densest point of the plume but at a point not less than 1/2 vehicle length
behind the vehicle and not less than 1/2 the height of the vehicle.

Opacity observations of emissions from the flares shall be conducted according to 40 CFR
60, Appendix A, Method 22. [R307-401]

Status: All emission points observed during the site inspection were within the required opacity
limits. The source has an employee currently Method 9 certified who performs monthly
opacity observations. Review of observations show Method 9 sheet used and readings in
accordance with method and include all point sources as well as road dust reading. In
compliance.

II.B.1.b Silver Eagle shall use natural gas, and/or plant fuel gas as a primary fuel in all plant fuel
burning equipment except as otherwise specified. Fuel oil may be fired as a backup fuel only
during periods of natural gas curtailment or to test oil-burning capability of units. Testing
may be done one hour per month. [R307-401]

Status: The source uses both natural gas and plant gas but is not capable of using fuel oil for
any reason in the process stream. Fuel oil is only used in the emergency generator and
fire pumps. In compliance.

II.B.1.c Silver Eagle shall use only natural gas, and /or plant fuel gas that has an H2S content no
higher than 0.10 grain/dscf (based on a 3-hour rolling average) as a fuel for any fuel burning
devices subject to 40 CFR 60 Subpart J. [R307-401]

Status: The facility monitors H2S with a CEMS. CEMS reports are sent to the DAQ quarterly
for review. No exceedances have been reported. See site file for CEMS reports. Note:
SIP requires the source to be compliant with Subpart Ja instead of Subpart J which
requires a ppm limit rather than the listed grain/dscf. Readings taken during the
inspection showed 3-hour avg of 0.00 ppmv for plant gas meter and 14.55 ppmv for
flare meter reading. In compliance.

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II.B.1.d All fuel oil consumed shall be ultra-low sulfur diesel or better. Sulfur content shall be
determined by ASTM Method D-4294-89, or approved equivalent. [R307-401]

Status: ULS fuel oil is purchased for the fire pumps and back-up generator. Receipts show ULS
fuel is used. In compliance.

II.B.1.e VOC products shall be stored only in tanks that have the appropriate emissions controls as
specified by NSPS and/or R307-327. Silver Eagle shall maintain records to demonstrate the
true vapor pressure of the products stored in each tank and the type of emission controls
applied to each tank. [R307-401]

Status: All Naptha tanks have internal floating roofs. Diesel tanks only have internal floating
roofs in some instances. All tanks are tracked on a tracking system for monthly
averages. The company submits seal inspection reports. In compliance.

II.B.1.f Silver Eagle shall comply with all applicable provisions of SIP Section IX Part H.11.g.
Petroleum Refineries. [SIP Section IX.H.11]

Status: See SIP compliance evaluation below.

II.B.2 Conditions and Limitations

II.B.2.a Silver Eagle shall not exceed the following throughput value:

15,000 barrels per day (bpd) of crude on a 30-day rolling average.

Throughput shall be determined through the use of flow meters. [R307-401-8]

Status: The highest 30-day production average since January 1, 2022, was 11,214 barrels per
day based on spreadsheet values. Spreadsheet is kept showing daily and rolling
numbers for emissions, and daily and 30-day averages for throughput. Numbers are
updated each day. In compliance.

II.B.2.b Total emissions of greenhouse gases (GHG) shall not exceed 98,000 tons per rolling 12-
month period. Compliance with this limitation shall be demonstrated using the monthly GHG
emission values recorded for 40 CFR 98 Subpart C, "General Stationary Fuel Combustion
Sources", and Subpart Y, "Petroleum Refineries". Each month a new 12-month rolling total
will be calculated using the values from the previous 12 months. Compliance shall be
determined monthly. [40 CFR 98, R307-401]

Status: The rolling total as of October 31, 2024, was 47,706 metric tons (52,587 tons). Records
kept in spreadsheets are tracked as monthly and 12-month totals. No exceedances of the
rolling total occurred based on review of spreadsheet. In compliance.

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II.B.2.c Total emissions to the atmosphere from all regulated emission points and all regulated
fugitive emissions shall not exceed the following rates:

Pollutant/Period Emission Limit Units

PM10
Annual 14.47 tons/rolling 12-month period

SO2
Annual 2.03 tons/rolling 12-month period

NOx
Annual 67.5 tons/rolling 12-month period. [R307-401]

Status: The 12-month totals for the 12-month period ending October 31, 2024, were 31.92 tons
of NOx, 2.02 tons of PM10, and 0.41 tons of SOx based on provided spreadsheet. A
spreadsheet is kept showing daily and rolling numbers for emissions, and daily and
30-day averages for throughput. Numbers are updated each day. Review of the
spreadsheet shows no 12-month total exceeding the allowed limit. In compliance.

II.B.2.d The following combustion emission factors shall be used to calculate emissions:

Pollutant/Source Emission Factors Units Reference

SO2
Natural Gas Combustion 0.60 lbs/MMscf AO limit
Plant Fuel Gas Combustion
(Note 2) (Note 1) lbs/MMscf Calculated

NOx
Natural Gas or Plant Fuel Gas
Combustion 100 lbs/MMscf AP-42
Natural Gas or Plant Fuel Gas
with Low NOx burners 50 lbs/MMscf AP-42

PM10
Natural Gas or Plant Fuel Gas
Combustion 5 lbs/MMscf AO limit

Note 1: Emission factor shall be calculated from the H2S content of the plant fuel gas as
shown in Condition II.B.2.e.

Note 2: The term plant fuel gas as used in this permit means either refinery generated fuel
gas or a mixture of refinery generated plant fuel gas and natural gas. [R307-401]

Status: The most recent check of the spreadsheet indicated that the appropriate emission
factors are being used. In compliance.

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II.B.2.e The SO2 emission factors for plant fuel gas shall be determined as follows:

The H2S content of the plant fuel gas shall be measured, in parts per million by volume
(ppmv), by a continuous emissions monitor located downstream of the refinery fuel gas drum.
Daily plant fuel gas emission factors shall be calculated as follows using average hourly H2S
content data from the CEM:

(lb SO2 / 10^6 scf gas) = (24 hr avg. ppmv H2S)/10^6 * (64 lb SO2 / lb mole) / (385.65 scf / lb
mole measured at 68 deg. F)
[R307-401]

Status: The most recent check of the spreadsheet indicated that the appropriate emission
factors are being used. In compliance.

II.B.2.f Compliance with the SO2, NOx and PM10 emissions limitations in Condition II.B.2.c shall be
determined by applying the appropriate emissions factors from Conditions II.B.2.d and
II.B.2.e to the relevant quantities of fuel combusted in all furnaces, heaters, and boilers as
follows:

For plant fuel gas the following equation shall be used:

Daily Emissions = Emission Factor (lbs/MMscf) * Gas Consumption (MMscf/24 hrs) /
(2,000 lb/ton)

The gas stream, providing natural gas/plant fuel gas to all furnaces, heaters and boilers, shall
be measured by meters monitoring the flow to each combustion device. Total annual
emissions shall be calculated using the sum of all the individual meters.

Fuel gas flow to the individual meters will be normalized to equal the amount of fuel gas
consumed as recorded by the supplied natural gas custody transfer meter and the refinery
Green House Gas Meter that records the amount of fuel gas generated by the refinery.

SRU turnaround emissions are not to be included in the emissions limitations of Condition
II.B.2.c. [R307-401]

Status: The most recent check of the spreadsheet indicated that emissions are being calculated
in accordance with this condition. In compliance.

II.B.2.g Compliance with annual limitations shall be determined on a rolling 12-month total. Based on
the first day of each month, the previous month's daily (24-hour) emissions shall be summed
for a monthly total. Annual emissions shall be the summation of the last 12 monthly totals.
Results shall be tabulated monthly. [R307-401]

Status: Spreadsheet was provided and includes daily and 12-month totals for several years.
Review of the spreadsheet shows correct calculations done on a daily and monthly basis.
In compliance.

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II.B.2.h Silver Eagle shall install, calibrate, maintain, and operate a continuous monitoring system
located downstream of the primary fuel mixing drum to determine compliance with the SO2
emission limits and the H2S limits of NSPS subpart J. The owner/operator shall record the
output of the system, for measuring the H2S concentration in the plant fuel gas. SO2
emissions rates shall be calculated assuming 100% of the H2S in the plant fuel gas is
combusted forming SO2 at a ratio of 34 lbs of H2S equals 64 lbs of SO2. The monitoring
system shall comply with all applicable sections of R307-170 and 40 CFR 60, Appendix B,
Specification 7 - H2S. Notification about RATA testing shall be submitted 45 days prior to
testing. [R307-401]

Status: The company does submit Part 170 data and reports. The Relative Accuracy Test Audit
(RATA) appears to be conducted annually and is submitted for review. All reports are
reviewed by the CEM specialist and are in the source files. In compliance.

II.B.2.i Silver Eagle generated plant fuel gas shall be continuously monitored with equipment that
will determine the quantity of plant fuel gas consumed. The meters outputs shall be located
such that an inspector/operator can safely read the output at any time. An accuracy check of
the transmitters and/or transducers for the meter measurement parameters shall be performed
at least once every 120 days. The response of each individual transmitter/transducer shall be
checked against a standard to verify on overall accuracy of the meter reading to within plus or
minus two (2) percent of the full scale of the meter. The accuracy of each
transmitter/transducer tested shall be calculated as follows:

ACC = 100 x [(Standard - Reading) / Full Scale ]

If each transmitter/transducer has an accuracy (ACC) value within plus or minus one (1)
percent of tranducer full scale, the meter system shall be considered to have passed the two
(2) percent overall accuracy criterion. The specification for the measurement standard(s)
and/or alternative methods of calculating overall accuracy shall be established by the
company and shall be submitted to the Director for approval. [R307-401, 40 CFR 75]

Status: Calibration is performed in house by maintenance personnel. Maintenance calibration
is performed quarterly as required. Copies of calibrations are available for review
during inspection as part of maintenance tracking system. In compliance.

II.B.3 Vacuum Distillation Unit (VDU)

II.B.3.a All vacuum ejector exhaust from the vacuum distillation unit shall be incinerated in one of
the process heaters. [R307-401]

Status: Previous review of the piping diagram shows all VDU exhaust does go to the vacuum
furnace or auxiliary heater. In compliance.

II.B.4 Sulfur Recovery Unit (SRU)

II.B.4.a The SRU shall be at least 95% effective in removing sulfur from the streams fed into the unit.
Shut down for routine maintenance (expected every two to five years for a period of
approximately 15 days) for the SRU shall only be scheduled during the period from April
through October. The projected periods/forecasts for the SRU (NASH) turnarounds shall be
submitted to the Director by the end of the first calendar quarter of each year planned and 30
days prior to the turnaround a notice shall be given to the Director. The emissions increase
(above normal operations) experienced during the SRU routine turnarounds shall not be
included in the annual compliance demonstration of condition II.B.2.c. Copies of the SRU
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Operating Instruction/Standard shall be made available to the Executive Secretary upon
request.

In the event the SRU efficiency drops and remains below 95%, the refinery shall isolate the
problem within five days from discovery. A permanent repair or modification shall be
accomplished within 15 days from the day of discovery. If the repair proves to be
satisfactory, i.e., no repeat failure modes of the same type occur for at least 30 days, the
efficiency drop shall not be considered a violation. A separate failure within the 30-day
period shall constitute a new event.

SRU efficiency shall be estimated and reported to the Director a minimum of once per year
via the following method: Over a minimum of three and a maximum of seven operating days
or other period of time as approved by the Director, the total H2S output from the SRU plant
fuel gas (prior to mixing with natural gas) and the concentration of sulfur in the inlet and
outlet streams from the low pressure NASH unit shall be measured. From these parameters
the SRU efficiency shall be calculated. An alternate method may be used if approved by the
Director. [R307-401]

Status: The source file contains copies of test notifications. The most recent test done February
19-21, 2024, showed an average efficiency of 99.92%. The test calculations and
parameters are included in the report. In compliance.

II.B.4.b The SRU throughput rate during SRU testing will be used to determine the maximum
monthly operating rate of the unit. The SRU throughput rate during the test plus 10%
becomes the monthly maximum allowable operating rate. Additional testing at higher
throughput rates will be required to establish a higher monthly maximum allowable operating
rate if the existing monthly maximum allowable throughput rate is to be exceeded. The
maximum monthly SRU operating rate so determined shall in no way supersede the
constraints established in the emissions limitations section of the AO. [R307-401]

Status: The Sulfur Recovery Unit (SRU) throughput is tracked with the use of a flow meter.
The flow can vary depending on the season and on severity of operations. This
throughput does not relate directly to the plant production numbers. However, the SRU
throughput rate, as determined at the MDDW, is used. As this is a limiting factor for
production, a change to language in this condition will be made during next Notice of
Intent. In compliance.

II.B.4.c Silver Eagle shall notify the Director of test dates at least 30 days prior to a stack test or SRU
compliance test. A pretest conference shall be held if directed by the Director. The
conference shall be held at least 30 days prior to the test and shall be attended by the
owner/operator, the tester, and the Director or representative. [R307-401]

Status: Test notices for the past two years have been received 30 days prior to actual testing to
ensure proper test oversight, see source files for notifications. In compliance.

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II.B.5 Vapor Recovery Unit (VRU)

II.B.5.a VRU on Loading Rack: The loading device shall not leak and shall be designed and operated
to allow no more than an average of 15cc drainage per disconnect for five consecutive
disconnects. All loading and vapor lines shall be equipped with fittings which make a vapor
tight connection and shall be closed prior to disconnection to prevent release of VOC. In no
case shall vapor emissions to the atmosphere exceed 0.64 lb/1000 gallons gasoline/ethanol
transferred. An approved inspection program shall be in place prior to the compliance test.
Testing procedures shall be consistent with the requirements of R307-328. Necessary repairs
to lines, joints, etc., shall be completed as soon as practicable as specified in R307-328. All
transport vessels loading gasoline/gasohol shall be equipped with compatible bottom load
connections and vapor recovery systems. [R307-401]

Status: The loading rack is inspected semi-annually. The equipment appears to be maintained
in accordance with good safety and environmental practices and all transport vessels
are bottom loaded to minimize emissions. Emissions numbers were confirmed during
the AO process. One naphtha loading was observed during a past walkthrough
inspection. The vapor recovery system must be hooked up to allow fuel delivery. One
disconnect was observed on October 15, 2024, with disconnect from one loading port to
a second loading port, and no drops were observed during the disconnect. In
compliance.

II.B.6 Emergency Equipment

II.B.6.a All emergency generators shall be used for electricity producing operation only during the
periods when electric power from the public utilities is interrupted, or for regular
maintenance of the generators. Records documenting generator usage shall be kept in a log
and they shall show the date the generator was used, the duration in hours of the generator

usage, and the reason for each generator usage. Firewater pumps shall be used only for
emergency and maintenance/testing purposes.

Emergency generators and firewater pumps hours of operation for maintenance firing
purposes shall not exceed 100 hours per rolling 12-month total for each. To determine
compliance with a rolling 12-month total, based on the first day of each month a new 12-
month total shall be calculated using data from the previous 12 months. Monthly calculations
shall be made no later than 20 days after the end of each calendar month. [R307-401]

Status: The 12-month total hours as of October 31, 2024, were: 5.63 - old fire pump engine,
18.90 - new fire pump, and 20.50 - back-up generator. Spot check of engine hours on
equipment to hours reported was done. In compliance.

15
Section III: APPLICABLE FEDERAL REQUIREMENTS

In addition to the requirements of this AO, all applicable provisions of the following federal programs
have been found to apply to this installation. This AO in no way releases the owner or operator from any
liability for compliance with all other applicable federal, state, and local regulations including UAC
R307.

NSPS (Part 60), A: General Provisions

Status: In compliance. Reports and notifications made.

NSPS (Part 60), J: Standards of Performance for Petroleum Refineries

Status: In compliance. Silver Eagle operates the applicable flare under Subpart Ja as required in
the State Implementation Plan evaluated later in this report. Silver Eagle does not have a
Fluid Catalytic Cracking Unit (FCCU) or Claus sulfur recover plant.

NSPS (Part 60), Ja: Standards of Performance for Petroleum Refineries for Which Construction,
Reconstruction, or Modification Commenced After May 14, 2007

Note: Only the relevant sections called out in the SIP are included.

1. §60.100a Applicability, designation of affected facility, and reconstruction.
(a) The provisions of this subpart apply to the following affected facilities in petroleum refineries:
fluid catalytic cracking units (FCCU), fluid coking units (FCU), delayed coking units, fuel gas
combustion devices (including process heaters), flares and sulfur recovery plants. The sulfur recovery
plant need not be physically located within the boundaries of a petroleum refinery to be an affected
facility, provided it processes gases produced within a petroleum refinery. ... (Text deleted for
brevity.)
(c) For all affected facilities other than flares, the provisions in §60.14 regarding modification apply.
As provided in §60.14(f), the special provisions set forth under this subpart shall supersede the
provisions in §60.14 with respect to flares. For the purposes of this subpart, a modification to a flare
occurs as provided in paragraphs (c)(1) or (2) of this section.
(1) Any new piping from a refinery process unit, including ancillary equipment, or a fuel gas system
is physically connected to the flare (e.g., for direct emergency relief or some form of continuous or
intermittent venting). However, the connections described in paragraphs (c)(1)(i) through (vii) of this
section are not considered modifications of a flare.
(i) Connections made to install monitoring systems to the flare.
(ii) Connections made to install a flare gas recovery system or connections made to upgrade or
enhance components of a flare gas recovery system (e.g., addition of compressors or recycle lines).
(iii) Connections made to replace or upgrade existing pressure relief or safety valves, provided the
new pressure relief or safety valve has a set point opening pressure no lower and an internal diameter
no greater than the existing equipment being replaced or upgraded.
(iv) Connections made for flare gas sulfur removal.
(v) Connections made to install back-up (redundant) equipment associated with the flare (such as a
back-up compressor) that does not increase the capacity of the flare.
(vi) Replacing piping or moving an existing connection from a refinery process unit to a new location
in the same flare, provided the new pipe diameter is less than or equal to the diameter of the
pipe/connection being replaced/moved.
(vii) Connections that interconnect two or more flares.
(2) A flare is physically altered to increase the flow capacity of the flare.

16
(d) For purposes of this subpart, under §60.15, the “fixed capital cost of the new components”
includes the fixed capital cost of all depreciable components which are or will be replaced pursuant to
all continuous programs of component replacement which are commenced within any 2-year period
following the relevant applicability date specified in paragraph (b) of this section.

Status: In compliance. Applicability for the refinery fuel gas and the hydrocarbon flare is required
by the State Implementation Plan for PM evaluated later in this report. The source does not
have an FCCU or FCU. Only the required sections are included in this report as specified in
the SIP.

2. §60.102a Emissions limitations.
(a) Each owner or operator that is subject to the requirements of this subpart shall comply with the
emissions limitations in paragraphs (b) through (i) of this section on and after the date on which the
initial performance test, required by §60.8, is completed, but not later than 60 days after achieving the
maximum production rate at which the affected facility will be operated or 180 days after initial
startup, whichever comes first. ...
(g) Each owner or operator of an affected fuel gas combustion device shall comply with the emissions
limits in paragraphs (g)(1) and (2) of this section.
(1) Except as provided in (g)(1)(iii) of this section, for each fuel gas combustion device, the owner or
operator shall comply with either the emission limit in paragraph (g)(1)(i) of this section or the fuel
gas concentration limit in paragraph (g)(1)(ii) of this section. For CO boilers or furnaces that are part
of a fluid catalytic cracking unit or fluid coking unit affected facility, the owner or operator shall
comply with the fuel gas concentration limit in paragraph (g)(1)(ii) for all fuel gas streams combusted
in these units.
(i) The owner or operator shall not discharge or cause the discharge of any gases into the atmosphere
that contain SO2 in excess of 20 ppmv (dry basis, corrected to 0-percent excess air) determined hourly
on a 3-hour rolling average basis and SO2 in excess of 8 ppmv (dry basis,
corrected to 0-percent excess air), determined daily on a 365 successive calendar day rolling average
basis; or
(ii) The owner or operator shall not burn in any fuel gas combustion device any fuel gas that contains
H2S in excess of 162 ppmv determined hourly on a 3-hour rolling average basis and H2S in excess of
60 ppmv determined daily on a 365 successive calendar day rolling average basis.
(iii) The combustion in a portable generator of fuel gas released as a result of tank degassing and/or
cleaning is exempt from the emissions limits in paragraphs (g)(1)(i) and (ii) of this section. ...

Status: In compliance. Emission limitations are observed by the DAQ at the times required or
determined by the source. There are no outstanding compliance issues concerning
applicable emission limits associated with Silver Eagle at this time. Specific emissions
related reports can be found in the source file.

3. §60.103a Design, equipment, work practice or operational standards.
(c) Except as provided in paragraphs (f) and (g) of this section, each owner or operator that operates a
fuel gas combustion device, flare or sulfur recovery plant subject to this subpart shall conduct a root
cause analysis and a corrective action analysis for each of the conditions specified in paragraphs
(c)(1) through (3) of this section.
(1) For a flare:
(i) Any time the SO2 emissions exceed 227 kilograms (kg) (500 lb) in any 24-hour period; or
(ii) Any discharge to the flare in excess of 14,160 standard cubic meters (m3) (500,000 standard cubic
feet (scf)) above the baseline, determined in paragraph (a)(4) of this section, in any 24-hour period; or
(iii) If the monitoring alternative in §60.107a(g) is elected, any period when the flare gas line pressure
exceeds the water seal liquid depth, except for periods attributable to compressor staging that do not
exceed the staging time specified in paragraph (a)(3)(vii)(C) of this section.
17
(2) For a fuel gas combustion device, each exceedance of an applicable short-term emissions limit in
§60.102a(g)(1) if the SO2 discharge to the atmosphere is 227 kg (500 lb) greater than the amount that
would have been emitted if the emissions limits had been met during one or more consecutive periods
of excess emissions or any 24-hour period, whichever is shorter.
(3) For a sulfur recovery plant, each time the SO2 emissions are more than 227 kg (500 lb) greater
than the amount that would have been emitted if the SO2 or reduced sulfur concentration was equal to
the applicable emissions limit in §60.102a(f)(1) or (2) during one or more consecutive periods of
excess emissions or any 24-hour period, whichever is shorter. ...

Status: In compliance. There were no obvious preventable exceedances, breakdowns, or operational
problems determined at this time. A flare management plan is in place.

4. §60.107a Monitoring of emissions and operations for fuel gas combustion devices and flares.
(a) Fuel gas combustion devices subject to SO2 or H2S limit and flares subject to H2S concentration
requirements. The owner or operator of a fuel gas combustion device that is subject to §60.102a(g)(1)
and elects to comply with the SO2emission limits in §60.102a(g)(1)(i) shall comply with the
requirements in paragraph (a)(1) of this section. The owner or operator of a fuel gas combustion
device that is subject to §60.102a(g)(1) and elects to comply with the H2S concentration limits in
§60.102a(g)(1)(ii) or a flare that is subject to the H2S concentration requirement in §60.103a(h) shall
comply with paragraph (a)(2) of this section. ...
(b) Exemption from H2S monitoring requirements for low-sulfur fuel gas streams. The owner or
operator of a fuel gas combustion device or flare may apply for an exemption from the H2S
monitoring requirements in paragraph (a)(2) of this section for a fuel gas stream that is inherently low
in sulfur content. A fuel gas stream that is demonstrated to be low-sulfur is exempt from the
monitoring requirements of paragraphs (a)(1) and (2) of this section until there are changes in
operating conditions or stream composition. ...
(e) Sulfur monitoring for assessing root cause analysis threshold for affected flares. Except as
described in paragraphs (e)(4) and (h) of this section, the owner or operator of an affected flare
subject to §60.103a(c) through (e) shall determine the total reduced sulfur concentration for each gas
line directed to the affected flare in accordance with either paragraph (e)(1), (e)(2) or (e)(3) of this
section. Different options may be elected for different gas lines. If a monitoring system is in place that
is capable of complying with the requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of
this section, the owner or operator of a modified flare must comply with the requirements related to
either paragraph (e)(1), (e)(2) or (e)(3) of this section upon startup of the modified flare. If a
monitoring system is not in place that is capable of complying with the requirements related to either
paragraph (e)(1), (e)(2) or (e)(3) of this section, the owner or operator of a modified flare must
comply with the requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section no later
than November 11, 2015 or upon startup of the modified flare, whichever is later. ...
(f) Flow monitoring for flares. Except as provided in paragraphs (f)(2) and (h) of this section, the
owner or operator of an affected flare subject to §60.103a(c) through (e) shall install, operate,
calibrate and maintain, in accordance with the specifications in paragraph (f)(1) of this section, a
CPMS to measure and record the flow rate of gas discharged to the flare. If a flow monitor is not
already in place, the owner or operator of a modified flare shall comply with the requirements of this
paragraph by no later than November 11, 2015 or upon startup of the modified flare, whichever is
later. ...
(g) Alternative monitoring for certain flares equipped with water seals. The owner or operator of an
affected flare subject to §60.103a(c) through (e) that can be classified as either an emergency flare, a
secondary flare or a flare equipped with a flare gas recovery system designed, sized and operated to
capture all flows except those resulting from startup, shutdown or malfunction may, as an alternative
to the sulfur and flow monitoring requirements of paragraphs (e) and (f) of this section, install,
operate, calibrate and maintain, in accordance with the requirements in paragraphs (g)(1) through (7)
of this section, a CPMS to measure and record the pressure in the flare gas header between the knock-
18
out pot and water seal and to measure and record the water seal liquid level. If the required
monitoring systems are not already in place, the owner or operator of a modified flare shall comply
with the requirements of this paragraph by no later than November 11, 2015 or upon startup of the
modified flare, whichever is later. ...
(i) Excess emissions. For the purpose of reports required by §60.7(c), periods of excess emissions for
fuel gas combustion devices subject to the emissions limitations in §60.102a(g) and flares subject to
the concentration requirement in §60.103a(h) are defined as specified in paragraphs (i)(1) through (5)
of this section. Determine a rolling 3-hour or a rolling daily average as the arithmetic average of the
applicable 1-hour averages (e.g., a rolling 3-hour average is the arithmetic average of three
contiguous 1-hour averages). Determine a rolling 30-day or a rolling 365-day average as the
arithmetic average of the applicable daily averages (e.g., a rolling 30-day average is the arithmetic
average of 30 contiguous daily averages). ...

Status: In compliance. Reports and calibrations are provided as required or requested. See site file
for documentation.

5. §60.108a Recordkeeping and reporting requirements.
(a) Each owner or operator subject to the emissions limitations in §60.102a shall comply with the
notification, recordkeeping, and reporting requirements in §60.7 and other requirements as specified
in this section.
(b) Each owner or operator subject to an emissions limitation in §60.102a shall notify the
Administrator of the specific monitoring provisions of §§60.105a, 60.106a and 60.107a with which
the owner or operator intends to comply. Each owner or operator of a co-fired process heater subject
to an emissions limitation in §60.102a(g)(2)(iii) or (iv) shall submit to the Administrator
documentation showing that the process heater meets the definition of a co-fired process heater in
§60.101a. Notifications required by this paragraph shall be submitted with the notification of initial
startup required by §60.7(a)(3).
(c) The owner or operator shall maintain the following records:
(1) A copy of the flare management plan.
(2) Records of information to document conformance with bag leak detection system operation and
maintenance requirements in §60.105a(c).
(3) Records of bag leak detection system alarms and actions according to §60.105a(c).
(4) For each fuel gas stream to which one of the exemptions listed in §60.107a(a)(3) applies, records
of the specific exemption determined to apply for each fuel stream. If the owner or operator applies
for the exemption described in §60.107a(a)(3)(iv), the owner or operator must keep a copy of the
application as well as the letter from the Administrator granting approval of the application.
(5) Records of discharges greater than 500 lb SO2 in any 24-hour period from any affected flare,
discharges greater than 500 lb SO2 in excess of the allowable limits from a fuel gas combustion
device or sulfur recovery plant and discharges to an affected flare in excess of 500,000 scf above
baseline in any 24-hour period as required by §60.103a(c). If the monitoring alternative provided in
§60.107a(g) is selected, the owner or operator shall record any instance when the flare gas line
pressure exceeds the water seal liquid depth, except for periods attributable to compressor staging that
do not exceed the staging time specified in §60.103a(a)(3)(vii)(C). The following information shall be
recorded no later than 45 days following the end of a discharge exceeding the thresholds:
(i) A description of the discharge.
(ii) The date and time the discharge was first identified and the duration of the discharge.
(iii) The measured or calculated cumulative quantity of gas discharged over the discharge duration. If
the discharge duration exceeds 24 hours, record the discharge quantity for each 24-hour period. For a
flare, record the measured or calculated cumulative quantity of gas discharged to the flare over the
discharge duration. If the discharge duration exceeds 24 hours, record the quantity of gas discharged
to the flare for each 24-hour period. Engineering calculations are allowed for fuel gas combustion
devices, but are not allowed for flares, except for those complying with the alternative monitoring
19
requirements in §60.107a(g).
(iv) For each discharge greater than 500 lb SO2 in any 24-hour period from a flare, the measured total
sulfur concentration or both the measured H2S concentration and the estimated total sulfur
concentration in the fuel gas at a representative location in the flare inlet.
(v) For each discharge greater than 500 lb SO2 in excess of the applicable short-term emissions limit
in §60.102a(g)(1) from a fuel gas combustion device, either the measured concentration of H2S in the
fuel gas or the measured concentration of SO2 in the stream discharged to the atmosphere. Process
knowledge can be used to make these estimates for fuel gas combustion devices, but cannot be used
to make these estimates for flares, except as provided in §60.107a(e)(4).
(vi) For each discharge greater than 500 lb SO2 in excess of the allowable limits from a sulfur
recovery plant, either the measured concentration of reduced sulfur or SO2 discharged to the
atmosphere.
(vii) For each discharge greater than 500 lb SO2 in any 24-hour period from any affected flare or
discharge greater than 500 lb SO2 in excess of the allowable limits from a fuel gas combustion device
or sulfur recovery plant, the cumulative quantity of H2S and SO2 released into the atmosphere. For
releases controlled by flares, assume 99-percent conversion of reduced sulfur or total sulfur to SO2.
For fuel gas combustion devices, assume 99-percent conversion of H2S to SO2.
(viii) The steps that the owner or operator took to limit the emissions during the discharge.
(ix) The root cause analysis and corrective action analysis conducted as required in §60.103a(d),
including an identification of the affected facility, the date and duration of the discharge, a statement
noting whether the discharge resulted from the same root cause(s) identified in a previous analysis
and either a description of the recommended corrective action(s) or an explanation of why corrective
action is not necessary under §60.103a(e).
(x) For any corrective action analysis for which corrective actions are required in §60.103a(e), a
description of the corrective action(s) completed within the first 45 days following the discharge and,
for action(s) not already completed, a schedule for implementation, including proposed
commencement and completion dates.
(xi) For each discharge from any affected flare that is the result of a planned startup or shutdown of a
refinery process unit or ancillary equipment connected to the affected flare, a statement that a root
cause analysis and corrective action analysis are not necessary because the owner or operator
followed the flare management plan.
(7) If the owner or operator elects to comply with §60.107a(e)(2) for a flare, records of the H2S and
total sulfur analyses of each grab or integrated sample, the calculated daily total sulfur-to-H2S ratios,
the calculated 10-day average total sulfur-to-H2S ratios and the 95-percent confidence intervals for
each 10-day average total sulfur-to-H2S ratio.
(d) Each owner or operator subject to this subpart shall submit an excess emissions report for all
periods of excess emissions according to the requirements of §60.7(c) except that the report shall
contain the information specified in paragraphs (d)(1) through (7) of this section.
(1) The date that the exceedance occurred;
(2) An explanation of the exceedance;
(3) Whether the exceedance was concurrent with a startup, shutdown, or malfunction of an affected
facility or control system; and
(4) A description of the action taken, if any.
(5) The information described in paragraph (c)(6) of this section for all discharges listed in paragraph
(c)(6) of this section. For a flare complying with the monitoring alternative under §60.107a(g),
following the fifth discharge required to be recorded under paragraph (c)(6) of this section and
reported under this paragraph, the owner or operator shall include notification that monitoring
systems will be installed according to §60.107a(e) and (f) within 180 days following the fifth
discharge.
(6) For any periods for which monitoring data are not available, any changes made in operation of the
emission control system during the period of data unavailability which could affect the ability of the
system to meet the applicable emission limit. Operations of the control system and affected facility
20
during periods of data unavailability are to be compared with operation of the control system and
affected facility before and following the period of data unavailability.
(7) A written statement, signed by a responsible official, certifying the accuracy and completeness of
the information contained in the report.

Status: In compliance. The H2S monitoring requirements that were granted to Silver Eagle by an
EPA exemption in 2017 changed the H2S discharge report limits from the 500 lbs listed
above to 100 lbs (see site file). All required reports are performed as required. A flare
management plan has been completed and is in place.

NSPS (Part 60), K: Standards of Performance for Storage Vessels for Petroleum Liquids for Which
Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May
19, 1978

§60.112 Standard for volatile organic compounds (VOC).
(a) The owner or operator of any storage vessel to which this subpart applies shall store
petroleum liquids as follows:
(1) If the true vapor pressure of the petroleum liquid, as stored, is equal to or greater than 78 mm
Hg (1.5 psia) but not greater than 570 mm Hg (11.1 psia), the storage vessel shall be equipped
with a floating roof, a vapor recovery system, or their equivalents. ...
Status: In compliance. Tanks 101, 102, 103, and 104 have all been subject to NSPS K and State
Rule R307-327 in the past. All of the tanks are being maintained and operated in a
manner exceeding minimum requirements. The tanks listed above have been equipped
with a fixed roof and an internal floating roof which rests directly upon the surface of
the liquid.
§ 60.113 Monitoring of operations.
(a) Except as provided in paragraph (d) of this section, the owner or operator subject to this
subpart shall maintain a record of the petroleum liquid stored, the period of storage, and the
maximum true vapor pressure of that liquid during the respective storage period. ...

Status: In compliance. The source has an onsite lab and a computerized system to track and record
throughput, the average monthly storage temperature, and the type of liquid. The
maximum true vapor pressure is monitored daily. Typical vapor pressure for naphthalene
is approximately 4 psia. Typical vapor pressures for diesel is 0.001 psia.

NSPS (Part 60), Ka: Standards of Performance for Storage Vessels for Petroleum Liquids for
Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior
to July 23, 1984

§ 60.112a Standard for volatile organic compounds (VOC).
(a) The owner or operator of each storage vessel to which this subpart applies which contains a
petroleum liquid which, as stored, has a true vapor pressure equal to or greater than 10.3 kPa (1.5
psia) but not greater than 76.6 kPa (11.1 psia) shall equip the storage vessel with one of the
following: ...
(2) A fixed roof with an internal floating type cover equipped with a continuous closure device
between the tank wall and the cover edge. The cover is to be floating at all times, (i.e., off the leg
supports) except during initial fill and when the tank is completely emptied and subsequently
refilled. The process of emptying and refilling when the cover is resting on the leg supports shall
be continuous and shall be accomplished as rapidly as possible. Each opening in the cover except
for automatic bleeder vents and the rim space vents is to provide a projection below the liquid
21
surface. Each opening in the cover except for automatic bleeder vents, rim space vents, stub
drains and leg sleeves is to be equipped with a cover, seal, or lid which is to be maintained in a
closed position at all times (i.e., no visible gap) except when the device is in actual use.
Automatic bleeder vents are to be closed at all times when the cover is floating except when the
cover is being floated off or is being landed on the leg supports. Rim vents are to be set to open
only when the cover is being floated off the leg supports or at the manufacturer's recommended
setting. ...

Status: In compliance. Tanks 18, 19, 23, 105, and 106 are subject to NSPS Ka. These tanks all
have a fixed roof with an internal floating type cover equipped with a continuous
closure device between the tank wall and the cover edge. All projections through the
floating cover are properly equipped with seals as required.

§ 60.115a Monitoring of operations.
(a) Except as provided in paragraph (d) of this section, the owner or operator subject to this
subpart shall maintain a record of the petroleum liquid stored, the period of storage, and the
maximum true vapor pressure of that liquid during the respective storage period. ...

Status: In compliance. The company has an onsite lab and a computerized system to track and
record throughput, the average monthly storage temperature, and the type of liquid.
The maximum true vapor pressure is monitored instantaneously and continually with a
daily printout.

NSPS (Part 60), 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

§ 60.112b Standard for volatile organic compounds (VOC).
(a) The owner or operator of each storage vessel either with a design capacity greater than or
equal to 151 m3 containing a VOL that, as stored, has a maximum true vapor pressure equal to or
greater than 5.2 kPa but less than 76.6 kPa or with a design capacity greater than or equal to 75
m3 but less than 151 m3 containing a VOL that, as stored, has a maximum true vapor pressure
equal to or greater than 27.6 kPa but less than 76.6 kPa, shall equip each storage vessel with one
of the following:
(1) A fixed roof in combination with an internal floating roof meeting the following
specifications:
(i) The internal floating roof shall rest or float on the liquid surface (but not necessarily in
complete contact with it) inside a storage vessel that has a fixed roof. The internal floating roof
shall be floating on the liquid surface at all times, except during initial fill and during those
intervals when the storage vessel is completely emptied or subsequently emptied and refilled.
When the roof is resting on the leg supports, the process of filling, emptying, or refilling shall be
continuous and shall be accomplished as rapidly as possible.
(ii) Each internal floating roof shall be equipped with one of the following closure devices
between the wall of the storage vessel and the edge of the internal floating roof:
(A) A foam- or liquid-filled seal mounted in contact with the liquid (liquid-mounted seal). A
liquid-mounted seal means a foam- or liquid-filled seal mounted in contact with the liquid
between the wall of the storage vessel and the floating roof continuously around the
circumference of the tank.
(B) Two seals mounted one above the other so that each forms a continuous closure that
completely covers the space between the wall of the storage vessel and the edge of the internal
floating roof. The lower seal may be vapor-mounted, but both must be continuous.

22
(C) A mechanical shoe seal. A mechanical shoe seal is a metal sheet held vertically against the
wall of the storage vessel by springs or weighted levers and is connected by braces to the floating
roof. A flexible coated fabric (envelope) spans the annular space between the metal sheet and the
floating roof.
(iii) Each opening in a noncontact internal floating roof except for automatic bleeder vents
(vacuum breaker vents) and the rim space vents is to provide a projection below the liquid
surface.
(iv) Each opening in the internal floating roof except for leg sleeves, automatic bleeder vents,
rim space vents, column wells, ladder wells, sample wells, and stub drains is to be equipped with
a cover or lid which is to be maintained in a closed position at all times (i.e., no visible gap)
except when the device is in actual use. The cover or lid shall be equipped with a gasket. Covers
on each access hatch and automatic gauge float well shall be bolted except when they are in use.
(v) Automatic bleeder vents shall be equipped with a gasket and are to be closed at all times
when the roof is floating except when the roof is being floated off or is being landed on the roof
leg supports.
(vi) Rim space vents shall be equipped with a gasket and are to be set to open only when the
internal floating roof is not floating or at the manufacturer's recommended setting.
(vii) Each penetration of the internal floating roof for the purpose of sampling shall be a sample
well. The sample well shall have a slit fabric cover that covers at least 90 percent of the opening.
(viii) Each penetration of the internal floating roof that allows for passage of a column
supporting the fixed roof shall have a flexible fabric sleeve seal or a gasketed sliding cover.
(ix) Each penetration of the internal floating roof that allows for passage of a ladder shall have a
gasketed sliding cover. ...

Status: In compliance. Tanks 1, 2, 24, 26, 27, 28, 47, and 48 are subject to NSPS Kb. Each tank
subject to NSPS Subpart Kb is equipped with an internal floating roof inside a fixed roof.
All floating roofs rest on top of the liquid surface at all times except during emptying and
refill, and are fitted with a liquid mounted seal. Covers or lids are sealed by gasket and kept
closed at all times except when in use. All penetrations through the floating roof are
equipped with gaskets. Company records show which tanks are in the required service and
applicability of rules based on size, date, product, and use. Additional inspection, reporting,
and monitoring requirements listed in Subpart Kb are not included in this report because
they are not applicable at this time due to the minimum vapor pressure requirements.

§ 60.113b Testing and procedures.
The owner or operator of each storage vessel as specified in §60.112b(a) shall meet the
requirements of paragraph (a), (b), or (c) of this section. The applicable paragraph for a
particular storage vessel depends on the control equipment installed to meet the requirements of
§60.112b.
(a) After installing the control equipment required to meet §60.112b(a)(1) (permanently affixed
roof and internal floating roof), each owner or operator shall:
(1) Visually inspect the internal floating roof, the primary seal, and the secondary seal (if one is
in service), prior to filling the storage vessel with VOL. If there are holes, tears, or other
openings in the primary seal, the secondary seal, or the seal fabric or defects in the internal
floating roof, or both, the owner or operator shall repair the items before filling the storage
vessel.
(2) For Vessels equipped with a liquid-mounted or mechanical shoe primary seal, visually
inspect the internal floating roof and the primary seal or the secondary seal (if one is in service)
through manholes and roof hatches on the fixed roof at least once every 12 months after initial
fill. If the internal floating roof is not resting on the surface of the VOL inside the storage vessel,
or there is liquid accumulated on the roof, or the seal is detached, or there are holes or tears in
the seal fabric, the owner or operator shall repair the items or empty and remove the storage
23
vessel from service within 45 days. If a failure that is detected during inspections required in this
paragraph cannot be repaired within 45 days and if the vessel cannot be emptied within 45 days,
a 30-day extension may be requested from the Administrator in the inspection report required in
§60.115b(a)(3). Such a request for an extension must document that alternate storage capacity is
unavailable and specify a schedule of actions the company will take that will assure that the
control equipment will be repaired or the vessel will be emptied as soon as possible.
(3) For vessels equipped with a double-seal system as specified in §60.112b(a)(1)(ii)(B):
(i) Visually inspect the vessel as specified in paragraph (a)(4) of this section at least every 5
years; or
(ii) Visually inspect the vessel as specified in paragraph (a)(2) of this section.
(4) Visually inspect the internal floating roof, the primary seal, the secondary seal (if one is in
service), gaskets, slotted membranes and sleeve seals (if any) each time the storage vessel is
emptied and degassed. If the internal floating roof has defects, the primary seal has holes, tears,
or other openings in the seal or the seal fabric, or the secondary seal has holes, tears, or other
openings in the seal or the seal fabric, or the gaskets no longer close off the liquid surfaces from
the atmosphere, or the slotted membrane has more than 10 percent open area, the owner or
operator shall repair the items as necessary so that none of the conditions specified in this
paragraph exist before refilling the storage vessel with VOL. In no event shall inspections
conducted in accordance with this provision occur at intervals greater than 10 years in the case of
vessels conducting the annual visual inspection as specified in paragraphs (a)(2) and (a)(3)(ii) of
this section and at intervals no greater than 5 years in the case of vessels specified in paragraph
(a)(3)(i) of this section.
(5) Notify the Administrator in writing at least 30 days prior to the filling or refilling of each
storage vessel for which an inspection is required by paragraphs (a)(1) and (a)(4) of this section
to afford the Administrator the opportunity to have an observer present. If the inspection required
by paragraph (a)(4) of this section is not planned and the owner or operator could not have
known about the inspection 30 days in advance or refilling the tank, the owner or operator shall
notify the Administrator at least 7 days prior to the refilling of the storage vessel. Notification
shall be made by telephone immediately followed by written documentation demonstrating why
the inspection was unplanned. Alternatively, this notification including the written
documentation may be made in writing and sent by express mail so that it is received by the
Administrator at least 7 days prior to the refilling.

Status: In compliance. Each seal is inspected upon the initial fill, when drained and refilled.
The source has notified DAQ at least 7 days or greater prior to filling or refilling each
storage vessel. See copies of notifications in the source file. Additionally, the covers are
visually inspected twice a year from the top hatch.

NSPS (Part 60), GGG: Standards of Performance for Equipment Leaks of VOC in Petroleum
Refineries for which Construction, Reconstruction, or Modification Commenced After January 4,
1983, and on or Before November 7, 2006

Status: This subpart is addressed as Subpart GGGa as required through the SIP.

40 CFR Part 60, Subpart GGGa - Standards of Performance for Equipment Leaks of VOC in
Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After
November 7, 2006

§60.590a Applicability and designation of affected facility. ...

Status: In compliance. The source is subject to Subpart GGGa (40 CFR 60.590a to 60.593) due
to the requirements of the December 7, 2016, SIP.
24
§60.592a Standards.
(a) Each owner or operator subject to the provisions of this subpart shall comply with the
requirements of §§ 60.482-1a to 60.482-10a as soon as practicable, but no later than 180 days
after initial startup.
(b) For a given process unit, an owner or operator may elect to comply with the requirements of
paragraphs (b)(1), (2), or (3) of this section as an alternative to the requirements in § 60.482-7a.
(1) Comply with § 60.483-1a.
(2) Comply with § 60.483-2a.
(3) Comply with the Phase III provisions in § 63.168, except an owner or operator may elect to
follow the provisions in § 60.482-7a(f) instead of § 63.168 for any valve that is designated as
being leakless.
(c) An owner or operator may apply to the Administrator for a determination of equivalency for
any means of emission limitation that achieves a reduction in emissions of VOC at least
equivalent to the reduction in emissions of VOC achieved by the controls required in this
subpart. In doing so, the owner or operator shall comply with requirements of § 60.484a.
(d) Each owner or operator subject to the provisions of this subpart shall comply with the
provisions of § 60.485a except as provided in § 60.593a.
(e) Each owner or operator subject to the provisions of this subpart shall comply with the
provisions of §§ 60.486a and 60.487a.

Status: In Compliance. Silver Eagle complies with the requirements of 40 CFR 60, Subpart
VVa (60.482a-1 to 60.482a-10, 60.485a to 60.487a) as specified in §60.592a above. See
specific status information under Subpart VVa.

§60.593a Exceptions.
(a) Each owner or operator subject to the provisions of this subpart may comply with the
following exceptions to the provisions of subpart VVa of this part.
(b)(1) Compressors in hydrogen service are exempt from the requirements of § 60.592a if an
owner or operator demonstrates that a compressor is in hydrogen service.
(2) Each compressor is presumed not to be in hydrogen service unless an owner or operator
demonstrates that the piece of equipment is in hydrogen service. For a piece of equipment to be
considered in hydrogen service, it must be determined that the percent hydrogen content can be
reasonably expected always to exceed 50 percent by volume. ...
(g) Connectors in gas/vapor or light liquid service are exempt from the requirements in § 60.482-
11a, provided the owner or operator complies with § 60.482-8a for all connectors, not just those
in heavy liquid service.

Status: Not applicable. Silver Eagle complies with the applicable sections under NSPS VVa. Silver
Eagle has two hydrogen compressors that are exempt per §60.593a(b)(1)(2) due to hydrogen
content percentage (approx. 90%). Hydrogen percentage is determined by in house testing
using “engineering judgement.”

Subpart VVa—Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic
Chemicals Manufacturing Industry for which Construction, Reconstruction, or Modification
Commenced After November 7, 2006

Status: In compliance. The source is subject to the standards of this subpart because it is referenced
in Subpart GGGa. No equivalence per (c)(1) above has been requested or approved.

25
§60.482-2a Standards: Pumps in light liquid service.
(a)(1) Each pump in light liquid service shall be monitored monthly to detect leaks by the methods
specified in §60.485(b), except as provided in §60.482-1(c) and (f) and paragraphs (d), (e), and (f) of
this section. 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 §60.482-1(c) and (f) and
paragraphs (d), (e), and (f) of this section.
(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, except as provided in §60.482-1(f).
(b)(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, the owner or operator shall follow
the procedure specified in either paragraph (b)(2)(i) or (ii) of this section. This requirement does not
apply to a pump that was monitored after a previous weekly inspection if the instrument reading for
that monitoring event was less than 10,000 ppm and the pump was not repaired since that monitoring
event.
(i) Monitor the pump within 5 days as specified in §60.485(b). If an instrument reading of 10,000
ppm or greater is measured, a leak is detected. The leak shall be repaired using the procedures in
paragraph (c) of this section.
(ii) Designate the visual indications of liquids dripping as a leak, and repair the leak within 15 days of
detection by eliminating the visual indications of liquids dripping.
(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 §60.482-9.
(2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.
First attempts at repair include, but are not limited to, the practices described in paragraphs (c)(2)(i)
and (ii) of this section, where practicable.
(i) Tightening the packing gland nuts;
(ii) Ensuring that the seal flush is operating at design pressure and temperature.
(d) Each pump equipped with a dual mechanical seal system that includes a barrier fluid system is
exempt from the requirements of paragraph (a) of this section, provided the requirements specified in
paragraphs (d)(1) through (6) of this section 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
§60.482-10; 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)(i) Each pump is checked by visual inspection, each calendar week, for indications of liquids
dripping from the pump seals.
(ii) If there are indications of liquids dripping from the pump seal at the time of the weekly
inspection, the owner or operator shall follow the procedure specified in either paragraph (d)(4)(ii)(A)
or (B) of this section.
(A) Monitor the pump within 5 days as specified in §60.485(b) to determine if there is a leak of VOC
in the barrier fluid. If an instrument reading of 10,000 ppm or greater is measured, a leak is detected.
(B) Designate the visual indications of liquids dripping as a leak.
(5)(i) Each sensor as described in paragraph (d)(3) of this section is checked daily or is equipped with
an audible alarm.

26
(ii) The owner or operator determines, based on design considerations and operating experience, a
criterion that indicates failure of the seal system, the barrier fluid system, or both.
(iii) If the sensor indicates failure of the seal system, the barrier fluid system, or both, based on the
criterion established in paragraph (d)(5)(ii) of this section, a leak is detected.
(6)(i) When a leak is detected pursuant to paragraph (d)(4)(ii)(A) of this section, it shall be repaired as
specified in paragraph (c) of this section.
(ii) A leak detected pursuant to paragraph (d)(5)(iii) of this section shall be repaired within 15 days of
detection by eliminating the conditions that activated the sensor.
(iii) A designated leak pursuant to paragraph (d)(4)(ii)(B) of this section shall be repaired within 15
days of detection by eliminating visual indications of liquids dripping.
(e) Any pump that is designated, as described in §60.486(e)(1) and (2), 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), (c), and (d) of 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 in §60.485(c),
and
(3) Is tested for compliance with paragraph (e)(2) of this section initially upon designation, annually,
and at other times requested by the Administrator.
(f) 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 §60.482-10, it is exempt from paragraphs (a) through (e) of this section.
(g) Any pump that is designated, as described in §60.486(f)(1), as an unsafe-to-monitor pump is
exempt from the monitoring and inspection requirements of paragraphs (a) and (d)(4) through (6) of
this section if:
(1) The owner or operator 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 with
paragraph (a) of this section; and
(2) The owner or operator 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 (c) of this section if a leak is detected.
(h) Any pump that is located within the boundary of an unmanned plant site is exempt from the
weekly visual inspection requirement of paragraphs (a)(2) and (d)(4) of this section, and the daily
requirements of paragraph (d)(5) of this section, provided that each pump is visually inspected as
often as practicable and at least monthly.

Status: In compliance. Based on monitoring, NSPS VVa applies to several pumps. Those in service
are visually inspected weekly and monitored monthly. A first attempt at repair is made
within five days of discovery and all repairs are completed within fifteen days if possible.
Repairs not made within 15 days are properly tagged for delay of repair which normally
occurs at unit turnaround and reported as required. Silver Eagle has procedures in place to
ensure the rules are followed and procedures are consistent. NSPS applicable pumps are
included in quarterly LDAR reports. Silver Eagle has installed several “mag-drive” pumps
that do not have seals and are exempt from this requirement.

27
§60.482-3a Standards: Compressors.
(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 § 60.482-1a(c) and paragraphs (h),
(i), and (j) of this section. ...

Status: Not applicable at this time. There are two compressors exempted (noted previously in
Subpart GGGa evaluations - in hydrogen service).

§60.482-4a Standards: Pressure relief devices in gas/vapor service.
(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 § 60.485a(c).
(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 § 60.482-9a.
(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 specified in § 60.485a(c).
(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 § 60.482-10a 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 owner
or operator 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 § 60.482-9a.

Status: In compliance. The only pressure relief valve (PRV) open to the atmosphere is on the crude
tower, PRV-16903. It is subject to NSPS. This valve has not released in the past two years. It
is monitored on a quarterly basis for leaks.

§60.482-5a Standards: Sampling connection systems.
(a) Each sampling connection system shall be equipped with a closed-purge, closed-loop, or closed-
vent system, except as provided in § 60.482-1a(c) and paragraph (c) of this section.
(b) Each closed-purge, closed-loop, or closed-vent system as required in paragraph (a) of this section
shall comply with the requirements specified in paragraphs (b)(1) through (4) of this section.
(1) Gases displaced during filling of the sample container are not required to be collected or captured.
(2) Containers that are part of a closed-purge system must be covered or closed when not being filled
or emptied.
(3) Gases remaining in the tubing or piping between the closed-purge system valve(s) and sample
container valve(s) after the valves are closed and the sample container is disconnected are not
required to be collected or captured.
(4) Each closed-purge, closed-loop, or closed-vent system shall be designed and operated to meet
requirements in either paragraph (b)(4)(i), (ii), (iii), or (iv) of this section.
(i) Return the purged process fluid directly to the process line.
(ii) Collect and recycle the purged process fluid to a process.
(iii) Capture and transport all the purged process fluid to a control device that complies with the
requirements of § 60.482-10a.
(iv) Collect, store, and transport the purged process fluid to any of the following systems or facilities:
28
(A) A waste management unit as defined in 40 CFR 63.111, if the waste management unit is subject
to and operated in compliance with the provisions of 40 CFR part 63, subpart G, applicable to Group
1 wastewater streams;
(B) A treatment, storage, or disposal facility subject to regulation under 40 CFR part 262, 264, 265, or
266;
(C) A facility permitted, licensed, or registered by a state to manage municipal or industrial solid
waste, if the process fluids are not hazardous waste as defined in 40 CFR part 261;
(D) A waste management unit subject to and operated in compliance with the treatment requirements
of 40 CFR 61.348(a), provided all waste management units that collect, store, or transport the purged
process fluid to the treatment unit are subject to and operated in compliance with the management
requirements of 40 CFR 61.343 through 40 CFR 61.347; or
(E) A device used to burn off-specification used oil for energy recovery in accordance with 40 CFR
part 279, subpart G, provided the purged process fluid is not hazardous waste as defined in 40 CFR
part 261.
(c) In-situ sampling systems and sampling systems without purges are exempt from the requirements
of paragraphs (a) and (b) of this section.

Status: In compliance. Silver Eagle has several sampling stations that are subject to this
requirement and are closed-loop design. Inspection of units confirms status.

§60.482-6a Standards: Open-ended valves or lines.
(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 § 60.482-1a(c) and paragraphs (d) and (e) of this section.
(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.
(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.

Status: In compliance. All open-ended valves have end plugs or a second valve. Inspections are
done through LDAR and plant inspections as described in the sections above.

§60.482-7a Standards: Valves in gas/vapor service and in light liquid service.
(a)(1) Each valve shall be monitored monthly to detect leaks by the methods specified in § 60.485a(b)
and shall comply with paragraphs (b) through (e) of this section, except as provided in paragraphs (f),
(g), and (h) of this section, § 60.482-1a(c) and (f), and §§ 60.483-1a and 60.483-2a.
(2) 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)(2)(i) or (ii), except for a valve
that replaces a leaking valve and except as provided in paragraphs (f), (g), and (h) of this section, §
60.482-1a(c), and §§ 60.483-1a and 60.483-2a.
(i) 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.

29
(ii) If the existing valves in the process unit are monitored in accordance with § 60.483-1a or §
60.483-2a, count the new valve as leaking when calculating the percentage of valves leaking as
described in § 60.483-2a(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) If an instrument reading of 500 ppm or greater is measured, a leak is detected.
(c) (1) (i) 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.
(ii) As an alternative to monitoring all of the valves in the first month of a quarter, an owner or
operator may elect to subdivide the process unit into two or three subgroups of valves and monitor
each subgroup in a different month during the quarter, provided each subgroup is monitored every 3
months. The owner or operator must keep records of the valves assigned to each subgroup.
(2) If a leak is detected, the valve shall be monitored monthly until a leak is not detected for 2
successive months.
(d) (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 § 60.482-9a.
(2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.
(e) 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.
(f) Any valve that is designated, as described in § 60.486a(e)(2), for no detectable emissions, as
indicated by an instrument reading of less than 500 ppm above background, is exempt from the
requirements of paragraph (a) of this section 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 § 60.485a(c), and
(3) Is tested for compliance with paragraph (f)(2) of this section initially upon designation, annually,
and at other times requested by the Administrator.
(g) Any valve that is designated, as described in § 60.486a(f)(1), as an unsafe-to-monitor valve is
exempt from the requirements of paragraph (a) of this section if:
(1) The owner or operator 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
paragraph (a) of this section, and
(2) The owner or operator of the valve adheres to a written plan that requires monitoring of the valve
as frequently as practicable during safe-to-monitor times.
(h) Any valve that is designated, as described in § 60.486a(f)(2), as a difficult-to-monitor valve is
exempt from the requirements of paragraph (a) of this section if:
(1) The owner or operator 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:
(i) Becomes an affected facility through § 60.14 or § 60.15 and was constructed on or before January
5, 1981; or

30
(ii) Has less than 3.0 percent of its total number of valves designated as difficult-to-monitor by the
owner or operator.
(3) The owner or operator of the valve follows a written plan that requires monitoring of the valve at
least once per calendar year.

Status: In compliance. All valves (except unsafe to monitor valves) are monitored quarterly and
switched to monthly monitoring when a leak is detected. Leak detection dates are entered
into an electronic database to help ensure each valve is being monitored either monthly or
quarterly. The first attempt at repair is made during monitoring. Valves not repaired are
placed on work orders and repair is made within 15 days unless a turnaround is required.
The unsafe to monitor valves are all recorded and monitored once per year and reported to
the DAQ as required. The reporting ensures that the percentage of unsafe to monitor valves
monitored is not exceeded per (h)(2) above. Inspections were done as described in the
sections above.

§60.482-8a Standards: Pumps and valves in heavy liquid service, pressure relief devices in light
liquid or heavy liquid service, and connectors.
(a) If evidence of a potential leak is found by visual, audible, olfactory, or any other detection method
at pumps, valves, and connectors in heavy liquid service and pressure relief devices in light liquid or
heavy liquid service, the owner or operator shall follow either one of the following procedures:
(1) The owner or operator shall monitor the equipment within 5 days by the method specified in §
60.485a(b) and shall comply with the requirements of paragraphs (b) through (d) of this section.
(2) The owner or operator shall eliminate the visual, audible, olfactory, or other indication of a
potential leak within 5 calendar days of detection.
(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 § 60.482-9a.
(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 under §§
60.482-2a(c)(2) and 60.482-7a(e).

Status: In compliance. First attempt at repair is made within five days. Those unable to be repaired
within five days are repaired no later than fifteen days or during process turnaround if
necessary. Inspections are done as described in the section above.

§60.482-9a Standards: 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. Monitoring to verify repair must occur within
15 days after startup of the process unit.
(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.
(c) Delay of repair for valves and connectors will be allowed if:
(1) The owner or operator 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 affected, the purged material is collected and destroyed or recovered
in a control device complying with § 60.482-10a.
(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.

31
(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, valve, or connector that remains in service,
the pump, valve, or connector may be considered repaired and no longer subject to delay of
repair requirements if two consecutive monthly monitoring instrument readings are below the leak
definition.

Status: In compliance. Delay of repair records are reported with quarterly LDAR submissions to
DAQ. Some repairs have been delayed because of leaking equipment repairs that cannot be
safely isolated without a process unit shutdown and because purged material resulting from
immediate repair are greater than the fugitive emissions likely to result from a delay of the
repair. Inspections were done as described in the section above.

§60.482-10a Standards: Closed vent systems and control devices.

Status: Not applicable at this time. Silver Eagle does not have a closed vent system.

§60.483-1a Alternative standards for valves—allowable percentage of valves leaking.

Status: Not applicable at this time. The facility is not following this alternative standard.

§60.483-2a Alternative standards for valves—skip period leak detection and repair.
(a) (1) An owner or operator may elect to comply with one of the alternative work practices specified
in paragraphs (b)(2) and (3) of this section.
(2) An owner or operator must notify the Administrator before implementing one of the alternative
work practices, as specified in § 60.487(d)a.
(b) (1) An owner or operator shall comply initially with the requirements for valves in gas/vapor
service and valves in light liquid service, as described in § 60.482-7a.
(2) After 2 consecutive quarterly leak detection periods with the percent of valves leaking equal to or
less than 2.0, an owner or operator 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, an owner or operator 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 owner or operator shall comply with the
requirements as described in § 60.482-7a but can again elect to use this section.
(5) The percent of valves leaking shall be determined as described in § 60.485a(h).
(6) An owner or operator 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 § 60.482-7a(a)(2)(i) or (ii) before the provisions of this section can be applied to that
valve.

Status: In compliance. Silver Eagle refining does use alternative standards for valves-skip period
leak detection and repair.

32
§60.484a Equivalence of means of emission limitation. ...

Status: Not applicable. No equivalent means of emission testing has been requested or approved.

§60.485a Test methods and procedures.
(a) In conducting the performance tests required in § 60.8, the owner or operator shall use as
reference methods and procedures the test methods in appendix A of this part or other methods and
procedures as specified in this section, except as provided in § 60.8(b).
(b) The owner or operator shall determine compliance with the standards in §§ 60.482-1a through
60.482-11a, 60.483a, and 60.484a 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 of appendix A-7 of
this part. The following calibration gases shall be used:
(i) Zero air (less than 10 ppm of hydrocarbon in air); and
(ii) A mixture of methane or n-hexane and air at a concentration no more than 2,000 ppm greater than
the leak definition concentration of the equipment monitored. If the monitoring instrument's design
allows for multiple calibration scales, then the lower scale shall be calibrated with a calibration gas
that is no higher than 2,000 ppm above the concentration specified as a leak, and the highest scale
shall be calibrated with a calibration gas that is approximately equal to 10,000 ppm. If only one scale
on an instrument will be used during monitoring, the owner or operator need not calibrate the scales
that will not be used during that day's monitoring.
(2) A calibration drift assessment shall be performed, at a minimum, at the end of each monitoring
day. ...

Status: In compliance. All testing is done in accordance with Method 21 by a contractor and
reports are submitted to the DAQ for review.

§60.486a Recordkeeping requirements.
(a)(1) Each owner or operator subject to the provisions of this subpart shall comply with the
recordkeeping requirements of this section.
(2) An owner or operator 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.
(3) The owner or operator shall record the information specified in paragraphs (a)(3)(i) through (v) of
this section for each monitoring event required by §§ 60.482-2a, 60.482-3a, 60.482-7a, 60.482-8a,
60.482-11a, and 60.483-2a.
(i) Monitoring instrument identification.
(ii) Operator identification.
(iii) Equipment identification.
(iv) Date of monitoring.
(v) Instrument reading.
(b) When each leak is detected as specified in §§ 60.482-2a, 60.482-3a, 60.482-7a, 60.482-8a,
60.482-11a, and 60.483-2a, 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 § 60.482-7a(c) and no leak has been detected during those 2 months.
(3) The identification on a connector may be removed after it has been monitored as specified in §
60.482-11a(b)(3)(iv) and no leak has been detected during that monitoring.
(4) The identification on equipment, except on a valve or connector, may be removed after it has been
repaired.

33
(c) When each leak is detected as specified in §§ 60.482-2a, 60.482-3a, 60.482-7a, 60.482-8a, 60.482-
11a, and 60.483-2a, 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,
except when indications of liquids dripping from a pump are designated as a leak.
(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) Maximum instrument reading measured by Method 21 of appendix A-7 of this part at the time the
leak is successfully repaired or determined to be nonrepairable, except when a pump is repaired by
eliminating indications of liquids dripping.
(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 owner or operator (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.
(9) The date of successful repair of the leak. ...
(e) The following information pertaining to all equipment subject to the requirements in §§ 60.482-1a
to 60.482-11a 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 provisions of §§ 60.482-2a(e), 60.482-3a(i), and 60.482-7a(f).
(ii) The designation of equipment as subject to the requirements of § 60.482-2a(e), § 60.482-3a(i), or
§ 60.482-7a(f) shall be signed by the owner or operator. Alternatively, the owner or operator may
establish a mechanism with their permitting authority that satisfies this requirement.
(3) A list of equipment identification numbers for pressure relief devices required to comply with §
60.482-4a.
(4) (i) The dates of each compliance test as required in §§ 60.482-2a(e), 60.482-3a(i), 60.482-4a, and
60.482-7a(f).
(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 owner or operator designates as operating
in VOC service less than 300 hr/yr in accordance with § 60.482-1a(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.
(7) The date and results of the weekly visual inspection for indications of liquids dripping from
pumps in light liquid service.
(8) Records of the information specified in paragraphs (e)(8)(i) through (vi) of this section for
monitoring instrument calibrations conducted according to sections 8.1.2 and 10 of Method 21 of
appendix A-7 of this part and § 60.485a(b).
(i) Date of calibration and initials of operator performing the calibration.
(ii) Calibration gas cylinder identification, certification date, and certified concentration.
(iii) Instrument scale(s) used.
(iv) A description of any corrective action taken if the meter readout could not be adjusted to
correspond to the calibration gas value in accordance with section 10.1 of Method 21 of appendix A-7
of this part.
(v) Results of each calibration drift assessment required by § 60.485a(b)(2) (i.e., instrument reading
for calibration at end of monitoring day and the calculated percent difference from the initial
calibration value).
(vi) If an owner or operator makes their own calibration gas, a description of the procedure used.
(9) The connector monitoring schedule for each process unit as specified in § 60.482-11a(b)(3)(v).
34
(10) Records of each release from a pressure relief device subject to § 60.482-4a.
(f) The following information pertaining to all valves subject to the requirements of § 60.482-7a(g)
and (h), all pumps subject to the requirements of § 60.482-2a(g), and all connectors subject to the
requirements of § 60.482-11a(e) shall be recorded in a log that is kept in a readily accessible location:
(1) A list of identification numbers for valves, pumps, and connectors that are designated as unsafe-
to-monitor, an explanation for each valve, pump, or connector stating why the valve, pump, or
connector is unsafe-to-monitor, and the plan for monitoring each valve, pump, or connector.
(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 valve.
(g) The following information shall be recorded for valves complying with § 60.483-2a:
(1) A schedule of monitoring.
(2) The percent of valves found leaking during each monitoring period.
(h) The following information shall be recorded in a log that is kept in a readily accessible location:
(1) Design criterion required in §§ 60.482-2a(d)(5) and 60.482-3a(e)(2) and explanation of the design
criterion; and
(2) Any changes to this criterion and the reasons for the changes.
(i) The following information shall be recorded in a log that is kept in a readily accessible location for
use in determining exemptions as provided in § 60.480a(d):
(1) An analysis demonstrating the design capacity of the affected facility,
(2) A statement listing the feed or raw materials and products from the affected facilities and an
analysis demonstrating whether these chemicals are heavy liquids or beverage alcohol, and
(3) An analysis demonstrating that equipment is not in VOC service.
(j) 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.
(k) The provisions of § 60.7(b) and (d) do not apply to affected facilities subject to this subpart.

Status: In compliance. Leak documentation appeared to be done in accordance with the
requirements in this section. All valves (except unsafe to monitor valves) are monitored
quarterly and switched to monthly monitoring when a leak is detected. Leak detection dates
are entered into an electronic database to help ensure each valve is being properly
monitored either monthly or quarterly.

§60.487a Reporting requirements.
(a) Each owner or operator subject to the provisions of this subpart shall submit semiannual reports to
the Administrator beginning 6 months after the initial startup date.
(b) The initial semiannual report to the Administrator shall include the following information:
(1) Process unit identification.
(2) Number of valves subject to the requirements of § 60.482-7a, excluding those valves designated
for no detectable emissions under the provisions of § 60.482-7a(f).
(3) Number of pumps subject to the requirements of § 60.482-2a, excluding those pumps designated
for no detectable emissions under the provisions of § 60.482-2a(e) and those pumps complying with §
60.482-2a(f).
(4) Number of compressors subject to the requirements of § 60.482-3a, excluding those compressors
designated for no detectable emissions under the provisions of § 60.482-3a(i) and those compressors
complying with § 60.482-3a(h).
(5) Number of connectors subject to the requirements of § 60.482-11a.
(c) All semiannual reports to the Administrator shall include the following information, summarized
from the information in § 60.486a:
(1) Process unit identification.
(2) For each month during the semiannual reporting period,
(i) Number of valves for which leaks were detected as described in § 60.482-7a(b) or § 60.483-2a,
35
(ii) Number of valves for which leaks were not repaired as required in § 60.482-7a(d)(1),
(iii) Number of pumps for which leaks were detected as described in § 60.482-2a(b), (d)(4)(ii)(A) or
(B), or (d)(5)(iii),
(iv) Number of pumps for which leaks were not repaired as required in § 60.482-2a(c)(1) and (d)(6),
(v) Number of compressors for which leaks were detected as described in § 60.482-3a(f),
(vi) Number of compressors for which leaks were not repaired as required in § 60.482-3a(g)(1),
(vii) Number of connectors for which leaks were detected as described in § 60.482-11a(b)
(viii) Number of connectors for which leaks were not repaired as required in § 60.482-11a(d), and
(ix)-(x) [Reserved]
(xi) 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) An owner or operator electing to comply with the provisions of §§ 60.483-1a or 60.483-2a shall
notify the Administrator of the alternative standard selected 90 days before implementing either of the
provisions.
(e) An owner or operator shall report the results of all performance tests in accordance with § 60.8 of
the General Provisions. The provisions of § 60.8(d) do not apply to affected facilities subject to the
provisions of this subpart except that an owner or operator must notify the Administrator of the
schedule for the initial performance tests at least 30 days before the initial performance tests.
(f) The requirements of paragraphs (a) through (c) of this section remain in force until and unless
EPA, in delegating enforcement authority to a state under section 111(c) of the CAA, approves
reporting requirements or an alternative means of compliance surveillance adopted by such state. In
that event, affected sources within the state will be relieved of the obligation to comply with the
requirements of paragraphs (a) through (c) of this section, provided that they comply with the
requirements established by the state.

Status: In compliance. Required LDAR semi-annual and quarterly reports are submitted together
per State Rule 307-326-9. These reports are reviewed by DAQ’s compliance section at the
time of their submittal. Copies of all submitted reports are available in the source file.

§60.488a Reconstruction. ...

Status: Not applicable at this time.

36
NSPS (Part 60), QQQ: Standards of Performance for VOC Emissions from Petroleum
Refinery Wastewater Systems

§60.690 Applicability and designation of affected facility.
(a) (1) The provisions of this subpart apply to affected facilities located in petroleum refineries for
which construction, modification, or reconstruction is commenced after May 4, 1987.
(2) An individual drain system is a separate affected facility.
(3) An oil-water separator is a separate affected facility.
(4) An aggregate facility is a separate affected facility.
(b) Notwithstanding the provisions of 40 CFR 60.14(e)(2), the construction or installation of a new
individual drain system shall constitute a modification to an affected facility described in
§60.690(a)(4). For purposes of this paragraph, a new individual drain system shall be limited to all
process drains and the first common junction box.

Status: In compliance. The oil-water separator and slop oil tank (tank 62) are exempt from this
section due to age. Both were installed prior to May 4, 1987. Some drains are subject to
NSPS QQQ, and some are not. All drains in the newly constructed isomerization unit
are subject to NSPS QQQ.

§60.692-1 Standards: General.
(a) Each owner or operator subject to the provisions of this subpart shall comply with the
requirements of §§60.692-1 to 60.692-5 and with §§60.693-1 and 60.693-2, except during periods of
startup, shutdown, or malfunction.
(b) Compliance with §§60.692-1 to 60.692-5 and with §§60.693-1 and 60.693-2 will be determined
by review of records and reports, review of performance test results, and inspection using the methods
and procedures specified in §60.696.
(c) Permission to use alternative means of emission limitation to meet the requirements of §§60.692-2
through 60.692-4 may be granted as provided in §60.694.
(d)(1) Stormwater sewer systems are not subject to the requirements of this subpart.
(2) Ancillary equipment, which is physically separate from the wastewater system and does not come
in contact with or store oily wastewater, is not subject to the requirements of this subpart.
(3) Non-contact cooling water systems are not subject to the requirements of this subpart.
(4) An owner or operator shall demonstrate compliance with the exclusions in paragraphs (d)(1), (2),
and (3) of this section as provided in §60.697 (h), (i), and (j).

Status: In Compliance.

§60.692-2 Standards: Individual drain systems.
(a) (1) Each drain shall be equipped with water seal controls.
(2) Each drain in active service shall be checked by visual or physical inspection initially and monthly
thereafter for indications of low water levels or other conditions that would reduce the effectiveness
of the water seal controls.
(3) Except as provided in paragraph (a)(4) of this section, each drain out of active service shall be
checked by visual or physical inspection initially and weekly thereafter for indications of low water
levels or other problems that could result in VOC emissions.
(4) As an alternative to the requirements in paragraph (a)(3) of this section, if an owner or operator
elects to install a tightly sealed cap or plug over a drain that is out of service, inspections shall be
conducted initially and semiannually to ensure caps or plugs are in place and properly installed.
(5) Whenever low water levels or missing or improperly installed caps or plugs are identified, water
shall be added or first efforts at repair shall be made as soon as practicable, but not later than 24 hours
after detection, except as provided in §60.692-6.
37
(b)(1) Junction boxes shall be equipped with a cover and may have an open vent pipe. The vent pipe
shall be at least 90 cm (3 ft) in length and shall not exceed 10.2 cm (4 in) in diameter.
(2) Junction box covers shall have a tight seal around the edge and shall be kept in place at all times,
except during inspection and maintenance.
(3) Junction boxes shall be visually inspected initially and semiannually thereafter to ensure that the
cover is in place and to ensure that the cover has a tight seal around the edge.
(4) If a broken seal or gap is identified, first effort at repair shall be made as soon as practicable, but
not later than 15 calendar days after the broken seal or gap is identified, except as provided in
§60.692-6.
(c) (1) Sewer lines shall not be open to the atmosphere and shall be covered or enclosed in a manner
so as to have no visual gaps or cracks in joints, seals, or other emission interfaces.
(2) The portion of each unburied sewer line shall be visually inspected initially and semiannually
thereafter for indication of cracks, gaps, or other problems that could result in VOC emissions.
(3) Whenever cracks, gaps, or other problems are detected, repairs shall be made as soon as
practicable, but not later than 15 calendar days after identification, except as provided in §60.692-6.
(d) Except as provided in paragraph (e) of this section, each modified or reconstructed individual
drain system that has a catch basin in the existing configuration prior to May 4, 1987 shall be exempt
from the provisions of this section.
(e) Refinery wastewater routed through new process drains and a new first common downstream
junction box, either as part of a new individual drain system or an existing individual drain system,
shall not be routed through a downstream catch basin.

Status: In compliance. Drains are inspected monthly for low water levels. Low water levels are
refilled when found. All junction boxes are covered and sealed. Junction boxes and
sealed/covered drains are inspected semi-annually and a log is kept and reported to the
DAQ. See semi-annual reports in the site file.

§60.692-3 Standards: Oil-water separators. ...

Status: Not Applicable. The oil-water separator was installed prior to May 4, 1987, and is
exempt from NSPS QQQ due to age and flow rate. The slop oil tank (tank 62) does
have a fixed roof. The system has a design capacity below the 250 gpm threshold
mentioned in (5)(b) above. Vapors are not purged. Silver Eagle is operating the
oil-water separator in compliance with the requirements although the slop tank is
technically grandfathered from this requirement. There have been no recent
modifications made to the system and is still considered to be eligible for grandfathered
status.

§60.692-4 Standards: Aggregate facility. ...

Status: Not applicable.

§60.692-5 Standards: Closed vent systems and control devices.

Status: Not applicable. There are no control devices or closed vent systems associated with the
wastewater system.

38
§60.692-6 Standards: Delay of repair.
(a) Delay of repair of facilities that are subject to the provisions of this subpart will be allowed if
the repair is technically impossible without a complete or partial refinery or process unit
shutdown.
(b) Repair of such equipment shall occur before the end of the next refinery or process unit
shutdown.

Status: In compliance. Repairs to the wastewater system are minimal. There were no delays of
repair recorded during the prior 12-month period.

§60.692-7 Standards: Delay of compliance.
(a) Delay of compliance of modified individual drain systems with ancillary downstream
treatment components will be allowed if compliance with the provisions of this subpart cannot
be achieved without a refinery or process unit shutdown.
(b) Installation of equipment necessary to comply with the provisions of this subpart shall occur
no later than the next scheduled refinery or process unit shutdown.

Status: In compliance. No wastewater component repairs have required a delay to the annual
process shutdown.

§60.693- 1 Alternative standards for individual drain systems.

Status: Not applicable. The wastewater system is not a completely enclosed system.

§60.693-2 Alternative standards for oil-water separators.

Status: Not applicable. The slop-oil tank is exempt from NSPS QQQ due to age (pre-1974)
although this tank has a fixed roof in accordance with NSPS QQQ.

§60.694 Permission to use alternative means of emission limitation.

Status: Not applicable. No alternate means of emissions limitations are used.

§60.695 Monitoring of operations.

Status: Not applicable. Silver Eagle is not required to use any of the listed control devices for
the wastewater system due to the age of the system.

§60.696 Performance test methods and procedures and compliance provisions.
(a) Before using any equipment installed in compliance with the requirements of 60.692-2,
60.692-3,60.692-4,60.692-5, or 60.693, the owner or operator shall inspect such equipment for
indications of potential emissions, defects, or other problems that may cause the requirements of
this subpart not to be met. Points of inspection shall include, but are not limited to, seals, flanges,
joints, gaskets, hatches, caps, and plugs.

Status: In compliance. All seals and gaskets were checked initially as required and are
rechecked semi-annually. Inspection records were verified during the site visit. Silver
Eagle does not have a closed vent system, flare, or other applicable control equipment
that is associated with the wastewater system.

39
§60.697 Recordkeeping requirements.
(a) Each owner or operator of a facility subject to the provisions of this subpart shall comply
with the Recordkeeping requirements of this section. All records shall be retained for a period of
2 years after being recorded unless otherwise noted.
(b) (1) For individual drain systems subject to 60.692-2, the location, date, and corrective action
shall be recorded for each drain when the water seal is dry or otherwise breached, when a drain
cap or plug is missing or improperly installed, or other problem is identified that could result in
VOC emissions, as determined during the initial and periodic visual or physical inspection.
(2) For junction boxes subject to 60.692-2, the location, date, and corrective action shall be
recorded for inspections required by 60.692-2(b) when a broken seal, gap, or other problem is
identified that could result in VOC emissions.
(3) For sewer lines subject to 60.692-2 and 60.693-1 (e), the location, date, and corrective action
shall be recorded for inspections required by 60.692-2(c) and 60.693-1 (e) when a problem is
identified that could result in VOC emissions.
(c) For oil-water separators subject to 60.692-3, the location, date, and corrective action shall be
recorded for inspections required by 60.692-3(a) when a problem is identified that could result in
VOC emissions.
(e) (1) If an emission point cannot be repaired or corrected without a process unit shutdown, the
expected date of a successful repair shall be recorded.
(2) The reason for the delay as specified in 60.692-6 shall be recorded if an emission point or
equipment problem is not repaired or corrected in the specified amount of time.
(3) The signature of the owner or operator (or designee) whose decision it was that repair could
not be affected without refinery or process shutdown shall be recorded.
(4) The date of successful repair or corrective action shall be recorded.
(f) (1) A copy of the design specifications for all equipment used to comply with the provisions
of this subpart shall be kept for the life of the source in a readily accessible location.
(2) The following information pertaining to the design specifications shall be kept.
(i) Detailed schematics, and piping and instrumentation diagrams.
(ii) The dates and descriptions of any changes in the design specifications.
(g) If an owner or operator elects to install a tightly sealed cap or plug over a drain that is out of
active service, the owner or operator shall keep for the life of a facility in a readily accessible
location, plans, or specifications, which indicate the location of such drains.
(h) For Storm water sewer systems subject to the exclusion in 60.692-1 (d)(1), an owner or
operator shall keep for the life of the facility in a readily accessible location, plans or
specifications which demonstrate that no wastewater from any process units or equipment is
directly discharged to the Storm water sewer system.
(i) For ancillary equipment subject to the exclusion in 60.692- 1(d)(2), an owner or operator shall
keep for the life of a facility in a readily accessible location, plans, or specifications which
demonstrate that the ancillary equipment does not come in contact with or store oily wastewater.
(j) For non-contact cooling water systems subject to the exclusion in 60.692-1(d)(3), an owner or
operator shall keep for the life of the facility in a readily accessible location, plans or
specifications which demonstrate that the cooling water does not contact hydrocarbons or oily
wastewater and is not recirculated through a cooling tower.

Status: In compliance. All plans and piping diagrams are kept on site and are available for
review. Wastewater drains are inspected monthly. Junction boxes have been inspected
semi-annually. Records appeared to include all required details. The API separator is a
vintage unit installed pre-1987 (likely in the 1970s), is inspected semiannually, and
reports sent to DAQ.

40
§60.698 Reporting requirements.
(a) An owner or operator electing to comply with the provisions of 60.693 shall notify the
Administrator of the alternative standard selected in the report required in 60.7.
(b)(1) Each owner or operator of a facility subject to this subpart shall submit to the
Administrator within 60 days after initial startup a certification that the equipment necessary to
comply with these standards has been installed and that the required initial inspections or tests of
process drains, sewer lines, junction boxes, oil-water separators, and closed vent systems and
control devices have been carried out in accordance with these standards. Thereafter, the owner
or operator shall submit to the Administrator semiannually a certification that all of the required
inspections have been carried out in accordance with these standards.
(2) Each owner or operator of an affected facility that uses a flare shall submit to the
Administrator within 60 days after initial startup, as required under 60.8(a), a report of the results
of the performance test required in 60.696(c).
(c) A report that summarizes all inspections when a water seal was dry or otherwise breached,
when a drain cap or plug was missing or improperly installed, or when cracks, gaps, or other
problems were identified that could result in VOC emissions, including information about the
repairs or corrective action taken, shall be submitted initially and semiannually thereafter to the
Administrator.
(e) If compliance with the provisions of this subpart is delayed pursuant to 60.692-7, the
notification required under 40 CFR 60.7(a)(4) shall include the estimated date of the next
scheduled refinery or process unit shutdown after the date of notification and the reason why
compliance with the standards is technically impossible without a refinery or process unit
shutdown.

Status: In compliance. Quarterly reports are submitted. The reports include the required
information including any discrepancies, see the source file for reports.

NSPS (Part 60), IIII: Standards of Performance for Stationary Compression Ignition Internal
Combustion Engines, ENGINE: 2012 300 H.P. John Deere Fire Pump

For fire pump engines with a displacement of less than 30 liters/cyl,
manufactured prior to the model years in Table 3 of 40 CFR part 60, subpart IIII
constructed after July 11, 2005 and manufactured after July 1, 2006

1. 60.4205(c) Owners and operators of fire pump engines with a displacement of less than 30 liters per
cylinder must comply with the emission standards in table 4 to this subpart, for all pollutants.

Status: In compliance. The 2012 fire pump is an EPA certified engine.

41
2. 60.4207 (a) Beginning October 1, 2007, owners and operators of stationary CI ICE subject to this
subpart that use diesel fuel must use diesel fuel that meets the requirements of 40 CFR 80.510(a).
(b) Beginning October 1, 2010, owners and operators of stationary CI ICE subject to this subpart with
a displacement of less than 30 liters per cylinder that use diesel fuel must purchase diesel fuel that
meets the requirements of 40 CFR 80.510(b) for nonroad diesel fuel.
40 CFR 80.510 (b) Beginning June 1, 2010. Except as otherwise specifically provided in this subpart,
all NR and LM diesel fuel is subject to the following per-gallon standards:
(1) Sulfur content. (i) 15 ppm maximum for NR diesel fuel. ….
(2) Cetane index or aromatic content, as follows: (i) A minimum cetane index of 40; or (ii) A
maximum aromatic content of 35 volume percent.

Status: In compliance. Diesel fuel for all three emergency generators comes from the same source.
Fuel for the emergency generators has been tested in the past and current fuel delivery slips
show ULS is used.

3. 60.4208(h) In addition to the requirements specified in §§60.4201, 60.4202, 60.4204, and 60.4205, it
is prohibited to import stationary CI ICE with a displacement of less than 30 liters per cylinder that do
not meet the applicable requirements specified in paragraphs (a) through (g) of this section after the
dates specified in paragraphs (a) through (g) of this section.
(i) The requirements of this section do not apply to owners or operators of stationary CI ICE that have
been modified, reconstructed, and do not apply to engines that were removed from one existing
location and reinstalled at a new location.

Status: In compliance. The engine has not been imported, modified, reconstructed, or moved.

4. 60.4209(a) If you are an owner or operator of an emergency stationary CI internal combustion engine
that does not meet the standards applicable to non-emergency engines, you must install a non-
resettable hour meter prior to startup of the engine.

Status: Not Applicable. The engine meets standards and has a non-resettable hour meter.

5. 60.4206 Owners and operators of stationary CI ICE must operate and maintain stationary CI ICE that
achieve the emission standards as required in §§60.4204 and 60.4205 over the entire life of the
engine.
60.4211(a) If you are an owner or operator and must comply with the emission standards specified in
this subpart, you must do all of the following, except as permitted under paragraph (g) of this section:
(1) Operate and maintain the stationary CI internal combustion engine and control device according
to the manufacturer's emission-related written instructions;
(2) Change only those emission-related settings that are permitted by the manufacturer; and
(3) Meet the requirements of 40 CFR parts 89, 94 and/or 1068, as they apply to you.
(f) If you own or operate an emergency stationary ICE, you must operate the emergency stationary
ICE according to the requirements in paragraphs (f)(1) through (3) of this section. In order for the
engine to be considered an emergency stationary ICE under this subpart, any operation other than
emergency operation, maintenance and testing, emergency demand response, and operation in non-
emergency situations for 50 hours per year, as described in paragraphs (f)(1) through (3) of this
section, is prohibited. If you do not operate the engine according to the requirements in paragraphs
(f)(1) through (3) of this section, the engine will not be considered an emergency engine under this
subpart and must meet all requirements for non-emergency engines.
(1) There is no time limit on the use of emergency stationary ICE in emergency situations.
(2) You may operate your emergency stationary ICE for any combination of the purposes specified in
paragraphs (f)(2)(i) through (iii) of this section for a maximum of 100 hours per calendar year. Any
operation for non-emergency situations as allowed by paragraph (f)(3) of this section counts as part of
42
the 100 hours per calendar year allowed by this paragraph (f)(2).
(g) If you do not install, configure, operate, and maintain your engine and control device according to
the manufacturer's emission-related written instructions, or you change emission-related settings in a
way that is not permitted by the manufacturer, you must demonstrate compliance as follows: ...
(2) If you are an owner or operator of a stationary CI internal combustion engine greater than or equal
to 100 HP and less than or equal to 500 HP, you must keep a maintenance plan and records of
conducted maintenance and must, to the extent practicable, maintain and operate the engine in a
manner consistent with good air pollution control practice for minimizing emissions. In addition, you
must conduct an initial performance test to demonstrate compliance with the applicable emission
standards within 1 year of startup, or within 1 year after an engine and control device is no longer
installed, configured, operated, and maintained in accordance with the manufacturer's emission-
related written instructions, or within 1 year after you change emission-related settings in a way that
is not permitted by the manufacturer.

Status: In compliance. The source adheres to the requirements and is an emergency use engine
only. The engine is maintained and installed in accordance with manufacturer’s
recommendations.

6. 60.4214(b) If the stationary CI internal combustion engine is an emergency stationary internal
combustion engine, the owner or operator is not required to submit an initial notification. Starting
with the model years in Table 5 to this subpart, if the emergency engine does not meet the standards
applicable to non-emergency engines in the applicable model year, the owner or operator must keep
records of the operation of the engine in emergency and non-emergency service that are recorded
through the non-resettable hour meter. The owner must record the time of operation of the engine and
the reason the engine was in operation during that time.

Status: In compliance. The engine meets the requirements for not requiring initial notification. The
engine operated less than 100 hours in the previous 12 months as reported above. The
engine is not equipped with a diesel particulate filter and has a non-resettable meter. Engine
reported to be maintained.

MACT (Part 63), A: General Provisions

Status: In Compliance.

40 CFR Part 63 (MACT), ZZZZ: National Emissions Standards for Hazardous Air Pollutants for
Stationary Reciprocating Internal Combustion Engines. Pre 1996 460 H.P. Fire Pump and Pre 1996
369 H.P. Emergency Generator, Existing Stationary Engine ≤500 HP Located at Area Sources of HAP,
constructed before June 12, 2006

1. 40 CFR 63.6603 What emission limitations, operating limitations, and other requirements must I
meet if I own or operate an existing stationary RICE located at an area source of HAP
emissions?
(a) If you own or operate an existing stationary RICE located at an area source of HAP
emissions, you must comply with the requirements in Table 2d to this subpart and the operating
limitations in Table 2b to this subpart which apply to you.

Status: In compliance. Engine maintained as required. The company has a maintenance staff
and uses a maintenance tracking system to ensure preventative maintenance is
completed.

43
2. 40 CFR 63.6604 What fuel requirements must I meet if I own or operate a stationary CI RICE?
(b) Beginning January 1, 2015, if you own or operate an existing emergency CI stationary RICE
with a site rating of more than 100 brake HP and a displacement of less than 30 liters per
cylinder that uses diesel fuel and operates or is contractually obligated to be available for more
than 15 hours per calendar year for the purposes specified in § 63.6640(f)(2)(ii) and (iii) or that
operates for the purpose specified in § 63.6640(f)(4)(ii), you must use diesel fuel that meets the
requirements in 40 CFR 80.510(b) for nonroad diesel fuel, except that any existing diesel fuel
purchased (or otherwise obtained) prior to January 1, 2015, may be used until depleted.
40 CFR 80.510 (b) Beginning June 1, 2010. Except as otherwise specifically provided in this
subpart, all NR and LM diesel fuel is subject to the following per-gallon standards:
(1) Sulfur content. (i) 15 ppm maximum for NR diesel fuel. ….
(2) Cetane index or aromatic content, as follows: (i) A minimum cetane index of 40; or (ii) A
maximum aromatic content of 35 volume percent.

Status: In compliance. ULS fuel is used.

3. 40CFR 63.6625 What are my monitoring, installation, collection, operation, and maintenance
requirements?
(e) If you own or operate any of the following stationary RICE, you must operate and maintain
the stationary RICE and after-treatment control device (if any) according to the manufacturer's
emission-related written instructions or develop your 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:
(3) An existing emergency or black start stationary RICE located at an area source of HAP
emissions;
(f) If you own or operate an existing emergency stationary RICE with a site rating of less than or
equal to 500 brake HP located at a major source of HAP emissions or an existing emergency
stationary RICE located at an area source of HAP emissions, you must install a non-resettable
hour meter if one is not already installed.
(h) If you operate a new, reconstructed, or existing stationary engine, you must minimize the
engine's time spent at idle during startup 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 emission standards applicable to all times other than startup in Tables 1a, 2a, 2c, and 2d to
this subpart apply.
(i) If you own or operate a stationary CI engine that is subject to the work, operation or
management practices in items 1 or 2 of Table 2c to this subpart or in items 1 or 4 of Table 2d to
this subpart, you have the option of utilizing an oil analysis program in order to extend the
specified oil change requirement in Tables 2c and 2d to this subpart. The oil analysis must be
performed at the same frequency specified for changing the oil in Table 2c or 2d to this subpart.
The analysis program must at a minimum analyze the following three parameters: Total Base
Number, viscosity, and percent water content. The condemning limits for these parameters are as
follows: Total Base Number is less than 30 percent of the Total Base Number of the oil when
new; viscosity of the oil has changed by more than 20 percent from the viscosity of the oil when
new; or percent water content (by volume) is greater than 0.5. If all of these condemning limits
are not exceeded, the engine owner or operator is not required to change the oil. If any of the
limits are exceeded, the engine owner or operator must change the oil within 2 business days of
receiving the results of the analysis; if the engine is not in operation when the results of the
analysis are received, the engine owner or operator must change the oil within 2 business days or
before commencing operation, whichever is later.

44
The owner or operator must keep records of the parameters that are analyzed as part of the
program, the results of the analysis, and the oil changes for the engine. The analysis program
must be part of the maintenance plan for the engine.

Status: In compliance. The engines have a non-resettable hour meter and are maintained.

4. 40 CFR 63.6605 What are my general requirements for complying with this subpart?
(a) You must be in compliance with the emission limitations and operating limitations in this
subpart that apply to you at all times.
(b) At all times you must 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 you 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 Administrator 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.
§ 63.6640 (a) You must demonstrate continuous compliance with each emission limitation and
operating limitation in Tables 1a and 1b, Tables 2a and 2b, Table 2c, and Table 2d to this subpart
that apply to you according to methods specified in Table 6 to this subpart.
(e) You must also report each instance in which you did not meet the requirements in Table 8 to
this subpart that apply to you. If you own or operate a new or reconstructed stationary RICE with
a site rating of less than or equal to 500 brake HP located at a major source of HAP emissions
(except new or reconstructed 4SLB engines greater than or equal to 250 and less than or equal to
500 brake HP), a new or reconstructed stationary RICE located at an area source of HAP
emissions, or any of the following RICE with a site rating of more than 500 brake HP located at
a major source of HAP emissions, you do not need to comply with the requirements in Table 8 to
this subpart: An existing 2SLB stationary RICE, an existing 4SLB stationary RICE, an existing
emergency stationary RICE, an existing limited use stationary RICE, or an existing stationary
RICE which fires landfill gas or digester gas equivalent to 10 percent or more of the gross heat
input on an annual basis. If you own or operate any of the following RICE with a site rating of
more than 500 brake HP located at a major source of HAP emissions, you do not need to comply
with the requirements in Table 8 to this subpart, except for the initial notification requirements: a
new or reconstructed stationary RICE that combusts landfill gas or digester gas equivalent to 10
percent or more of the gross heat input on an annual basis, a new or reconstructed emergency
stationary RICE, or a new or reconstructed limited use stationary RICE.
(f) If you own or operate an emergency stationary RICE, you must operate the emergency
stationary RICE according to the requirements in paragraphs (f)(1) through (4) of this section. In
order for the engine to be considered an emergency stationary RICE under this subpart, any
operation other than emergency operation, maintenance and testing, emergency demand
response, and operation in nonemergency situations for 50 hours per year, as described in
paragraphs (f)(1) through (4) of this section, is prohibited. If you do not operate the engine
according to the requirements in paragraphs (f)(1) through (4) of this section, the engine will not
be considered an emergency engine under this subpart and must meet all requirements for non-
emergency engines.
(1) There is no time limit on the use of emergency stationary RICE in emergency situations.
(2) You may operate your emergency stationary RICE for any combination of the purposes
specified in paragraphs (f)(2)(i) through (iii) of this section for a maximum of 100 hours per
calendar year. Any operation for non-emergency situations as allowed by paragraphs (f)(3) and
(4) of this section counts as part of the 100 hours per calendar year allowed by this paragraph
(f)(2).
45
(i) Emergency stationary RICE may be operated for maintenance checks and readiness testing,
provided that the tests are recommended by federal, state or local government, the manufacturer,
the vendor, the regional transmission organization or equivalent balancing authority and
transmission operator, or the insurance company associated with the engine. The owner or
operator may petition the Administrator for approval of additional hours to be used for
maintenance checks and readiness testing, but a petition is not required if the owner or operator
maintains records indicating that federal, state, or local standards require maintenance and
testing of emergency RICE beyond 100 hours per calendar year. ...
(4) Emergency stationary RICE located at area sources of HAP may be operated for up to 50
hours per calendar year in non-emergency situations. The 50 hours of operation in non-
emergency situations are counted as part of the 100 hours per calendar year for maintenance and
testing and emergency demand response provided in paragraph (f)(2) of this section. Except as
provided in paragraphs (f)(4)(i) and (ii) of this section, the 50 hours per year for nonemergency
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. ...

Status: In compliance. The source runs the engines for emergency and maintenance purposes
only. Total hours during the previous 12 months were below 100 hours as reported
above.

5. 63.6655 What records must I keep?

Status: In compliance. Records are maintained for operations and maintenance and are
available for review. Logbooks are kept at each engine location.

MACT (Part 63), BBBBBB: National Emission Standards for Hazardous Air Pollutants for Source
Category: Gasoline Distribution Bulk Terminals, Bulk Plants, and Pipeline Facilities

Status: Not Applicable at this time. Silver Eagle has discontinued production of gasoline at the
facility and has ceased their Subpart BBBBBB semi-annual reporting. Additional
information is available in the site file concerning this subpart.

Title V (Part 70) Area Source

Status: In compliance. The source has addressed all requirements of the permitting process in
accordance with the Division of Air Quality guidance and is not required to have a Title V
permit.

STATE RULES EVALUATION:

STATE IMPLEMENTATION PLAN:
December 7, 2016 version (edited for brevity)

Section IX, Part H.1 General Requirements: Control Measures for Area and Point Sources,
Emission Limits and Operating Practices, PM10 Requirements Note: Davis County is a PM10
Attainment Area and since Silver Eagle does not affect the neighboring non-attainment area as a minor
source. Part H.11 section g is the only section that applies as it applies to both PM10 and PM2.5 areas.

46
Part H.11. General Requirements: Control Measures for Area and Point Sources, Emission Limits
and Operating Practices, PM2.5
a. Except as otherwise outlined in individual conditions of this Subsection IX.H.11 listed below, the
terms and conditions of this Subsection IX.H.11 shall apply to all sources subsequently addressed in
Subsection IX.H.12 and 13. Should any inconsistencies exist between these subsections, the source
specific conditions listed in IX.H.12 and 13 shall take precedence.

Status: Silver Eagle is not a listed source in Subsection IX.H.12 and 13 but is addressed as a
“refinery” in section “g. Petroleum Refineries”.

g. Petroleum Refineries.
i. Limits at Fluid Catalytic Cracking Units (FCCU) ...

Status: Silver Eagle does not have an FCCU.

ii. Limits on Refinery Fuel Gas
A. By no later than January 1, 2018, all petroleum refineries in or affecting the PM2.5 nonattainment
area shall reduce the H2S content of the refinery plant gas to 60 ppm or less as described in 40 CFR
60.102a. Compliance shall be based on a rolling average of 365 days. The owner/operator shall
comply with the fuel gas monitoring requirements of 40 CFR 60.107a and the related recordkeeping
and reporting requirements of 40 CR 60.108a. As used herein, refinery “plant gas” shall have the
meaning of “fuel gas” as defined in 40 CFR 60.101a, and may be used interchangeably.
B. For natural gas, compliance is assumed while the fuel comes from a public utility.

Status: In compliance. Silver Eagle continuously monitors the H2S content of the refinery gas and
maintains H2S emissions in a 12-month rolling average.

iii. Limits on Heat Exchangers
A. Each owner or operator shall comply with the requirements of 40 CFR 63.654 for heat
exchange systems in VOC service as soon as practicable but no later than January 1,
2015. The owner or operator may elect to use another EPA-approved method other than
the Modified El Paso Method if approved by the Director.
I. The following applies in lieu of 40 CFR 63.654(b): A heat exchange system is exempt from the
requirements in paragraphs 63.654(c) through (g) of this section if it meets any one of the criteria in
the following paragraphs (1) through (2) of this section.
1. All heat exchangers that are in VOC service within the heat exchange system that either:
a. Operate with the minimum pressure on the cooling water side at least 35 kilopascals greater than
the maximum pressure on the process side; or
b. Employ an intervening cooling fluid, containing less than 10 percent by weight of VOCs, between
the process and the cooling water. This intervening fluid must serve to isolate the cooling water from
the process fluid and must not be sent through a cooling tower or discharged. For purposes of this
section, discharge does not include emptying for maintenance purposes.
2. The heat exchange system cools process fluids that contain less than 10 percent by weight VOCs
(i.e., the heat exchange system does not contain any heat exchangers that are in VOC service).

Status: In compliance. Silver Eagle refinery is not specifically called out, however it is reported that
heat exchangers are monitored with the El Paso Method.

47
iv. Leak Detection and Repair Requirements
A. Each owner or operator shall comply with the requirements of 40 CFR 60.590a to 60.593a as soon
as practicable but no later than January 1, 2016.
B. For units complying with the Sustainable Skip Period, previous process unit monitoring
results may be used to determine the initial skip period interval provided that each valve
has been monitored using the 500 ppm leak definition.

Status: In compliance. Silver Eagle refinery is not specifically called out, however, Silver Eagle
operates in compliance with the applicable sections and standards of NSPS Subpart GGGa
as referenced above (40 CFR 60.590a to 60.593a) and Subpart VVa as referenced in
Subpart GGGa.

v. Requirements on Hydrocarbon Flares
A. Beginning January 1, 2018, all hydrocarbon flares at petroleum refineries located in or
affecting a designated PM2.5 non-attainment area within the State shall be subject to the
flaring requirements of NSPS Subpart Ja (40 CFR 60.100a–109a), if not already subject
under the flare applicability provisions of Ja.
B. By no later than January 1, 2019, all major source petroleum refineries in or affecting a
designated PM2.5 non-attainment area within the State shall either 1) install and operate a
flare gas recovery system designed to limit hydrocarbon flaring produced from each
affected flare during normal operations to levels below the values listed in 40 CFR
60.103a(c), or 2) limit flaring during normal operations to 500,000 scfd for each affected
flare. Flare gas recovery is not required for dedicated SRU flare and header systems, or
HF flare and header systems.

Status: In compliance. Subpart Ja evaluated earlier in this report. Part B above does not apply as
Silver Eagle is not a major source.

vi. Requirements on Tank Degassing
A. Beginning January 1, 2017, the owner or operator of any stationary tank of 40,000-gallon
or greater capacity and containing or last containing any organic liquid, with a true vapor
pressure equal or greater than 10.5 kPa (1.52 psia) at storage temperature (see R307-324-
4(1)) shall not allow it to be opened to the atmosphere unless the emissions are controlled
by exhausting VOCs contained in the tank vapor-space to a vapor control device until the
organic vapor concentration is 10 percent or less of the lower explosion limit (LEL).
B. These degassing provisions shall not apply while connecting or disconnecting degassing
equipment.
C. The Director shall be notified of the intent to degas any tank subject to the rule. Except in
an emergency situation, initial notification shall be submitted at least three (3) days prior to degassing
operations. The initial notification shall include:
I. Start date and time;
II. Tank owner, address, tank location, and applicable tank permit numbers;
III. Degassing operator’s name, contact person, telephone number;
IV. Tank capacity, volume of space to be degassed, and materials stored;
V. Description of vapor control device.

Status: In compliance. The requirement only applies to Silver Eagle’s NAPTHA tanks due to vapor
pressure exceptions. See the source file for past notifications of tank opening.

48
vii. No Burning of Liquid Fuel Oil in Stationary Sources
A. No petroleum refineries in or affecting any PM nonattainment or maintenance area shall
be allowed to burn liquid fuel oil in stationary sources except during natural gas curtailments or as
specified in the individual subsections of Section IX, Part H.
B. The use of diesel fuel meeting the specifications of 40 CFR 80.510 in standby or emergency
equipment is exempt from the limitation of IX.H.11.g.vii.A above.

Status: In compliance. Silver Eagle is aware of this requirement and does not burn any liquid fuel
oil. All diesel fueled engines are operated with ultra-low sulfur fuel.

R307-326. Ozone Nonattainment and Maintenance Areas: Control of Hydrocarbon Emissions in
Petroleum Refineries. Effective March 15, 2007

R307-326-4. Vacuum Producing Systems.
The emission of noncondensable VOCs from the condensers, hot wells, or accumulators of vacuum
producing systems shall be controlled by:
(1) piping the noncondensable vapors to a firebox or incinerator, or
(2) compressing the vapors and adding them to the refinery fuel gas, or
(3) other equally effective means provided the design and effectiveness of such means are
documented and submitted to and approved by the director

Status: In compliance. Vapors from vacuum producing systems are ducted to the F-501 Vacuum
Furnace (option 1 above), see also AO condition II.B.3.a.

R307-326-5. Wastewater (Oil/Water) Systems.
Any wastewater separator handling VOCs shall be equipped with:
(1) covers and seals approved by the director on all separators and forebays,
(2) lids or seals on all openings in covers, separators, and forebays. Such lids or seals shall be in the
closed position at all times except when in actual use.

Status: In compliance. The oil/water separator system was observed during the site visit and the
system was covered with lids and associated seals as required.

R307-326-6. Process Unit Turnaround.
The owner or operator of a petroleum refinery shall insure that a minimum of VOCs are emitted to
the atmosphere during process unit turnarounds. The owner or operator shall develop and submit to
the director for approval a procedure for minimizing VOC emissions during turnarounds. At a
minimum the procedure shall provide for:
(1) venting of the process unit or vessel during depressurization and purging to a vapor recovery
system, flare or firebox, and
(2) preventing discharge to the atmosphere of emissions of VOCs from a process unit or vessel until
its internal pressure is 136 kPa (19.7 psia) or less; or
(3) an equally effective system provided the R307-300 Series. Requirements for Specific Locations.
27 design and effectiveness of such system are documented and submitted to and approved by the
director.
(4) keeping records of the following items:
(a) every date that each process unit or vessel is shut down;
(b) the approximate vessel VOC concentration when the VOCs were first discharged to the
atmosphere; and

49
(c) the approximate total quantity of VOCs emitted to the atmosphere.
(5) maintaining records. The records required in (4) above shall be kept for at least two years and
shall be made available for review by the director or the director’s representative.

Status: In compliance. The refinery procedures specify process unit turnaround steps. The
procedure requires depressurizing the fuel gas system down to 45 psi and then venting
vapors to the refinery flare until a pressure reading of 5 psi or less is reached and the vessel
is usually purged with nitrogen or steam. The flare management plan (2016) has been
updated and is in accordance with Subpart Ja. Records of shut down date, approximate
vessel VOC concentration, and approximate total quantity of VOCs emitted are all kept.
For total quantity of VOCs emitted to the atmosphere after vessel depressurization, Silver
Eagle assumes 100 percent of the vapors remaining after depressurization and venting to
the flare is emitted to the atmosphere to approximate total quantity of VOCs emitted.
Opening permits at Silver Eagle help calculate emissions for each opening.

R307-326-7. Catalytic Cracking Units.
Flue gas produced by catalytic cracker catalyst regeneration units shall be vented to a waste heat
boiler or a process heater firebox, or incinerated, or controlled by other methods, provided the design
and effectiveness of such methods are documented, submitted to, and approved by the director.

Status: Not applicable. The refinery does not have a catalytic cracking unit.

R307-326-8. Safety Pressure Relief Valves.
All safety pressure relief valves handling organic material shall be vented to a flare, firebox, or vapor
recovery system, or controlled by the inspection, monitoring, and repair requirements described in
R307-326-9.

Status: In compliance. The majority of the pressure valves are vented to the refinery flare ducting.
The remaining valves are logged and tracked through the LDAR program in accordance
with R307-326-9 below.

R307-326-9. Leaks from Petroleum Refinery Equipment.
(1) The owner or operator of a petroleum refinery complex shall develop and conduct a VOC
monitoring program and shall follow the recording, reporting, and operating requirements consistent
with R307-326-9. The monitoring program shall be submitted 30 days prior to start-up of the
petroleum refinery complex or as determined necessary by the director.
(2) Any affected component within a petroleum refinery complex found to be leaking shall be
repaired and retested as soon as practicable, but not later than fifteen (15) days after the leak is
detected. A leaking component is defined as one that has a concentration of VOCs exceeding 10,000
parts per million by volume (ppmv) when tested by a VOC detection instrument at the leak source in
the manner described in 40 CFR 60, Appendix A, Reference Method 21, using methane or hexane as
the calibration gas. Components not subject to New Source Performance Standards Subpart GGG
shall use methane or hexane as calibration gas, provided a relative response factor for each individual
instrument is determined for the calibration gas used. Those leaks that cannot be repaired until the
unit is shut down for turnaround shall be identified with a tag and recorded as per (6) below and shall
be reported as per (7) below. The director, in coordination with the refinery owner or operator, may
require early unit turnaround based on the number and severity of tagged leaks awaiting turnaround.
(3) Monitoring Requirements.
(a) In order to ensure that all existing VOC leaks are identified and that new VOC leaks are located as
soon as practicable, the refinery owner or operator shall perform necessary monitoring using visual
observations when specified or the method described in 40 CFR 60, Appendix A, Reference Method
21, as follows:
50
(i) Monitor at least one time per year (annually) all pump seals, valves in liquid service, and process
drains;
(ii) Monitor four times per year (quarterly) all compressor seals, valves in gaseous service, and
pressure relief valves in gaseous service;
(iii) Monitor visually 52 times per year (weekly) all pump seals;
(iv) Monitor within 24 hours (with a portable VOC detection device) or repair within 15 days any
pump seal from which liquids are observed dripping;
(v) Monitor any relief valve within 24 hours after it has been vented to the atmosphere;
(vi) Monitor immediately after repair any component that was found leaking;
(vii) For all other valves considered "unsafe-to-monitor" or inaccessible during an annual inspection,
the owner or operator shall document to the director the number of valves considered "unsafe-to-
monitor" or inaccessible, the dangers involved or reasons for inaccessibility, the location of these
valves, and the procedures that the owner or operator shall follow to ensure that the valves do not
leak. The documentation for each calendar year shall be submitted for approval to the director 15 days
after the last day of each calendar year. At a minimum, the inaccessible valves shall be monitored at
least once per year (annually).
(b) For the purpose of R307-326, gaseous service for pipeline valves and pressure relief valves is
defined as the VOCs being gaseous at conditions that prevail in the components during normal
operations. Pipeline valves and pressure relief valves in gaseous service and other components subject
to leaks shall be noted or marked so that their location within the refinery complex is obvious to the
refinery operator performing the monitoring and to the State of Utah, Division of Air Quality.
(4) Exemptions. The following are exempt from the monitoring requirements of (3) above: R307-300
Series. Requirements for Specific Locations.
(a) Pressure relief devices that are connected to an operating flare header, firebox, or vapor recovery
devices, storage tank valves, and valves that are not externally regulated;
(b) Refinery equipment containing a stream composition less than 10 percent by weight VOCs; and
(c) Refinery equipment containing natural gas supplied by a public utility as defined by the Utah
Public Service Commission.
(5) Alternate Monitoring Methods and Requirements.
(a) If at any time after two complete liquid service inspections and five complete gaseous service
inspections, the owner or operator of a petroleum refinery can demonstrate that modifications to (3)
above are in order, he may apply in writing to the Air Quality Board for a variance from the
requirements of (3) above.
(b) This submittal shall include data that have been developed to justify the modification to (3) above.
As a minimum, the submittal should contain the following information:
(i) the name and address of the company;
(ii) the name and telephone number of the responsible company representative;
(iii) a description of the proposed alternate monitoring procedures; and
(iv) a description of the proposed alternate operational or equipment controls.
(6) Recording Requirements. Identified leaks shall be noted and affixed with a readily visible and
weatherproof tag bearing the identification of the leak and the date the leak was detected. The tag
shall remain in place until the leaking component is repaired. The presence of the leak shall also be
noted in a log maintained by the operator or owner of the refinery. The log shall contain, at a
minimum, the name of the process unit where the component is located, the type of component, the
tag number, the date the leak is detected, the date repaired, and the date and instrument reading when
the recheck of the component is made. The log should also indicate those leaks that cannot be
repaired until turnaround, and summarize the total number of components found leaking. The
operator or owner of the refinery complex shall retain the leak detection log for two years after the
leak has been repaired and shall make the log available to the director upon request.

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(7) Reporting Requirements. The operator or owner of a petroleum refinery complex shall submit a
report to the director by the 15th day of January, April, July, and October of each year listing the total
number of components inspected, all leaks that have been located during the previous 3 calendar
months but not repaired within 15 days, all leaking components awaiting unit turnaround and the total
number of components found leaking. In addition, the refinery operator or owner shall submit a
signed statement with each report that all monitoring has been performed as stipulated in R307-326-
9.
(8) Additional Requirements. Any time a valve, with the exception of safety pressure relief valves, is
located at the end of a pipe or line containing VOCs, the end of the line shall be sealed with one of the
following: a second valve, a blind flange, a plug or a cap. This sealing device shall only be removed
when the line is in use for sampling.

Status: In compliance. The source has an LDAR program in place to monitor components in VOC
service. Valves and seals are visually inspected or monitored according to the requirements.
The source submitted the required unsafe-to-monitor and quarterly monitoring reports.
The only pressure relief valve (PRV) open to the atmosphere is on the crude tower,
PRV-16903. The atmospheric relief valve did not vent within the last 24-months. A process
and instrument diagram are kept and shows the location and assigned number of every
valve. Leaking components are tagged, which includes identification of the leak and the date
detected. No alternative monitoring method is used. A first attempt at repair is made
immediately if possible, and repairs that do not require unit shutdown are done no later
than fifteen days after detection. A double valve or a plug or cap is installed on all pipes
ending with a valve. The tracking system tracks leaks and shows repair history. The LDAR
inspections are contracted out and need to be coordinated in order to witness any of the
inspections. Silver Eagle reports indicate that they are following NSPS Subpart GGGa leak
thresholds in their LDAR program.
R307-327. Ozone Nonattainment and Maintenance Areas: Petroleum Liquid Storage. Effective
February 1, 2012
R307-327-4. General Requirements.
(1) Any existing stationary storage tank, reservoir or other container with a capacity greater than
40,000 gallons (150,000 liters) that is used to store volatile petroleum liquids with a true vapor
pressure greater than 10.5 kilo pascals (kPa) (1.52 psia) at storage temperature shall be fitted with
control equipment that will minimize vapor loss to the atmosphere. Storage tanks, except those
erected before January 1, 1979, which are equipped with external floating roofs, shall be fitted with
an internal floating roof that shall rest on the surface of the liquid contents and shall be equipped with
a closure seal or seals to close the space between the roof edge and the tank wall, or alternative
equivalent controls, provided the design and effectiveness of such equipment is documented and
submitted to and approved by the executive secretary. The owner or operator shall maintain a record
of the type and maximum true vapor pressure of stored liquid.
(2) The owner or operator of a petroleum liquid storage tank not subject to (1) above, but containing
a petroleum liquid with a true vapor pressure greater than 7.0 kPa (1.0 psia), shall maintain records
of the average monthly storage temperature, the type of liquid, throughput quantities, and the
maximum true vapor pressure.

Status: In compliance. See Subparts (K, Ka, and Kb) evaluation. The source has no external
floating roof tanks.

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R307-327-5. Installation and Maintenance.
(1) The owner or operator shall ensure that all control equipment on storage vessels is properly
installed and maintained.
(a) There shall be no visible holes, tears or other openings in any seal or seal fabric and all openings,
except stub drains, shall be equipped with covers, lids, or seals.
(b) All openings in floating roof tanks, except for automatic bleeder vents, rim space vents, and leg
sleeves, shall provide a projection below the liquid surface.
(c) The openings shall be equipped with a cover, seal, or lid.
(d) The cover, seal, or lid is to be in a closed position at all times except when the device is in actual
use.
(e) Automatic bleeder vents shall be closed at all times except when the roof is floated off or landed
on the roof leg supports. Rim vents shall be set to open when the roof is being floated off the leg
supports or at the manufacturer's recommended setting.
(f) Any emergency roof drain shall be provided with a slotted membrane fabric cover or equivalent
cover that covers at least 90 percent of the area of the opening.
(2) The owner or operator shall conduct routine inspections from the top of the tank for external
floating roofs or through roof hatches for internal floating roofs at six month or shorter intervals to
insure there are no holes, tears, or other openings in the seal or seal fabric.
(a) The cover must be uniformly floating on or above the liquid and there must be no visible defects
in the surface of the cover or petroleum liquid accumulated on the cover.
(b) The seal(s) must be intact and uniformly in place around the circumference of the cover between
the cover and tank wall.
(3) A close visible inspection of the primary seal of an external floating roof is to be conducted at
least once per year from the roof top unless such inspection requires detaching the secondary seal,
which would result in damage to the seal system.
(4) Whenever a tank is emptied and degassed for maintenance, an emergency, or any other similar
purpose, a close visible inspection of the cover and seals shall be made.
(5) The executive secretary must be notified 7 days prior to the refilling of a tank that has been
emptied, degassed for maintenance, an emergency, or any other similar purpose. Any non-
compliance with this rule must be corrected before the tank is refilled.

Status: In compliance. The source has no external floating roofs (Item 1f and 3 do not apply.) All
seals on internal floating roofs are inspected. Records of tanks inspections have been kept
and submitted as required. The company has notified the Division of Air Quality before
refilling any emptied and degassed tank, see source file for past notification letters.

R307-327-6

Status: No external floating roof tanks.

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EMISSION INVENTORY:

2023 Emissions Inventory data are recorded as follows:

Pollutant Code Pollutant Description
Emissions
(excludes tailpipe)
Tailpipe
Emissions Total Emissions
PM10-PRI PM10 Primary (Filt + Cond) 3.30065 0.02950 3.33015
PM10-FIL PM10 Filterable 1.39190 <0.00001 1.39190
PM25-PRI PM2.5 Primary (Filt + Cond) 2.74449 0.02845 2.77294
PM25-FIL PM2.5 Filterable 0.83574 <0.00001 0.83574
PM-CON PM Condensible 1.90164 <0.00001 1.90164
SO2 Sulfur Dioxide 0.18241 0.00085 0.18326
NOX Nitrogen Oxides 23.98791 0.44759 24.43550
VOC Volatile Organic Compounds 47.42660 0.12073 47.54732
CO Carbon Monoxide 29.98405 2.92542 32.90947
7439921 Lead 0.00018 <0.00001 0.00018
NH3 Ammonia 1.06782 <0.00001 1.06782
75070 Acetaldehyde 0.00002 0 0.00002
107028 Acrolein <0.00001 0 <0.00001
7440382 Arsenic 0.00007 0 0.00007
71432 Benzene 0.07112 0 0.07112
7440417 Beryllium <0.00001 0 <0.00001
106990 1,3-Butadiene <0.00001 0 <0.00001
7440439 Cadmium 0.00037 0 0.00037
7440473 Chromium 0.00047 0 0.00047
7440484 Cobalt 0.00003 0 0.00003
100414 Ethyl Benzene 0.00205 0 0.00205
50000 Formaldehyde 0.02505 0 0.02505
110543 Hexane 4.02027 0 4.02027
7439965 Manganese 0.00012 0 0.00012
7439976 Mercury 0.00008 0 0.00008
91203 Naphthalene 0.01080 0 0.01080
7440020 Nickel 0.00068 0 0.00068
130498292 PAH, total <0.00001 0 <0.00001
7782492 Selenium 0.00001 0 0.00001
108883 Toluene 0.08909 0 0.08909
1330207 Xylenes (Mixed Isomers) 0.07251 0 0.07251
91576 2-Methylnaphthalene 0.00001 0 0.00001

PREVIOUS ENFORCEMENT
ACTIONS: No enforcement actions within the past five years.

COMPLIANCE STATUS & In compliance with conditions of AO DAQE-AN101240030-16 dated
RECOMMENDATIONS: November 9, 2016, state and federal regulations at the time of
inspection.
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HPV STATUS: Not applicable.

COMPLIANCE
ASSISTANCE: None.

RECOMMENDATION FOR Inspect as normal. This is a large site and multiple inspections may be
NEXT INSPECTION: required. Previous notice is recommended as company personnel have
begun teleworking schedules.

ATTACHMENTS: VEO form.