DAQ-2025-001251

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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. b. Definitions: i. The definitions contained in R307-101-2, Definitions, apply to Section IX, Part H. ii. Natural gas curtailment means a period of time during which the supply of natural gas to an affected facility is halted for reasons beyond the control of the facility. The act of entering into a contractual agreement with a supplier of natural gas established for curtailment purposes does not constitute a reason that is under the control of a facility for the purposes of this definition. An increase in the cost or unit price of natural gas does not constitute a period of natural gas curtailment. c. Recordkeeping and Reporting: i. Any information used to determine compliance shall be recorded for all periods when the source is in operation, and such records shall be kept for a minimum of five years. Any or all of these records shall be made available to the Director upon request. ii. Each source shall comply with all applicable sections of R307-150 Emission Inventories.
iii. Each source shall submit a report of any deviation from the applicable requirements of this Subsection IX.H, including those attributable to upset conditions, the probable cause of such deviations, and any corrective actions or preventive measures taken. The report shall be submitted to the Director no later than 24-months following the deviation or earlier if specified by an underlying applicable requirement. Deviations due to breakdowns shall be reported according to the breakdown provisions of R307-107.
iv. Each source shall comply with all applicable recordkeeping and reporting sections of their most recently issued Title V Operating Permit, including all requirements associated with the submission of annual compliance certifications and biannual monitoring reports. If more stringent or additional requirements are listed in Subsections IX.H.12 and IX.H.13, each source shall comply with those requirements.
v. Each source shall comply with all applicable recordkeeping and reporting as required in 40 CFR 60 and 40 CFR 63 requirements. d. Emission Limitations: i. All emission limitations listed in Subsections IX.H.12 and IX.H.13 apply at all times, unless otherwise specified in the source specific conditions listed in IX.H.12 and 13.
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ii. All emission limitations of particulate matter (PM2.5) listed in Subsections IX.H.12 and IX.H.13 include both filterable PM 2.5 and condensable PM, unless otherwise specified in the source specific conditions listed in IX.H.12 and IX.H.13. e. Stack Testing: i. As applicable, stack testing to show compliance with the emission limitations for the sources in Subsection IX.H.12 and 13 shall be performed in accordance with the following: A. Sample Location: The emission point shall be designed to conform to the requirements of 40 CFR 60, Appendix A, Method 1, or other EPA-approved testing methods acceptable to the Director. Occupational Safety and Health Administration (OSHA) approvable access shall be provided to the test location. B. Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or EPA Test Method No. 19 "SO2 Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other EPA-approved testing methods acceptable to the Director. C. PM: 40 CFR 60, Appendix A, Methods 5, 5b, 5f, 17 or other EPA approved testing methods acceptable to the Director. D. PM2.5: 40 CFR 51, Appendix M, 201a and 202, or other EPA approved testing methods acceptable to the Director. The back half condensables shall be used for compliance demonstration as well as for inventory purposes. If a method other than 201a is used, the portion of the front half of the catch considered PM2.5 shall be based on information in Appendix B of the fifth edition of the EPA document, AP-42, or other data acceptable to the Director. E. SO2: 40 CFR 60 Appendix A, Method 6C, or other EPA-approved testing methods acceptable to the Director. F. NOx: 40 CFR 60 Appendix A, Method 7E, or other EPA-approved testing methods acceptable to the Director. G. VOC: 40 CFR 60 Appendix A, Method 25A or other EPA -approved testing methods acceptable to the Director. H. Calculations: To determine mass emission rates (lb/hr, etc.) the pollutant concentration as determined by the appropriate methods above shall be multiplied by the volumetric flow rate and any necessary conversion factors to give the results in the specified units of the emission limitation. I. A stack test protocol shall be provided at least 30 days prior to the test. A pretest conference shall be held if directed by the Director. J. The production rate during all compliance testing shall be no less than 90% of the maximum production rate achieved in the previous three (3) years. If the desired production rate is not achieved at the time of the test, the maximum production rate shall be 110% of the tested achieved rate, but not more than the maximum allowable production rate. This new allowable maximum production rate shall
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remain in effect until successfully tested at a higher rate. The owner/operator shall request a higher production rate when necessary. Testing at no less than 90% of the higher rate shall be conducted. A new maximum production rate (110% of the new rate) will then be allowed if the test is successful. This process may be repeated until the maximum allowable production rate is achieved. f. Continuous Emission and Opacity Monitoring i. For all continuous monitoring devices, the following shall apply: A. Except for system breakdown, repairs, calibration checks, and zero and span adjustments required under paragraph (d) 40 CFR 60.13, the owner/operator of an affected source shall continuously operate all required continuous monitoring systems and shall meet minimum frequency of operation requirements as outlined in R307-170 and 40 CFR 60.13. Flow measurement shall be in accordance with the requirements of 40 CFR 52, Appendix E; 40 CFR 60 Appendix B; or 40 CFR 75, Appendix A. B. The monitoring system shall comply with all applicable sections of R307-170; 40 CFR 13; and 40 CFR 60, Appendix B –Performance Specifications. ii. Opacity observations of emissions from stationary sources shall be conducted in accordance with 40 CFR 60, Appendix A, Method 9. g. Petroleum Refineries. i. Limits at Fluid Catalytic Cracking Units A. FCCU SO2 Emissions I. Each owner or operator of an FCCU shall comply with an SO2 emission limit of 25 ppmvd @ 0% excess air on a 365-day rolling average basis and 50 ppmvd @ 0% excess air on a 7-day rolling average basis. II. Compliance with this limit shall be determined using a CEM in accordance with IX.H.11.f. B. FCCU PM Emissions I. Each owner or operator of an FCCU shall comply with an emission limit of 1.0 pounds PM per 1000 pounds coke burn-off. II. Compliance with this limit shall be determined by following the stack test protocol specified in 40 C.F.R. §60.106(b) to measure PM emissions on the FCCU. Each owner operator shall conduct stack tests once every three (3) years at each FCCU. III. No later than January 1, 2019, each owner or operator of an FCCU subject to NSPS Ja shall install, operate and maintain a continuous parameter monitor system (CPMS) to measure and record operating parameters from the FCCU and control devices as per the requirements of 40 CFR 60.105a(b)(1). No later than January 1, 2019, each owner or operator of an FCCU not subject to NSPS Ja shall install, operate and maintain a continuous opacity monitoring system to measure and record opacity from the FCCU as per the
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requirements of 40 CFR 63.1572(b) and comply with the opacity limitation as per the requirements of Table 7 to Subpart UUU of Part 63. ii. Limits on Refinery Fuel Gas A. All petroleum refineries in or affecting any PM2.5 nonattainment area or any PM10 nonattainment or maintenance 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 40CFR60.108a. As used herein, refinery “plant gas” shall have the meaning of “fuel gas” as defined in 40 CFR60.101a, and may be used interchangeably. B. For natural gas, compliance is assumed while the fuel comes from a public utility. 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. 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). 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. 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.
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v. Requirements on Hydrocarbon Flares A. All hydrocarbon flares at petroleum refineries located in or affecting a PM2.5 nonattainment area or any PM10 nonattainment or maintenance area 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. No later than January 1, 2019, all major source petroleum refineries in or affecting any PM2.5 nonattainment area or any PM10 nonattainment or maintenance area 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. 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. vii. No Burning of Liquid Fuel Oil in Stationary Sources A. No petroleum refineries in or affecting any PM2.5 nonattainment area or PM10 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]1090.305 in standby or emergency equipment is exempt from the limitation of IX.H.11.g.vii.A above.
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h. Catalytic Oxidation for VOC Control i. Internal Combustion Engines A. Emissions from each VOC catalytic-controlled IC engine shall be routed through the oxidation catalyst system prior to being emitted to the atmosphere. The oxidation catalyst system shall be installed and operated as outlined in 40 CFR 63.6625(e). iii. Natural Gas Combustion Turbines A. Emissions from each VOC catalytic-controlled combustion turbine shall be routed through the oxidation catalyst system prior to being emitted to the atmosphere. The oxidation catalyst system shall be installed and operated according to the manufacturer's emission-related written instructions and in a manner consistent with good air pollution control practice for minimizing emissions. i. Good Combustion Practices for Emission Minimization A. Each owner or operator shall operate all combustion units in accordance with good combustion practices and maintain all combustion units following the manufacturer’s recommendations. j. Recordkeeping and Reporting A. In addition to the requirements specified in Section IX.H.11.c, each refinery shall comply with the following recordkeeping and reporting requirements, until such time that a Title V Operating Permit is issued. At that time, each refinery shall comply with the applicable recordkeeping and reporting sections of their most recently issued Title V Operating Permit. i. All required monitoring data and support information required by Subsections IX.H.11 and IX.H.12 shall be retained by the source for a period of at least five years from the date of the monitoring sample, measurement, report, or application. Support information includes all calibration and maintenance records, all original strip-charts or appropriate readings for continuous monitoring instrumentation, and copies of all reports required by Subsections IX.H.11 and IX.H.12. ii. Monitoring reports, if applicable, shall be submitted to the Director as specified in Subsections IX.H.11.e and IX.H.11.f.

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H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5
Nonattainment Area
a. ATK Launch Systems Inc. Promontory

i. During the period November 1 to February 28/29 on days when the 24-hour
average PM2.5 levels exceed 35 μg/m3 at the nearest real-time monitoring station, the open burning of reactive wastes with properties identified in 40 CFR 261.23 (a)
(6) (7) (8) may be conducted when the 24-hour average PM2.5 levels exceed 35
μg/m3 at the nearest real time monitoring station in limited quantities. Limited
quantities, as authorized in the facility’s RCRA Subpart X permit, of time sensitive
reactive wastes may be open burned when the 24-hour average PM2.5 levels
exceed 35 μg/m3 at the nearest real-time monitoring station.

ii. During the period November 1 to February 28/29, on days when the 24-hour average
PM2.5 levels exceed 35 μg/m3 at the nearest real-time monitoring station, the
following shall not be tested:
A. Propellant, energetics, pyrotechnics, flares and other reactive compounds greater
than 2,400 lbs. per day; or

B. Rocket motors less than 1,000,000 lbs. of propellant per motor subject to
the following exception:

I. A single test of rocket motors less than 1,000,000 lbs. of propellant per motor
is allowed on a day when the 24-hour average PM2.5 level exceeds 35 μg/m3 at the nearest real-time monitoring station provided notice is given to the
Director of the Utah Air Quality Division. No additional tests of rocket motors
less than 1,000,000 lbs. of propellant may be conducted during the inversion period until the 24-hour average PM2.5 level has returned to a
concentration below 35 μg/m3 at the nearest real-time monitoring
station.

C. During this period, records will be maintained identifying the size of the
rocket motors tested and the 24-hour average PM2.5 level at the nearest
real-time monitoring station on days when motor testing occur.
iii. Natural Gas-Fired Boilers

A. Building M-576

I. One 71 MMBTU/hr boiler shall be upgraded with low NOx burners and flue
gas recirculation by January 2016. The boiler shall be rated at a maximum of 9
ppm. The remaining boiler shall not consume more than 100,000 MCF of
natural gas per rolling 12- month period unless upgraded so the NOx emission rate is no greater than 30 ppm.

II. Emissions to the atmosphere from the Cleaver Brooks 71
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MMBTU/hr boiler in building M-576 shall not exceed the following concentration:

a. Pollutant ppmdv (3% O2 dry) NOX 9

b. Compliance with the above emission limits shall be determined by
stack test as outlined in Section IX Part H.11.e of this SIP.
c. Subsequent to initial compliance testing, stack testing is required
every three years.
B. Building M-14

I. The two 25 MMBTU/hr boiler shall be upgraded with low NOx
burners and flue gas recirculation by December 31, 2024. The boiler
shall be rated at a maximum of 9 ppm.
II. Emissions to the atmosphere from the two (2) Cleaver Brooks 25
MMBTU/hr boilers in building M-14 shall not exceed the
following concentrations:
a. Pollutant ppmdv (3% O2 dry)

NOX 9

b. Compliance with the above emission limits shall be determined
by stack test as outlined in Section IX Part H.11.e of this
SIP.
c. Subsequent to initial compliance testing, stack testing is
required every three years.

b. Big West Oil LLC Refinery

i. [Source-wide PM2.5: Following installation of the Flue Gas Blow Back Filter (FGF), but no later than
January 1, 2019, combined emissions of PM2.5 (filterable+condensable) shall
not exceed 0.29 tons per day and 72.5 tons per rolling 12-month period. No later
than January 1, 2019, Big West Oil shall conduct stack testing to establish the ratio
of filterable and condensable PM2.5 from the Catalyst Regeneration System.

A. Setting of emission factors:

The emission factors derived from the most current performance test shall be
applied to the relevant quantities of fuel combusted. Unless adjusted by
performance testing as discussed in IX.H.12.b.i.B below, the default emission
factors to be used are as follows:
Natural gas:
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Filterable PM2.5: 1.9
lb/MMscf Condensable PM2.5:
5.7 lb/MMscf

Plant gas:
Filterable PM2.5: 1.9
lb/MMscf Condensable PM2.5:
5.7 lb/MMscf
Fuel Oil: The PM2.5 emission factors shall be determined from the latest
edition of AP-42 or other EPA-approved methods.
FCC Stacks: The PM2.5 emission factors shall be established by stack test.

Where mixtures of fuel are used in a Unit, the above factors shall be
weighted according to the use of each fuel.
B. The default emission factors listed in IX.H.12.b.i.A above apply until
such time as stack testing is conducted as provided in IX.H.11.e or as
outlined below:

PM2.5 stack testing on the FCC shall be performed initially no later than
January 1, 2019 and at least once every three (3) years thereafter. Stack
testing shall be performed as outlined in IX.H.11.e.

C. Compliance with the source-wide PM2.5 Cap shall be determined for each
day as follows: Total 24-hour PM2.5 emissions for the emission points
shall be calculated by adding the daily results of the PM2.5 emissions
equations listed below for natural gas, plant gas, and fuel oil combustion.
These emissions shall be added to the emissions from the FCC to arrive at
a combined daily PM2.5 emission total.

For purposes of this subsectiona“day”isdefinedasaperiodof24-hours
commencing at midnight and ending at the following midnight.
Daily gas consumption shall be measured by meters that can delineate the
flow of gas to the boilers, furnaces and the SRU incinerator.
The equation used to determine emissions from these units shall be as
follows: Emissions = Emission Factor (lb/MMscf) * Gas Consumption
(MMscf/24 hrs)/(2,000
lb/ton)

Daily fuel oil consumption shall be monitored by means of leveling gauges
on all tanks that supply combustion sources.
The daily PM2.5 emissions from the FCC shall be calculated using the following
equation: E = FR * EF
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Where:
E = Emitted PM2.5
FR = Feed Rate to Unit (kbbls/day)
EF = emission factor (lbs/kbbl), established by the most recent stack test
Results shall be tabulated for each day, and records shall be kept which include
the meter readings (in the appropriate units) and the calculated emissions.
ii. Source-wide NOx Cap
No later than January 1, 2019, combined emissions of NOx shall not exceed
0.80 tons per day (tpd) and 195 tons per rolling 12-month period.

A. Setting of emission factors:

The emission factors derived from the most current performance test shall be applied
to the relevant quantities of fuel combusted. Unless adjusted by performance testing
as discussed in IX.H.12.b.ii.B below, the default emission factors to be used are as
follows:
Natural gas: shall be determined from the latest edition of AP-42 or other
EPA- approved methods.
Plant gas: assumed equal to natural gas
Diesel fuel: shall be determined from the latest edition of AP-42 or other
EPA- approved methods.

Where mixtures of fuel are used in a Unit, the above factors shall be weighted
according to the use of each fuel.
B. The default emission factors listed in IX.H.12.b.ii.A above apply until such time
as stack testing is conducted as provided in IX.H.11.e or as outlined below:
Initial NOx stack testing on natural gas/refinery fuel gas combustion
equipment above 40 MMBtu/hr has been performed NOx emissions for the FCC
are monitored with a continuous emission monitoring system. Refinery Boilers and heaters over 40 MMBtu/hr, but less than 100 MMBtu/hr, are in compliance with
monitoring and work practice standards of Subpart DDDDD of Part 63.

C. Compliance with the source-wide NOx Cap shall be determined for each day
as follows: Total 24-hour NOx emissions shall be calculated by adding the
emissions for each emitting unit. The emissions for each emitting unit shall be
calculated by multiplying the hours of operation of a unit, feed rate to a unit, or
quantity of each fuel combusted at each affected unit by the associated
emission factor, and summing the results.

Daily plant gas consumption at the furnaces, boilers and SRU incinerator shall
be measured by flow meters. The equations used to determine emissions shall be as follows:

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

Where the emission factor is derived from the fuel used, as listed in IX.H.12.b.ii.A
above Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that supply combustion sources.

The daily NOx emissions from the FCC shall be calculated using a CEM as outlined
in IX.H.11.f
Total daily NOx emissions shall be calculated by adding the results of the above
NOx equations for natural gas and plant gas combustion to the estimate for the
FCC.

Forpurposesofthissubsectiona“day”isdefinedasaperiodof24-hours
commencing at midnight and ending at the following midnight.

Results shall be tabulated for each day, and records shall be kept which include the
meter readings (in the appropriate units) and the calculated emissions.

iii. Source-wide SO2 Cap
No later than January 1, 2019, combined emissions of SO2 shall not exceed 0.60
tons per day and 140 tons per rolling 12-month period.
A. Setting of emission factors: The emission factors derived from the most current performance test shall be
applied to the relevant quantities of fuel combusted. The default emission factors
to be used are as follows:

Natural Gas - 0.60 lb SO2/MMscf gas

Plant Gas: The emission factor to be used in conjunction with plant gas combustion shall be determined through the use of a CEM as outlined in
IX.H.11.f.

SRUs: The emission rate shall be determined by multiplying the
sulfur dioxide concentration in the flue gas by the flow rate of the flue gas. The sulfur dioxide concentration in the flue gas shall be determined
by CEM as outlined in IX.H.11.f.
Fuel oil: The emission factor to be used for combustion shall be calculated based
on the weight percent of sulfur, as determined by ASTM Method D-4294-89 or
EPA approved equivalent acceptable to the Director, and the density of the fuel oil,
as follows:

EF (lb SO2/k gal) = density (lb/gal) * (1000 gal/k gal) * wt. % S/100 * (64 lb
SO2/32 lbs)
Where mixtures of fuel are used in a Unit, the above factors shall be
weighted according to the use of each fuel.
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B. Compliance with the source-wide SO2 Cap shall be determined for each
day as follows:
Total daily SO2 emissions shall be calculated by adding the daily SO2
emissions for natural gas and plant fuel gas combustion, to those from the
FCC and SRU stacks.

The daily SOx emissions from the FCC shall be calculated using a CEM as outlined
in IX.H.11.f

Daily natural gas and plant gas consumption shall be determined through the use
of flow meters.
Daily fuel oil consumption shall be monitored by means of leveling gauges on all
tanks that supply combustion sources.
Forpurposesofthissubsectiona“day”isdefinedas a period of 24-hours
commencing at midnight and ending at the following midnight.

Results shall be tabulated for each day, and records shall be kept which include
CEM readings for H2S (averaged for each day), all meter readings (in the
appropriate units), fuel oil parameters (density and wt% sulfur for each day any
fuel oil is burned), and the calculated emissions.]

i. NOx emissions to the atmosphere from the indicated emission points shall not exceed
the following rates and concentrations. The averaging period for the following emission
limits is determined on a 30-day rolling average.
Emission Points Emission Rate (lb/MMBtu)

1. FCC Heater H-101 0.1 lb/MMBtu

2. Reformer Heaters H-621, 622, 624 0.05 lb/MMBtu

3. #1 Boiler 0.035 lb/MMBtu

4. #6 Boiler 0.035 lb/MMBtu
ii. Initial NOx stack testing has been performed for the #1 Boiler and #6 Boiler. For these units, stack testing shall be performed no later than December 31st, 2025. Subsequent stack testing shall be conducted at least once every three (3) years from the date of the last stack test. Stack testing shall be performed as outlined in IX.H.11.e. iii. Initial compliance testing for FCC Heater H-101, Reformer Heater H-621, Reformer Heater H-622, and Reformer Heater H-624 is required. The initial test shall be performed no later than December 31st, 2025. After the initial compliance test, stack testing shall be performed at least once every three (3) years from the date of the last stack test. Stack testing shall be performed as outlined in IX.H.11.e.
iv. [Emergency and Standby Equipment
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A. The use of diesel fuel meeting the specifications of 40 CFR 80.510 is allowed
in standby or emergency equipment at all times.]
iv. Alternate Startup and Shutdown Requirements

A. During any day which includes startup or shutdown of the FCCU, combined
emissions of SO2 shall not exceed 1.2 tons per day (tpd). For purposes of
this subsection, a "day" is defined as a period of 24-hours commencing at midnight
and ending at the following midnight.
B. The total number of days which include startup or shutdown of the
FCCU shall not exceed ten (10) per 12-month rolling period.
v. No later than January 1, 2019, the owner/operator shall install the following
to control emissions from the listed equipment:

Emission Unit Control Equipment
FCCU Regenerator Flue gas blowback “Pall Filter”, quaternary cyclones
with fabric filter
H-404 #1 Crude Heater Ultra-low NOx burners
Refinery Flares Subpart Ja, and MACT CC flaring standards
SRU Tail gas incinerator and redundant caustic scrubber
Product Loading Racks Vapor recovery and vapor combustors
Wastewater Treatment
System
API separator fixed cover, carbon adsorber canisters to
be installed 2019.

c. Chemical Lime Company (LHoist North America)
Lime Production Kiln

i. No later than January 1, 2019, or upon source start-up, whichever comes later,
SNCR technology shall be installed on the Lime Production Kiln.
a. Effective January 1, 2019, or upon source start-up, whichever comes later,
NOx emissions shall not exceed 56 lb/hr. (3-hr rolling average)
b. Compliance with the above emissions limit shall be determined by stack
testing as outlined in Section IX Part H.11.e of this SIP.

ii. No later than January 1, 2019, or upon source start-up, whichever comes later, a
baghouse control technology shall be installed and operating on the Lime Production
Kiln.
a. Effective January 1, 2019, or upon source start-up, whichever comes later, PM
emissions shall not exceed 0.12 pounds per ton (lb/ton) of stone feed. (3-hr
rolling average)

b. Effective January 1, 2019, or upon source start-up, whichever comes later, PM2.5
(filterable + condensable) emissions shall not exceed 1.5 lbs/ton of stone feed. (3-
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hr rolling average)
c. Compliance with the above emission limits shall be determined by stack testing as
outlined in Section IX Part H.11.e of this SIP and in accordance with 40 CFR
63 Subpart AAAAA.

iii. An initial compliance test is required no later than January 1, 2019 (if start-up occurs
on or before January 1, 2019) or within 180 days of source start-up (if start-up
occurs after January 1, 2019) All subsequent compliance testing shall be performed at least once annually based upon the date of
the last compliance test.
iv. Upon plant start-up kiln emissions shall be exhausted through the baghouse during all
startup, shutdown, and operations of the kiln.

v. Start-up/shut-down provisions for SNCR technology be as follows:

a. No ammonia or urea injection during startup until the combustion gases exiting
the kiln reach the temperature when NOx reduction is effective, and
b. No ammonia or urea injection during shutdown.

c. Records of ammonia or urea injection shall be documented in an operations log.
The operations log shall include all periods of start-up/shut-down and subsequent
beginning and ending times of ammonia or urea injection which documents v.a
and v.b above.
d. Chevron Products Company - Salt Lake Refinery
i. [Source-wide PM2.5 Cap

No later than January 1, 2019, combined emissions of PM2.5 (filterable+condensable) shall not exceed 0.305 tons per day (tpd) and 110 tons per
rolling 12-month period.

A. Setting of emission factors: The emission factors derived from the most current performance test shall be
applied to the relevant quantities of fuel combusted. Unless adjusted by
performance testing as discussed in IX.H.12.f.i.B below, the default emission
factors to be used are as follows:

Natural gas:
Filterable PM2.5: 1.9 lb/MMscf
Condensable PM2.5: 5.7 lb/MMscf

Plant gas:
Filterable PM2.5: 1.9 lb/MMscf
Condensable PM2.5: 5.7 lb/MMscf

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HF alkylation polymer: shall be determined from the latest edition of AP-42 (HF alkylation polymer treated as fuel oil #6) or other EPA-approved
methods.
Diesel fuel: shall be determined from the latest edition of AP-42 or other
EPA- approved methods.

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

Where mixtures of fuel are used in a Unit, the above factors shall be
weighted according to the use of each fuel.
B. The default emission factors listed in IX.H.12.f.i.A above apply until such time
as stack testing is conducted as provided in IX.H.11.e or as outlined below:

Initial PM2.5 stack testing on the FCC stack has been performed and shall
be conducted at least once every three (3) years from the date of the last
stack test. Stack testing shall be performed as outlined in IX.H.11.e.

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

Total 24-hour PM2.5 emissions for the emission points shall be calculated by
adding the daily results of the PM2.5 emissions equations listed below for natural
gas, plant gas, and fuel oil combustion. These emissions shall be added to the
emissions from the FCC to arrive at a combined daily PM2.5 emission total.
Forpurposesofthissubsectiona“day”isdefinedasaperiod of 24-hours
commencing at midnight and ending at the following midnight.
Daily natural gas and plant gas consumption shall be determined through the use of
flow meters.

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

The equation used to determine emissions for the boilers and furnaces shall be as
follows: Emissions = Emission Factor (lb/MMscf) * Gas Consumption (MMscf/24 hrs)/(2,000 lb/ton)

Results shall be tabulated for each day, and records shall be kept which include
the meter readings (in the appropriate units) and the calculated emissions.

ii. Source-wide NOx Cap

No later than January 1, 2019, combined emissions of NOx shall not exceed 2.1 tons
per day (tpd) and 766.5 tons per rolling 12-month period.

131
A. Setting of emission factors:
The emission factors derived from the most current performance test shall be
applied to the relevant quantities of fuel combusted. Unless adjusted by
performance testing as discussed in IX.H.12.f.ii.B below, the default emission
factors to be used are as follows:

Natural gas: shall be determined from the latest edition of AP-42 or other
EPA- approved methods.
Plant gas: assumed equal to natural gas
Alkylation polymer: shall be determined from the latest edition of AP-42 (as
fuel oil #6) or other EPA-approved methods.

Diesel fuel: shall be determined from the latest edition of AP-42 or other
EPA- approved methods.

Where mixtures of fuel are used in a Unit, the above factors shall be weighted
according to the use of each fuel.
B. The default emission factors listed in IX.H.12.f.ii.A above apply until such time
as stack testing is conducted as provided in IX.H.11.e or as outlined below:

Initial NOx stack testing on natural gas/refinery fuel gas combustion equipment
above 100 MMBtu/hr has been performed and shall be conducted at least once
every three (3) years from the date of the last stack test. At that time a new flow-
weighted average emission factor in terms of: lbs/MMbtu shall be derived for
each combustion type listed in IX.H.12.f.ii.A above. Stack testing shall be
performed as outlined in IX.H.11.e.

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

Total 24-hour NOx emissions shall be calculated by adding the emissions for
each emitting unit. The emissions for each emitting unit shall be calculated
by multiplying the hours of operation of a unit, feed rate to a unit, or quantity
of each fuel combusted at each affected unit by the associated emission
factor, and summing the results.

A NOx CEM shall be used to calculate daily NOx emissions from the FCC.
Emissions shall be determined by multiplying the nitrogen dioxide concentration in
the flue gas by the flow rate of the flue gas. The NOx concentration in the flue gas
shall be determined by a CEM as outlined in IX.H.11.f.

Forpurposesofthissubsectiona“day”isdefinedasaperiodof24-hours
commencing at midnight and ending at the following midnight.

Daily natural gas and plant gas consumption shall be determined through the use of
131
flow meters.
Daily fuel oil consumption shall be monitored by means of leveling gauges on all
tanks that supply combustion sources.

Results shall be tabulated for each day, and records shall be kept which include the
meter readings (in the appropriate units) and the calculated emissions

iii. Source-wide SO2

No later than January 1, 2019, combined emissions of SO2 shall not exceed 1.05
tons per day (tpd) and 383.3 tons per rolling 12-month period.

A. Setting of emission factors:
The emission factors derived from the most current performance test shall be applied
to the relevant quantities of fuel combusted. The default emission factors to be used are as follows:

FCC: The emission rate shall be determined by the FCC SO2 CEM as outlined
in IX.H.11.f.

SRUs: The emission rate shall be determined by multiplying the sulfur dioxide
concentration in the flue gas by the flow rate of the flue gas. The sulfur dioxide
concentration in the flue gas shall be determined by CEM as outlined in IX.H.11.f.

Natural gas: EF = 0.60 lb/MMscf

Fuel oil & HF Alkylation polymer: The emission factor to be used for combustion
shall be calculated based on the weight percent of sulfur, as determined by ASTM
Method D-4294-89 or EPA-approved equivalent acceptable to the Director, and the
density of the fuel oil, as follows:

EF (lb SO2/k gal) = density (lb/gal) * (1000 gal/k gal) * wt.% S/100 * (64 lb
SO2/32 lb S)
Plant gas: the emission factor shall be calculated from the H2S measurement
obtained from the H2S CEM.

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

B. Compliance with the source-wide SO2 Cap shall be determined for each day
as follows: Total daily SO2 emissions shall be calculated by adding the daily
SO2
131
emissions for natural gas and plant fuel gas combustion, to those from the FCC and SRU stacks.

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

Daily fuel oil consumption shall be monitored by means of leveling gauges on all
tanks that supply combustion sources.
Results shall be tabulated for each day, and records shall be kept which include
CEM readings for H2S (averaged for each one-hour period), all meter reading (in
the appropriate units), fuel oil parameters (density and wt% sulfur for each day
any fuel oil is burned), and the calculated emissions.] i. NOx Emissions to the atmosphere from the indicated emission points shall not exceed the following rates and concentrations. The averaging period for the following emission limits is determined on a 30-day rolling average. Emission Points Emission Rate (lb/MMBtu) 1. F-11005 Boiler #5 0.20 lb/MMBtu 2. F-11006 Boiler #6 0.20 lb/MMBtu 3. F-11007 Boiler #7 0.20 lb/MMBtu 4. F-21001 Crude Furnace #1 0.09 lb/MMBtu 5. F-21002 Crude Furnace #2 0.09 lb/MMBtu 6. F-32021 FCC Furnace #1 0.17 lb/MMBtu 7. F-32023 FCC Furnace #2 0.17 lb/MMBtu 8. F-35001 Reformer Furnace F-1 0.17 lb/MMBtu 9. F-35002 Reformer Furnace F-2 0.17 lb/MMBtu 10. F-36017 Alkylation Furnace 0.12 lb/MMBtu 11. F-70001 Coker Furnace 0.16 lb/MMBtu 12. F-66100 VGO Furnace #1 0.05 lb/MMBtu 13. F-66200 VGO Furnace #2 0.05 lb/MMBtu ii. Initial NOx stack testing has been performed for the following units: F-11005 Boiler #5, F-11006 Boiler #6, F-21001 Crude Furnace #1, F-21002 Crude Furnace #2, F-36017 Alkylation Furnace, and F-70001 Coker Furnace. For these units, stack testing shall be conducted at least once every three (3) years from the date of the last stack test. Stack testing shall be performed as outlined in IX.H.11.e. iii. For F-11007 Boiler #7, NOx emissions shall be monitored by CEMs to determine
131
compliance. The CEM shall operate as outlined in IX.H.11.f. iv. Initial compliance testing for F-32021 FCC Furnace #1, F-32023 FCC Furnace #2, F-66100 VGO Furnace #1, and F-66200 VGO Furnace #2 is required. The initial test shall be performed no later than December 31st, 2025. After the initial compliance test, stack testing shall be performed at least once every three (3) years from the date of the last stack test. Stack testing shall be performed as outlined in IX.H.11.e.
v. A stack testing port shall be installed for F-35001 Reformer Furnace F-1 and F-35002 Reformer Furnace F-2 and initial compliance testing shall be performed no later than December 31st, 2027. Stack testing shall be performed as outlined in IX.H.11.e.

vi. Emergency and Standby Equipment and Alternative Fuels

A. [The use of diesel fuel meeting the specifications of 40 CFR 80.510 is allowed in standby or emergency equipment at all times.

B. HF alkylation polymer may be burned in the Alky Furnace (F-36017).]
A. Plant coke may be burned in the FCC Catalyst Regenerator.

vii. Compressor Engine Requirements
A. Emissions of NOx from each rich-burn compressor engine shall not exceed
the following:

Engine Number NOx in ppmvd @ 0% O2
K35001 236
K35002 208
K35003 230

B. Initial stack testing to demonstrate compliance with the above emission limitations
shall be performed no later than January 1, 2019 and at least once every three years
thereafter. Stack testing shall be performed as outlined in IX.H.11.e.
viii. [Flare Calculation

A. Chevron’s Flare #3 receives gases from its Isomerization unit, Reformer unit as
well as its HF AlkylationUnit.TheHFAlkylationUnit’sflowcontributionto Flare #3
will not be included in determining compliance with the flow restrictions set in
IX.H.11.g.v.B]

ix. No later than January 1, 2019, the owner/operator shall install the following to
control emissions from the listed equipment:

Emission Unit Control Equipment
Boilers: 5, 6, 7 Low NOx burners and flue gas recirculation (FGR)
Cooling Water Towers High efficiency drift eliminators
Crude Furnaces F21001, F21002 Low NOx burners
Crude Oil Loading Vapor Combustion Unit (VCU)
FCC Regenerator Stack Vacuum gas oil hydrotreater, Electrostatic
precipitator (ESP) and cyclones
Flares: Flare 1, 2 Flare gas recovery system
HDS Furnaces F64010, F64011 Low NOx burners
Reformer Compressor Drivers
K35001, K35002, K35003
Selective Catalytic Reduction (SCR)
Sulfur Recovery Unit 1 Tail gas treatment unit and tail gas incineration
Sulfur Recovery Unit 2 Tail gas treatment unit and tail gas incineration
Wastewater Treatment Plant Existing wastewater controls system of induced air flotation (IAF) and regenerative thermal oxidation
(RTO).
Upon completion of startup and initial commissioning, the Dissolved Nitrogen Floatation
(DNF) process is allowed instead of the IAF system.

e. Compass Minerals Ogden Inc.
i. NOx emissions to the atmosphere from the indicated emission point shall not
exceed the following concentrations:

Emission Points Concentration (ppm) lb/hr
Boiler #1 9.0 1.3
Boiler #2 9.0 1.3

Compliance to the above emission limits shall be determined by stack test as outlined in Section IX Part H.11.e of this SIP. A compliance test shall be performed at least
annually subsequent to the initial compliance test.

ii. PM2.5 emissions (filterable+condensable) to the atmosphere from each of
the following emission points shall not exceed the listed concentration and
lb/hr emission rates:

Emission Unit PM2.5 Emission Rate (lb/hr) Concentration Emission Rate (grains/dscf)

AH-500 1.61 0.01
AH-502 0.74 0.04
AH-513 1.49 0.0114
BH-001 0.37 0.01
BH-002 0.47 0.01
BH-008 4.25 0.01

BH-501 1.15 0.01
BH-502 0.06 0.0053
BH-503 0.23 0.01
BH-505 0.12 0.01
AH-1555 0.39 0.01
BH-1400 2.78 0.02
AH-692 0.12 0.01
BH-1516 0.22 0.01

A. Compliance to the above emission limits shall be determined by stack test as outlined
in Section IX Part H.11.e of this SIP. Compliance testing shall be performed
annually.
B. Process emissions shall be routed through operating controls prior to being emitted to
the atmosphere.

iii. Emissions of VOC from all Magnesium Chloride Evaporators (four stacks total) shall not exceed 6.18 lb/hr.

A. Compliance shall be determined by stack test as outlined in Section IX Part H.11.e of this SIP. Compliance testing shall be performed at least once every three years.

B. Process emissions shall be routed through operating controls prior to being emitted to
the atmosphere.

f. Hexcel Corporation: Salt Lake Operations

i. The following limits shall not be exceeded for fiber line
operations:

A. 5.50 MMscf of natural gas consumed per day.
B. 0.061 MM pounds of carbon fiber produced per day.

C. Compliance with each limit shall be determined by the following methods:

I. Natural gas consumption shall be determined by examination of natural
gas billing records for the plant and onsite pipe-line metering.
II. Fiber production shall be determined by examination of plant production records.

III. Records of consumption and production shall be kept on a daily basis for all
periods when the plant is in operation.

ii. After a shutdown and prior to startup of fiber lines 13 to 16, the line’s
baghouse(s) and natural gas injection dual chambered regenerative thermal
oxidizer shall be started and remain in operation during production.

A. During fiber line production, the static pressure differential across the filter media

shall be within the manufacturer’s recommended range and shall be recorded daily.
B. The manometer or the differential pressure gauge shall be calibrated according to the
manufacturer’s instructions at least once every 12 months.

iii. Filter boxes will be installed on Fiber lines 13 and 14 to control PM2.5 emissions
no later than December 31, 2019.

iv. [Ultra Low NOx Burners with flue gas recirculation shall be installed on Fiber
lines 3, 4, and 7 to control NOx emissions no later than December 31,
2024.

A. Emission limitations for NOx shall be as follows:

Concentration (ppm)
Fiber Line 3 9.0

Fiber Line 4 9.0

Fiber Line 7 9.0

B. Stack testing shall be performed at least once every (3) years based upon the date of the last compliance test and at a time when PAN is not being introduced
into the burners.

v. De-NOx Water Direct Fired Thermal Oxidizer (DFTO) shall be installed on Fiber
lines 13, 14, 15, and 16 to control NOx emissions no later than December 31,
2024.]

iv. After a shutdown and prior to startup of the fiber lines, the residence time and
temperature associated with the regenerative thermal-oxidation fume incinerators
and solvent-coating fume incinerators shall be started and remain in operation during
production.
A. Unless otherwise indicated, the carbon fiber production thermal-oxidation fume
incinerators the minimum temperature shall be 1,400 deg F and the residence time
shall be greater than or equal to 0.5 seconds
Solvent-coating fume incinerators the minimum temperature shall be 1,450 deg
F and the residence time shall be greater than or equal to 0.5 seconds

For fiber lines 6, 7, 8, 10, 11, 12, and the line associated with the Research and
Development Facility, the solvent coating fume incinerators temperature shall range
from 1,400 to 1,700 deg F and the residence time shall be greater than or equal to
1.0 second
Residence times shall be determined by:

R = V / Qmax
Where
R = residence time
V = interior volume of the incinerator – ft3
Qmax = maximum exhaust gas flow rate – ft3/second

B. Incinerator temperatures shall be monitored with temperature sensing equipment
that is capable of continuous measurement and readout of the combustion temperature. The readout shall be located such that an inspector/operator can at
any time safely read the output. The measurement shall be accurate within ± 25°F
at operating temperature. The measurement need not be continuously recorded. All instruments shall be calibrated against a primary standard at least once every
180 days. The calibration procedure shall be in accordance with 40 CFR 60,
Appendix A, Method 2, paragraph 6.3, and 10.31, or use a type "K"
thermocouple.

g. Holly Frontier Sinclair Refinery [Corporation: Holly Refining & Marketing
Company (Holly Refinery)]
i. [Source-wide PM2.5 Cap

No later than January 1, 2019, PM2.5 emissions (filterable + condensable) from
all combustion sources shall not exceed 47.6 tons per rolling 12-month period and 0.134 tons per day (tpd).

A. Setting of emission factors: The emission factors derived from the most current performance test shall be
applied to the relevant quantities of fuel combusted. Unless adjusted by
performance testing as discussed in IX.H.12. g.i.B below, the default
emission factors to be used are as follows:
Natural gas or Plant gas:
non-NSPS combustion equipment: 7.65 lb
PM2.5/MMscf NSPS combustion equipment: 0.52 lb
PM2.5/MMscf

Fuel oil:
The filterable PM2.5 emission factor for fuel oil combustion shall be determined
based on the sulfur content of the oil as follows:

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

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

As an alternative to a continuous parameter monitor system or continuous opacity monitoring system for PM emissions from any FCCU controlled by a
wet gas scrubber, as required in Subsection IX.H.11.g.i.B.III, the
owner/operator may satisfy the opacity monitoring requirements from its
FCC Units with wet gas scrubbers through an alternate monitoring program as
approved by the EPA and acceptable to the Director.

B. The default emission factors listed in IX.H.12. g.i.A above apply until such
time as stack testing is conducted as outlined below:
Initial stack testing on all NSPS combustion equipment shall be conducted no
later than January 1, 2019 and at least once every three years thereafter. At that time a new flow-weighted average emission factor in terms of: lb
PM2.5/MMBtu shall be derived. Stack testing shall be performed as outlined in
IX.H.11.e.
C. Compliance with the source-wide PM2.5 Cap shall be determined for each day
as follows: Total 24-hour PM2.5 emissions for the emission points shall be
calculated by adding the daily results of the PM2.5 emissions equations listed
below for natural gas, plant gas, and fuel oil combustion. These emissions shall
be added to the emissions from the wet scrubbers to arrive at a combined daily
PM2.5 emission total.

For purposes of this subsectiona“day”isdefinedasaperiodof24-hours
commencing at midnight and ending at the following midnight.
Daily natural gas and plant gas consumption shall be determined through the use of
flow meters on all gas-fueled combustion equipment.

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

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

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

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

Results shall be tabulated for each day, and records shall be kept which include all
meter readings (in the appropriate units), and the calculated emissions.
ii. Source-wide NOx Cap

No later than January 1, 2019, NOx emissions into the atmosphere from all
emission points shall not exceed 347.1 tons per rolling 12-month period and 2.09 tons
per day (tpd).

A. Setting of emission factors:
The emission factors derived from the most current performance test shall be
applied to the relevant quantities of fuel combusted.

Unless adjusted by performance testing as discussed in IX.H.12. g.ii.B below,
the default emission factors to be used are as follows:

Natural gas/refinery fuel gas combustion using: Low NOx burners (LNB): 41 lbs/MMscf
Ultra-Low NOx (ULNB) burners: 0.04 lbs/MMbtu
Next Generation Ultra Low NOx burners (NGULNB): 0.10 lbs/MMbtu
Boiler #5: 0.02 lbs/MMbtu
All other boilers with selective catalytic reduction (SCR): 0.02
lbs/MMbtu All other combustion burners: 100 lb/MMscf
Where:
"Natural gas/refinery fuel gas" shall represent any combustion of natural
gas, refinery fuel gas, or combination of the two in the associated
burner.

All fuel oil combustion: 120 lbs/Kgal

B. The default emission factors listed in IX.H.12. g.ii.A above apply until such time as stack testing is conducted as outlined in IX.H.11.e or by NSPS.

C. Compliance with the Source-wide NOx Cap shall be determined for each day
as follows: Total daily NOx emissions for emission points shall be
calculated by adding the results of the NOx equations for plant gas, fuel oil,
and natural gas
combustionlistedbelow.Forpurposesofthissubsectiona“day”isdefinedasa
period of 24- hours commencing at midnight and ending at the following
midnight.

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

Daily fuel oil consumption shall be monitored by means of leveling gauges on all
tanks that supply combustion sources.
The equations used to determine emissions for the boilers and furnaces shall
be as follows:

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

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

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

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

Results shall be tabulated for each day; and records shall be kept which include the
meter readings (in the appropriate units), emission factors, and the calculated emissions.

iii. Source-wide SO2 Cap
No later than January 1, 2019, the emission of SO2 from all emission points
(excluding routine SRU turnaround maintenance emissions) shall not exceed 110.3
tons per rolling 12- month period and 0.31 tons per day (tpd).

A. Setting of emission factors:
The emission factors listed below shall be applied to the relevant quantities
of fuel combusted:
Natural gas - 0.60 lb SO2/MMscf

Plant gas - The emission factor to be used in conjunction with plant gas
combustion shall be determined through the use of a CEM which will measure the
H2S content of the fuel gas. The CEM shall operate as outlined in
IX.H.11.f.

Fuel oil - The emission factor to be used in conjunction with fuel oil combustion
shall be calculated based on the weight percent of sulfur, as determined by ASTM
Method D-4294-89 or EPA-approved equivalent, and the density of the fuel oil,
as follows:

(lb of SO2/kgal) = (density lb/gal) * (1000 gal/kgal) * (wt. %S)/100 * (64 g
SO2/32 g S)
The weight percent sulfur and the fuel oil density shall be recorded for each day
any fuel oil is combusted.

B. Compliance with the Source-wide SO2 Cap shall be determined for each day as
follows: Total daily SO2 emissions shall be calculated by adding daily results
of the SO2 emissions
equations listed below for natural gas, plant gas, and fuel oil combustion.
For purposes
ofthissubsectiona“day”isdefinedasaperiodof24-hours commencing
at midnight and ending at the following midnight.

The equations used to determine emissions are:
Emissions (tons/day) = Emission Factor (lb/MMscf) * Natural Gas

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

Emissions (tons/day) = Emission Factor (lb/kgal) * Fuel Oil
Consumption (kgal/24 hrs)/(2,000 lb/ton)

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

Results shall be tabulated for each day, and records shall be kept which include CEM
readings for H2S (averaged for each one-hour period), all meter reading (in the
appropriate units), fuel oil parameters (density and wt% sulfur for each day any fuel oil
is burned), and the calculated emissions.]

i. NOx Emissions to the atmosphere from the indicated emission points shall not exceed
the following rates and concentrations. The averaging period for the following emission
limits is determined on a 30-day rolling average.

Emission Points Emission Rate (lb/MMBtu)
1. Reformer Reheat Furnace 6H1 0.15 lb/MMBtu
2. Crude Furnace #1 8H2 0.04 lb/MMBtu

3. NHDS Reactor Charge Furnace 12H1 0.10 lb/MMBtu

4. Fractionator Charge Heater 20H2 0.04 lb/MMBtu
5. Boiler #5 0.02 lb/MMBtu
6. Boiler #8 0.02 lb/MMBtu

7. Boiler #9 0.02 lb/MMBtu

8. Boiler #10 0.02 lb/MMBtu

9. Boiler #11 0.02 lb/MMBtu
ii. A stack testing port shall be installed for Reformer Reheat Furnace 6H1 and initial
compliance testing shall be performed no later than December 31st, 2028. Stack testing
shall be performed as outlined in IX.H.11.e.
iii. Initial NOx stack testing has been performed for the following units: Crude Furnace #1
8H2, NHDS Reactor Charge Furnace 12H1, Boiler #5, Boiler #8, Boiler #9, Boiler #10,

and Boiler #11. For these units, stack testing shall be conducted at least once every three (3) years from the date of the last stack test. Stack testing shall be performed as
outlined in IX.H.11.e.

iv. Initial compliance testing for the Fractionator Charge Heater 20H2 is required. The initial test shall be performed no later than December 31st, 2025. After the initial
compliance test, stack testing shall be performed at least once every three (3) years
from the date of the last stack test. Stack testing shall be performed as outlined in IX.H.11.e.

v. [Emergency and Standby Equipment
A. The use of diesel fuel meeting the specifications of 40 CFR 80.510 is allowed in
standby or emergency equipment at all times.]

v. No later than January 1, 2019, the owner/operator shall install the following to
control emissions from the listed equipment:

Emission Unit Control Equipment
Process heaters and Boilers 8&11:
boilers LNB+SCR Boilers 5, 9
& 10: SCR
Process heaters 20H2, 20H3, [23H1], 24H1,
25H1: ULNB
Cooling water towers 10,
11
High efficiency drift eliminators
FCCU regenerator stacks WGS with Lo-TOx
Flares Flare gas recovery system
Sulfur recovery unit Tail gas incineration and WGS with Lo-TOx
Wastewater treatment plant API separators, dissolved gas floatation (DGF),
moving bed bio-film reactors (MBBR)

h. Kennecott Utah Copper (KUC): Mine

i. Bingham Canyon Mine (BCM)

A. Maximum total mileage per calendar day for diesel-powered ore and waste haul
trucks shall not exceed 30,000 miles.

KUC shall keep records of daily total mileage for all periods when the mine is in
operation. KUC shall track haul truck miles with a Global Positioning System or
equivalent. The system shall use real time tracking to determine daily mileage.
B. To minimize fugitive dust on roads at the mine, the owner/operator shall perform
the following measures:

I. Apply water to all active haul roads as weather and operational conditions
warrant except during precipitation or freezing weather conditions, and shall

apply a chemical dust suppressant to active haul roads located outside of the pit influence boundary no less than twice per year.

II. Chemical dust suppressant shall be applied as weather and operational
conditions warrant except during precipitation or freezing weather conditions on
unpaved access roads that receive haul truck traffic and light vehicle traffic.

III. Records of water and/or chemical dust control treatment shall be kept for
all periods when the BCM is in operation.
IV. KUC is subject to the requirements in the most recent federally approved
Fugitive Emissions and Fugitive Dust rules.
C. The In-pit crusher baghouse shall not exceed a PM2.5 emission limit of
0.78 lbs/hr (0.007 gr/dscf) PM2.5 monitoring shall be performed by stack
testing every three years.
ii. Copperton Concentrator (CC)

A. Control emissions from the Product Molybdenite Dryers with a scrubber during operation of the dryers.

During operation of the dryers, the static pressure differential between the inlet and
outlet of the scrubber shall be within the manufacturer’s recommended range
and shall be recorded weekly.

The manometer or the differential pressure gauge shall be calibrated according to the
manufacturer’s instructions at least once per year.
The remaining heaters shall not operate more than 300 hours per rolling 12- month
period unless upgraded so the NOx emission rate is no greater than 30 ppm.
i. Kennecott Utah Copper (KUC): Power Plant

i. Utah Power Plant

A. The following requirements are applicable to Unit #4:

I. Only natural gas shall only be used as a fuel, unless the supplier or transporter
of natural gas imposes a curtailment. Unit #4 may then burn coal, only for the
duration of the curtailment plus sufficient time to empty the coal bins following
the curtailment. The Director shall be notified of the curtailment within 48
hours of when it begins and within 48 hours of when it ends.
II. Emissions to the atmosphere when burning natural gas shall not exceed the
following rates and concentrations:
Pollutant grains/dscf ppmdv lbs/hr lbs/MMBtu
68oF. 29.92 in Hg 3% O2

1. PM2.5:
Filterable 0.004
Filterable +
condensable 0.03
2. NOx: 30 32 0.04

B. Upon commencement of operation of Unit #4, stack testing to demonstrate compliance with each emission limitation in IX.H.12.j.i.A and IX.H.12.j.i.B shall be performed
as follows:
* Initial compliance testing for the Unit 4 boiler is required. Initial testing shall be
performed when burning natural gas. The initial test shall be performed within 60
days after achieving the maximum heat input capacity production rate at which the
affected facility will be operated and in no case later than 180 days after the initial
startup of a new emission source.

The limited use of natural gas during maintenance firings and break-in firings does
not constitute operation and does not require stack testing.
Pollutant Test Frequency

I. PM2.5 every year

II. NOx every year

C. Unit #5 (combined cycle, natural gas-fired combustion turbine) shall not exceed the following emission rates to the atmosphere:

Pollutant lbs/hr ppmdv (15% O2 dry)
I. PM2.5 with duct firing:
Filterable + condensable 18.8
II. VOC: 2.0

III. NOx: 2.0

D: Upon commencement of operation of Unit #5*, stack testing to demonstrate
compliance with the emission limitations in IX.H.12.m.i.B shall be performed
as follows for the following air contaminants

* Initial compliance testing for the natural gas turbine and duct burner is required.
The initial test shall be performed within 60 days after achieving the maximum heat input capacity production rate at which the affected facility will be operated and in no
case later than 180 days after the initial startup of a new emission source.

The limited use of natural gas during maintenance firings and break-in firings
does not constitute operation and does not require stack testing.
Pollutant Test Frequency

I. PM2.5 every year

II. NOx every year
III. VOC every year

j. Kennecott Utah Copper: Smelter and Refinery

i. Smelter:

A. Emissions to the atmosphere from the indicated emission points shall not exceed the
following rates and concentrations:

I. Main Stack (Stack No. 11)

1. PM2.5
a. 85 lbs/hr (filterable)
b. 434 lbs/hr (filterable + condensable)

2. SO2
a. 552 lbs/hr (3 hr. rolling average)
b. 422 lbs/hr (daily average)

3. NOx 154 lbs/hr (daily average)

II. Holman Boiler
1. NOx
a. 14 lbs/hr, (calendar-day average)

B. Stack testing to show compliance with the emissions limitations of Condition
(A) above shall be performed as specified below:

EMISSION POINT POLLUTANT TEST FREQUENCY I. Main Stack (Stack No. 11) PM2.5 Every Year
SO2 CEM
NOx CEM
II. Holman Boiler NOx Every three years and
CEMS or alternate
method according to
applicable NSPS
Standards

The Holman boiler shall use an EPA approved test method every three years and in between years use or an approved CEMS or alternate method according to
applicable NSPS standards.

C. During startup/shutdown operations, NOx and SO2 emissions are
monitored by CEMS or alternate methods in accordance with applicable
NSPS standards.

D. KUC must operate and maintain the air pollution control equipment and monitoring equipment in a manner consistent with good air pollution control
practices for minimizing emissions at all times including during startup,
shutdown, and malfunction.

ii. Refinery:

A. Emissions to the atmosphere from the indicated emission point shall not exceed the
following rate:
EMISSION POINT POLLUTANT MAXIMUM EMISSION RATE

The sum of two
(Tankhouse)
Boilers

(Upgraded
NOx 9.5 lbs/hr (before December 2020)

Tankhouse Boiler) NOx 1.5 lbs/hr (After December 2020)

Combined Heat Plant NOx 5.96 lbs/hr

B. Stack testing to show compliance with the above emission limitations shall be performed as follows:

EMISSION POINT POLLUTANT TESTING FREQUENCY
Upgraded Tankhouse
Boilers

NOx

every three years*
Combined Heat Plant NOx every year
*Stack testing shall be performed on boilers that have operated more than 300
hours during a three year period.

C. One 82 MMBTU/hr Tankhouse boiler shall be upgraded to meet a NOx rating of
9 ppm no later than December 31, 2020. The remaining Tankhouse boiler shall
not consume more than 100,000 MCF of natural gas per rolling 12- month period
unless upgraded so the NOx emission rate is no greater than 30 ppm
D. KUC must operate and maintain the stationary combustion turbine, air pollution
control equipment, and monitoring equipment in a manner consistent with good air
pollution control practices for minimizing emissions at all times including during
startup, shutdown, and malfunction. Records shall be kept on site which indicate the date and time of startups and shutdowns.

k. Nucor Steel Mills
i. Emissions to the atmosphere from the indicated emission points shall not exceed the
following rates:
A. Electric Arc Furnace Baghouse

I. PM2.5
1. 17.4 lbs/hr (24 hr. average filterable) 2. 29.53 lbs/hr (24 hr. average condensable)

II. SO2
1. 93.98 lbs/hr (3 hr. rolling average) 2. 89.0 lbs/hr (daily average)

III. NOx 59.5 lbs/hr (calendar-day average)
IV. VOC 22.20 lbs/hr

B. Reheat Furnace #1
NOx 15.0 lb/hr

C. Reheat Furnace #2 NOx 8.0 lb/hr

ii. Stack testing to show compliance with the emissions limitations of Condition
(i) above shall be performed as outlined in IX.H.11.e and as specified
below:

EMISSION POINT POLLUTANT TEST FREQUENCY

A. Electric Arc Furnace Baghouse PM2.5 every year
SO2
NOx
VOC
CEM
CEM every year

B. Reheat Furnace #1 NOx every year

C. Reheat Furnace #2 NOx every year

iii. Testing Status (To be applied to (i) and (ii) above)
A. To demonstrate compliance with the Electric Arc Furnace stack mass emissions
limits for SO2 and NOx of Condition (i)(A) above, Nucor shall calibrate,
maintain and operate the measurement systems for continuously monitoring for SO2 and NOx concentrations and stack gas volumetric flow rates in the Electric Arc
Furnace stack. Such measurement systems shall meet the requirements of
R307-170.

B. For PM2.5 testing, 40 CFR 60, Appendix A, Method 5D, or another EPA
approved method acceptable to the Director, shall be used to determine total TSP
emissions. If TSP emissions are below the PM2.5 limit, that will constitute
compliance with the PM2.5 limit. If TSP emissions are not below the PM2.5
limit, the owner/operator shall retest using EPA approved methods specified for
PM2.5 testing, within 120 days.
C. Startup/shutdown NOx and SO2 emissions are monitored by CEMS.

l. PacifiCorp Energy: Gadsby Power Plant
i. Steam Generating Unit #1:

A. Emissions of NOx shall be no greater than 179 lbs/hr on a three (3)
hour block average basis.
B. Emissions of NOx shall not exceed 336 ppmdv (@ 3% O2, dry)
C. The owner/operator shall install, certify, maintain, operate, and quality-assure
a CEM consisting of NOx and O2 monitors to determine compliance with
the NOx limitation. The CEM shall operate as outlined in IX.H.11.f.

ii. Steam Generating Unit #2:

A. Emissions of NOx shall be no greater than 204 lbs/hr on a three (3)
hour block average basis.

B. Emissions of NOx shall not exceed 336 ppmdv (@ 3% O2, dry)

C. The owner/operator shall install, certify, maintain, operate, and quality-assure
a continuous emission monitoring system (CEMS) consisting of NOx
and O2 monitors to determine compliance with the NOx limitation.

iii. Steam Generating Unit #3:
A. Emissions of NOx shall be no greater than

I. 142 lbs/hr on a three (3) hour block average basis, applicable
between November 1 and February 28/29.

II. 203 lbs/hr on a three (3) hour block average basis, applicable between
March 1 and October 31.

B. Emissions of NOx shall not exceed

I. 168 ppmdv (@ 3% O2, dry), applicable between November 1 and
February 28/29

II. 168 ppmdv (@ 3% O2, dry), applicable between applicable between March
1 and October 31.

C. The owner/operator shall install, certify, maintain, operate, and quality-assure
a CEM consisting of NOx and O2 monitors to determine compliance with
the NOx limitation. The CEM shall operate as outlined in IX.H.11.f.

iv. Steam Generating Units #1-3:

A. The owner/operator shall use only natural gas as a primary fuel and No. 2 fuel oil
or better as back-up fuel in the boilers. The No. 2 fuel oil may be used only
during periods of natural gas curtailment and for maintenance firings.
Maintenance firings shall not exceed one-percent of the annual plant Btu requirement. In addition, maintenance firings shall be scheduled between April
1 and November 30 of any calendar year. Records of fuel oil use shall be kept and
they shall show the date the fuel oil was fired, the duration in hours the fuel oil
was fired, the amount of fuel oil consumed during each curtailment, and the
reason for each firing.

v. Natural Gas-fired Simple Cycle, Catalytic-controlled Turbine Units:
A. Total emissions of NOx from all three turbines shall be no greater than
600 lbs/day. For purposes of this subsection a “day” is defined as a
period of 24-hours commencing at midnight and ending at the
following midnight.

B. Emissions of NOx from each turbine stack shall not exceed 5 ppmvd (@ 15%
O2 dry). Emissions shall be calculated on a 30-day rolling average. This limitation applies to steady state operation, not including startup and
shutdown.

C. The owner/operator shall install, certify, maintain, operate, and quality-assure
a CEM consisting of NOx and O2 monitors to determine compliance with
the NOx limitation. The CEM shall operate as outlined in IX.H.11.f.

vi. Combustion Turbine Startup / Shutdown Emission Minimization Plan

A. Startup begins when the fuel values open and natural gas is supplied to

the combustion turbines
B. Startup ends when either of the following conditions is met:

I. The NOx water injection pump is operational, the dilution air temperature
is greater than 600°F, the stack inlet temperature reaches 570°F, the
ammonia block value has opened and ammonia is being injected into the SCR
and the unit has reached an output of ten (10) gross MW; or
II. The unit has been in startup for two (2) hours.

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

D. Shutdown ends at the cessation of fuel input to the turbine combustor.

E. Periods of startup or shutdown shall not exceed two (2) hours per combustion
turbine per day.
F. Turbine output (turbine load) shall be monitored and recorded on an hourly
basis with an electrical meter.

m. Tesoro Refining and Marketing Company LLC Marathon Refinery: Salt Lake City
Refinery

i. [Source-wide PM2.5 Cap

No later than January 1, 2019, combined emissions of PM2.5
(filterable+condensable) shall not exceed 2.25 tons per day (tpd) and 179 tons per
rolling 12-month period.

A. Setting of emission factors:
The emission factors derived from the most current performance test shall be
applied to the relevant quantities of fuel combusted. Unless adjusted by
performance testing as discussed in IX.H.12.p.i.B below, the default emission
factors to be used are as follows:

Natural gas:
Filterable PM2.5: 0.0019
lb/MMBtu Condensable PM2.5:
0.0056 lb/MMBtu

Plant gas:
Filterable PM2.5: 0.0019
lb/MMBtu Condensable PM2.5:
0.0056 lb/MMBtu

Fuel Oil: The PM2.5 emission factor shall be determined from the latest edition

of AP-42 or other EPA-approved methods.

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

Where mixtures of fuel are used in a Unit, the above factors shall be
weighted according to the use of each fuel.
B. The default emission factors listed in IX.H.12.m.i.A above apply until such time
as stack testing is conducted as provided in IX.H.11.e or as outlined below:
Initial PM2.5 stack testing on the FCC wet gas scrubber stack shall be
conducted no later than January 1, 2019 and at least once every three (3) years
thereafter. Stack testing shall be performed as outlined in IX.H.11.e.

C. Compliance with the Source-wide PM2.5 Cap shall be determined for each day
as follows: Total 24-hour PM2.5 emissions for the emission points shall be
calculated by adding the daily results of the PM2.5 emissions equations listed
below for natural gas, plant gas, and fuel oil combustion. These emissions shall
be added to the emissions from the wet scrubber to arrive at a combined daily
PM2.5 emission total.
Forpurposesofthissubsectiona“day”isdefinedasaperiodof24-hours
commencing at midnight and ending at the following midnight.
Daily natural gas and plant gas consumption shall be determined through the use of
flow meters.

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

The emissions for each emitting unit shall be calculated by multiplying the hours of operation of a unit feed rate to a unit, or quantity of each fuel combusted at each
affected unity by the associated emission factor, and summing the results.

Results shall be tabulated for each day, and records shall be kept which include the
meter readings (in the appropriate units) and the calculated emissions.

ii. Source-wide NOx Cap

No later than January 1, 2019, combined emissions of NOx shall not exceed 2.3 tons
per day (tpd) and 475 tons per rolling 12-month period.

A. Setting of emission factors:
The emission factors derived from the most current performance test shall be
applied to the relevant quantities of fuel combusted. Unless adjusted by
performance testing as discussed in IX.H.12.m.ii.B below, the default emission
factors to be used are as follows:

Natural gas/refinery fuel gas combustion using: Low NOx burners (LNB):0.051 lbs/MMbtu
Ultra-Low NOx (ULNB) burners: 0.04 lbs/MMbtu
Diesel fuel: shall be determined from the latest edition of AP-42 or other
EPA- approved methods.

B. The default emission factors listed in IX.H.12.m.ii.A above apply unless
stack testing results are available or emissions are measured by operation of
a NOx CEMS.
Initial NOx stack testing on natural gas/refinery fuel gas combustion equipment
above 100 MMBtu/hr has already been performed and shall be conducted at least
once every three (3) years. At that time a new flow-weighted average emission factor in terms of: lbs/MMbtu shall be derived. Stack testing shall be performed
as outlined in IX.H.11.e. Stack testing is not required for natural gas/refinery
fuel gas combustion equipment with a NOx CEMS.

C. Compliance with the source-wide NOx Cap shall be determined for each day as
follows: Total 24-hour NOx emissions shall be calculated by adding the
emissions for each emitting unit. The emissions for each emitting unit shall be
calculated by
multiplying the hours of operation of a unit, feed rate to a unit, or quantity of
each fuel combusted at each affected unit by the associated emission factor,
and summing the results.
A NOx CEM shall be used to calculate daily NOx emissions from the FCCU wet
gas scrubber stack. Emissions shall be determined by multiplying the nitrogen
dioxide concentration in the flue gas by the flow rate of the flue gas. The NOx
concentration in the flue gas shall be determined by a CEM as outlined in
IX.H.11.f.

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

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

Forpurposesofthissubsectiona“day”isdefined as a period of 24-hours
commencing at midnight and ending at the following midnight.

Results shall be tabulated for each day, and records shall be kept which include the
meter readings (in the appropriate units) and the calculated emissions.
iii. Source-wide SO2 Cap

No later than January 1, 2019, combined emissions of SO2 shall not exceed 3.8 tons
per day (tpd) and 300 tons per rolling 12-month period.
A. Setting of emission factors:

The emission factors derived from the most current performance test shall be applied
to the relevant quantities of fuel combusted. The default emission factors to be used
are as follows:

Natural gas: EF = 0.0006
lb/MMBtu Propane: EF = 0.0006
lb/MMBtu
Diesel fuel: shall be determined from the latest edition of AP-42 or other EPA- approved methods.

Plant fuel gas: the emission factor shall be calculated from the H2S measurement or
from the SO2 measurement obtained by direct testing/monitoring.

Where mixtures of fuel are used in a unit, the above factors shall be
weighted according to the use of each fuel.

B. Compliance with the source-wide SO2 Cap shall be determined for each
day as follows: Total daily SO2 emissions shall be calculated by adding the
daily SO2
emissions for natural gas, plant fuel gas, and propane combustion to those from the
wet gas scrubber stack.

Daily SO2 emissions from the FCCU wet gas scrubber stack shall be
determined by multiplying the SO2 concentration in the flue gas by the flow
rate of the flue gas.
The SO2 concentration in the flue gas shall be determined by a CEM as outlined
in IX.H.11.f.
SRUs: The emission rate shall be determined by multiplying the sulfur dioxide
concentration in the flue gas by the flow rate of the flue gas. The sulfur dioxide concentration in the flue gas shall be determined by CEM as outlined in
IX.H.11.f

Daily SO2 emissions from other affected units shall be determined by
multiplying the quantity of each fuel used daily at each affected unit by the
appropriate emission factor.

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

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

Results shall be tabulated for each day, and records shall be kept which include
CEM readings for H2S (averaged for each one-hour period), all meter reading (in
the appropriate units), fuel oil parameters (density and wt% sulfur for each day any
fuel oil is burned), and the calculated emissions.

C. Instead of complying with Condition IX.H.11.g.ii.A, source may reduce the H
2S content of the refinery plant gas to 60 ppm or less or reduce SO2
concentration from fuel gas combustion devices to 8 ppmvd at 0% O2 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 or
SO2 emissions monitoring requirements of 40 CFR 60.107a and the related
recordkeeping and reporting
requirementsof40CFR60.108a.Asusedherein,refinery“plantgas”shallhave
themeaningof“fuelgas”asdefinedin40CFR60.101a,andmaybeused
interchangeably.]

i. NOx Emissions to the atmosphere from the indicated emission points shall not exceed
the following rates and concentrations. The averaging period for the following emission limits is determined on a 30-day rolling average.

Emission Points Emission Rate (lb/MMBtu)
1. Crude Unit Furnace H-101 0.054 lb/MMBtu

2. UFU Furnace F-1 0.065 lb/MMBtu

ii. Initial NOx stack testing has been performed for the Crude Unit Furnace H-101 and
UFU Furnace F-1 and shall be conducted at least once annually from the date of the
last stack test. Stack testing shall be performed as outlined in IX.H.11.e.
iii. Emissions to the atmosphere from the cogeneration turbines with heat recovery
steam generation CG1 and CG2 shall not exceed the following concentration. The
averaging period for the following emission limit is determined on a 30-day rolling
average.

1. Pollutant ppmdv (15% O2 dry)
NOx 32

2. Initial NOx stack testing has been performed and shall be conducted at least once
every two (2) years from the date of the last stack test. Stack testing shall be performed as outlined in IX.H.11.e.

3. The above emission limits apply to steady state operations when ambient
temperature is between 0 °F and 120 °F, not including startup, shutdown,
and minimum power load operations.

iv. Startup / Shutdown / Minimum Power Load Emission Minimization Plan
1. Startup and shutdown events shall not exceed 614 hours per 12-month rolling
period per turbine.
2. Cumulative minimum power load operations shall not exceed 421 hours per 12-
month rolling period per turbine.

3. Startup begins when the fuel valves open and natural gas or fuel gas is supplied to the combustion turbines.

4. Startup ends when the following conditions are met:

a. The gas temperature is at least 575 °F, and the unit has reached an output of
50% operating load.

5. Shutdown begins when the unit load or output is reduced below 50% operating load with the intent of removing the unit from service.

6. Shutdown ends at the cessation of fuel input to the turbine combustor.
7. Minimum Power Load begins when the turbine generator is less than 50%
operating load and the heat recovery steam generation unit is no longer
supplemental fired, with the intent to continue operation of the turbine generator at
minimum power make.

8. Minimum Power Load ends when the turbine generator is greater than 50%
operating load.
9. Turbine output (turbine load) shall be monitored and recorded on an hourly basis
with an electrical meter.

v. SO2 emissions from the SRU/TGTU/TGI shall be limited to:

A. 1.68 tons per day (tpd) for up to 21 days per rolling 12-month period, and

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

C. Daily sulfur dioxide emissions from the SRU/TGI/TGTU shall be determined by
multiplying the SO2 concentration in the flue gas by the mass flow of the flue
gas. The sulfur dioxide concentration in the flue gas shall be determined by
CEM as outlined in IX.H.11.f
vi. [Emergency and Standby Equipment

A. The use of diesel fuel meeting the specifications of 40 CFR 80.510 is allowed
in standby or emergency equipment at all times.]
vi. No later than January 1, 2019, the owner/operator shall install the following to
control emissions from the listed equipment:
Emission Unit Control Equipment
FCCU / CO Boiler Wet Gas Scrubber, LoTOx
Furnace F-1 Ultra Low NOx Burners
Tanks Tank Degassing Controls
North and South Flares Flare Gas Recovery

Furnace H-101 Ultra Low NOx Burners
Truck loading rack Vapor recovery unit
Sulfur recovery unit Tail Gas Treatment Unit
API separator Floating roof (single seal)

n. The Procter & Gamble Paper Products Company
i. Emissions to the atmosphere at all times from the indicated emission points shall not
exceed the following rates:

Source: Paper Making Boilers (Each)
Pollutant Oxygen Ref. lb/hr
NOx 3% 3.3

PM2.5
(Filterable and Condensables) 3% 0.9

Source: Paper Machine Process Stack
Pollutant Oxygen Ref. lb/hr
NOX 3% 13.50
PM2.5
(Filterable and Condensables) 3% 17.95
Source: Utility Boilers (Each)

Pollutant Oxygen Ref. lb/hr
NOX 3% 1.8

PM2.5
(Filterable and Condensables) 3% 0.74

A. Compliance with the above emission limits shall be determined by stack test as
outlined in Section IX Part H.11.e of this SIP.

B. Subsequent to initial compliance testing, stack testing is required at a minimum of once every three years.

ii. Boiler Startup/Shutdown Emissions Minimization Plan
A. Startup begins when natural gas is supplied to the Boiler(s) with the intent of
combusting the fuel to generate steam. Startup conditions end within thirty (30)
minutes of natural gas being supplied to the boilers(s).

B. Shutdown begins with the initiation of the stop sequence of the boiler until the cessation of natural gas flow to the boiler.

iii. Paper Machine Startup/Shutdown Emissions Minimization Plan

A. Startup begins when natural gas is supplied to the dryer combustion equipment with
the intent of combusting the fuel to heat the air to a desired temperature for the
paper machine. Startup conditions end within thirty (30) minutes of natural gas being supplied to the dryer combustion equipment.

B. Shutdown begins with the diversion of the hot air to the dryer startup stack and then the cessation of natural gas flow to the dryer combustion equipment.
Shutdown conditions end within thirty (30) minutes of hot air being diverted to
the dryer startup stack.

o. Utah Municipal Power Association: West Valley Power Plant.
i. Total emissions of NOx from all five (5) catalytic-controlled turbines combined shall
be no greater than 1050 lb of NOx on a daily basis. For purposes of this subpart, a
"day" is defined as a period of 24-hours commencing at midnight and ending at the
following midnight.

ii. Emissions of NOx shall not exceed 5 ppmdv (@ 15% O2, dry) on a 30-day rolling average.

iii. Total emissions of NOx from all five (5) catalytic-controlled turbines shall include
the sum of all periods in the day including periods of startup, shutdown, and maintenance.

iv. The NOx emission rate (lb/hr) shall be determined by CEM. The CEM
shall operate as outlined in IX.H.11.f.

p. University of Utah: University of Utah Facilities

i Emissions to the atmosphere from the listed emission points in Building 303
LCHWTP shall not exceed the following concentrations:

Emissions Point Pollutant ppmdv (3% O2 dry)
BoilerA#.4*
B
NOx 187
.
Boiler1s)#6 & 7 NOx 9
.C.B
Boiler2)#9* NOx 9
.C
Turbin3e)

NOx

9
.D

Turbin4e) and WHRU Duct burner NOx 15

*By December 31, 2019, Boiler #4 will be decommissioned and Boiler #9 will be installed and
operational.
ii. Stack testing to show compliance with the emissions limitations of Condition i above shall
be performed as outlined in IX.H.11.e and as specified below:
Emissions Point Pollutant Initial Test Test Frequency

BoilBer #4* NOx * #
.
Boilers #6 & 7 NOx * # .C

5Boiler #9* ).C

TDurbine
.
ETurbine and WHRU
NOx

NOx
2020 #

* #
Duc.t Burner NOx * #

Initial test already performed
* Initial tests have been performed and the next method test using EPA approved test
methods shall be performed within 3 years of the last stack test. Initial compliance
testing for Boiler #9 is required. The initial test date shall be performed within 60
days after achieving the maximum heat input capacity production rate at which the
affected facility will be operated and in no case later than 180 days after the initial
startup of a new emission source.

# A compliance test shall be performed at least once every three years from the date of the last
compliance test that demonstrated compliance with the emission limit(s). Compliance
testing shall be performed using EPA approved test methods acceptable to the Director. The Director shall be notified, in accordance with all applicable rules, of any compliance test that
is to be performed.

iii. Boiler #4 in the LCHWTP shall be decommissioned and replaced by Boiler #9 by
December 31, 2019.

iv. By the end of the third quarter of calendar year 2019, Boilers #1, #3, and #4 in
the UCHWTP shall be limited to a natural gas usage of 530 MMscf per calendar year.

v. The HSC Transformation Project boilers shall be installed and operational by the end of the third quarter of calendar year 2019. The new HSC Transformation Project
boilers shall be equipped with low NOx burners rated at 30 ppmvd at 3% O2 or
less.

vi. Records shall be kept on site which indicate the date, and time of startup and shutdown.

q. Hill Air Force Base
i. Painting and Depainting Operations

A. VOC emissions from painting and depainting operations shall not exceed 0.58 tons per
day (tpd).
I. No later than the 28th of each month, a rolling 30-day VOC emission
average shall be calculated for the previous month.

ii. Boilers

A. The combined NOx emissions for all boilers (except those less than 5 MMBtu/hr)
shall not exceed 95 lb/hr. This limit shall not apply during periods of
curtailment.

I. No later than the 28th of each month, the NOx lb/hr emission total
shall be calculated for the previous month.

B. No later than December 31, 2024, no boiler shall be operating on base with the
capacity over 30 MMBtu/hr and with a manufacture date older than January 1, 1989.