DAQ-2025-001221

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H.1 General Requirements: Control Measures for Area and Point
Sources, Emission L imits and Operating Practices, PM10 Requirements
a. Except as otherwise outlined in individual conditions of this Subsection IX.H.1 listed
below, the terms and conditions of this Subsection IX.H.1 shall apply to all sources
subsequently addressed in Subsection IX.H.2 and IX.H.3. Should any
inconsistencies exist between these two subsections, the source specific conditions
listed in IX.H.2 and IX.H.3 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, and shall include a period of two years ending with the date of the
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.

d. Emission Limitations.

i. All emission limitations listed in Subsections IX.H.2 and IX.H.3 apply at all
times, unless otherwise specified in the source specific conditions listed in
IX.H.2 and IX.H.3.

ii. All emission limitations of PM10 listed in Subsections IX.H.2 and IX.H.3 include
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both filterable and condensable PM, unless otherwise specified in the source
specific conditions listed in IX.H.2 and IX.H.3.
e. Stack Testing.
i. As applicable, stack testing to show compliance with the emission limitations for
the sources in Subsection IX.H.2 and I.X.H.3 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, 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. PM10: 40 CFR 51, Appendix M, Methods 201a and 202, or other EPA approved
testing methods acceptable to the Director. If a method other than 201a is used,
the portion of the front half of the catch considered PM10 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. 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.

H. 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.

I. The production rate during all compliance testing shall be no less than 90%
of the maximum production rate achieved in the previous three (3) years. If
the desired production rate is not achieved at the time of the test, the
maximum production rate shall be 110% of the tested achieved rate, but
not more than the maximum allowable production rate. This new
allowable maximum production rate shall remain in effect until successfully
tested at a higher rate. The owner/operator shall request a higher
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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
of40 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 (FCCU)

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.1.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 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) or 40 C.F.R. §60.104a(d)
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
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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
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 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.

iii. Sulfur Removal Units

A. All petroleum refineries in or affecting any PM2.5 nonattainment area or any
PM10 nonattainment or maintenance area shall require:

I. Sulfur removal units/plants (SRUs) that are at least 95% effective
in removing sulfur from the streams fed to the unit; or

II. SRUs that meet the SO2 emission limitations listed in 40 CFR 60.102a(f)(1)
or 60.102a(f)(2) as appropriate.

B. The amine acid gas and sour water stripper acid gas shall be processed in the
SRU(s).

C. Compliance shall be demonstrated by daily monitoring of flows to the
SRU(s). Continuous monitoring of SO2 concentration in the exhaust stream
shall be conducted via CEM as outlined in IX.H.1.f above. Compliance shall be determined on a rolling 30-day average.

iv. No Burning of Liquid Fuel Oil in Stationary Sources

A. No petroleum refineries in or affecting any PM2.5 nonattainment area or any
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
in standby or emergency equipment is exempt from the limitation
of IX.H.1.g.iv.A above.

v. Requirements on Hydrocarbon Flares.
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A. All hydrocarbon flares at petroleum refineries located in or affecting any PM2.5
nonattainment area or any PM10 nonattainment or maintenance 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. No later than January 1, 2019, all major source petroleum refineries in or affecting
any PM2.5 nonattainment area or an 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.
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H.2 Source Specific Emission L imitations in Salt Lake County PM10
Nonattainment/Maintenance Area
a. Big West Oil Company

i. Source-wide PM10 Cap
No later than January 1, 2019, combined emissions of PM10 shall not exceed 1.037
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.2.a.i.B below, the default emission
factors to be used are as follows:

Natural gas:
Filterable PM10: 1.9 lb/MMscf
Condensable PM10: 5.7 lb/MMscf

Plant gas:
Filterable PM10: 1.9 lb/MMscf
Condensable PM10: 5.7 lb/MMscf

Fuel Oil: The PM10 emission factor shall be determined from the latest edition
of AP-42 or other EPA-approved methods.

Cooling Towers: The PM10 emission factor shall be determined from
the latest edition of AP-42 or other EPA-approved methods.

FCC Stacks: The PM10 emission factor 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.2.a.i.A above apply until such time
as stack testing is conducted as provided in IX.H.1.e or as outlined below:

PM10 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.1.e.

C. Compliance with the source-wide PM10 Cap shall be determined for each
day as follows:
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Total 24-hour PM10 emissions for the emission points shall be calculated by
adding the daily results of the PM10 emissions equations listed below for natural
gas, plant gas, and fuel oil combustion. These emissions shall be added to the
emissions from the cooling towers, and the FCCs to arrive at a combined daily
PM10 emission total.

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

Daily 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: 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 PM10 emissions from the FCC shall be calculated using the following
equation:

E = FR * EF

Where:
E = Emitted PM10
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.2.a.ii.B below, the default
emission factors to be used are as follows:
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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.2.a.ii.A above apply until such time
as stack testing is conducted as provided in IX.H.1.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:

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.2.a.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.1.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.
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For purposes of this subsection a “day” is defined 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 0.60
tons per day (tpd) 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.1.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.1.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 lb S)

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 and plant fuel gas combustion, to those from the FCC
and SRU stacks.

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The daily SOx emission 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.

For purposes of this subsection a “day” is defined 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
CEM readings for H2S (averaged for each day), 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.

iv. 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. 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.

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 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.
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b. Bountiful City Light and Power: Power Plant
i. Emissions to the atmosphere shall not exceed the following rates and
concentrations:
A. GT #1 (5.3 MW Turbine)
Exhaust Stack: 0.6 g NOx / kW-
hr

B. GT #2 and GT #3 (each TITAN Turbine) Exhaust Stack: 7.5 lb NOx / hr

ii. Compliance to the above emission limitations shall be determined by stack test.
Stack testing shall be performed as outlined in IX.H.1.e.

A. Initial stack tests have been performed. Each turbine shall be tested at least
once per year.

iii. Combustion Turbine Startup / Shutdown Emission Minimization Plan

A. Startup begins when natural gas is supplied to the combustion turbine(s) with the
intent of combusting the fuel to generate electricity. Startup conditions end within
sixty (60) minutes of natural gas being supplied to the turbine(s).

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

C. Periods of startup or shutdown shall not exceed two (2) hours per
combustion turbine per day.
c. Central Valley Water Reclamation Facility: Wastewater Treatment Plant
i. NOx emissions from the operation of all engines at the plant shall not exceed 0.648
tons per day.

ii. Compliance with the emission limitation shall be determined by summing the
emissions from all the engines. Emission from each engine shall be calculated from
the following equation:

Emissions (tons/day) = (Power production in kW-hrs/day) x
(Emission factor in grams/kW- hr) x (1 lb/453.59 g) x (1
ton/2000 lbs)

A. Stack tests shall be performed in accordance with IX.H.1.e. Each engine
shall be tested at least every three years from the previous test.

B. The NOx emission factor for each engine shall be derived from the most recent
stack test.
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C. NOx emissions shall be calculated on a daily basis.

D. A day is equivalent to the time period from midnight to the
following midnight.

E. The number of kilowatt hours generated by each engine shall be determined
by examination of electrical meters, which shall record electricity
production on a continuous basis.
d. Chevron Products Company

i. Source-wide PM10 Cap
No later than January 1, 2019, combined emissions of PM10 shall not exceed 0.715
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.2.d.i.B below, the default emission
factors to be used are as follows:

Natural gas:
Filterable PM10: 1.9 lb/MMscf
Condensable PM10: 5.7 lb/MMscf

Plant gas:
Filterable PM10: 1.9 lb/MMscf
Condensable PM10: 5.7 lb/MMscf

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.

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

FCC Stack:
The PM10 emission factors shall be based on the most recent stack test and verified
by parametric monitoring as outlined in IX.H.1.g.i.B.III
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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.2.d.i.A above apply until such time
as stack testing is conducted as provided in IX.H.1.e or as outlined below:

Initial PM10 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.1.e.

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

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

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

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:
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.

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.2.d.ii.B below, the default emission factors to be used are as follows:

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Natural gas: shall be determined from the latest edition of AP-42 Plant gas:
assumed equal to natural gas or other EPA-approved methods.

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.2.d.ii.A above apply until such time as
stack testing is conducted as provided in IX.H.1.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. Stack testing shall be
performed as outlined in IX.H.1.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.1.f.

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

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

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

Results shall be tabulated for each day, and records shall be kept which include the
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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 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.1.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.1.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 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.
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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.

iv. 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).

C. Plant coke may be burned in the FCC Catalyst Regenerator.

v. 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 (3)
years from the date of the last stack test thereafter. Stack testing shall be
performed as outlined in IX.H.1.e.

vi. Flare Calculation

A. Chevron’s Flare #3 receives gases from its Isomerization unit, Reformer unit as well as its HF
Alkylation Unit. The HF Alkylation Unit’s flow contribution to Flare #3 will not be included in
determining compliance with the flow restrictions set in IX.H.1.g.v.B

i. 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)
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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)
e. 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, 14, 15, or 16, the
line’s baghouse(s) shall be started and remain in operation
duringproduction.
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.
19
f. Holly Refining and Marketing Company

i. Source-wide PM10 Cap
No later than January 1, 2019, PM10 emissions from all sources shall not exceed
0.416 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.2.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
PM10/MMscf NSPS combustion equipment: 0.52 lb
PM10/MMscf

Fuel oil:
The filterable PM10 emission factor for fuel oil combustion shall be determined
based on the sulfur content of the oil as follows:

PM10 (lb/1000 gal) = (10 * wt. % S) + 3.22

The condensable PM10 emission factor for fuel oil combustion shall be
determined from the latest edition of AP-42.

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

FCC Wet Scrubbers:
The PM10 emission factors shall be based on the most recent stack test and
verified by parametric monitoring as outlined in IX.H.1.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.1.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.2.f.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
20
later than January 1, 2019 and 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: lb PM10/MMBtu shall be derived. Stack testing shall be performed as
outlined in
IX.H.1.e.

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

Total 24-hour PM10 emissions for the emission points shall be calculated by adding
the daily results of the PM10 emissions equations listed below for natural gas, plant
gas, and fuel oil combustion. These emissions shall be added to the emissions
from the cooling towers and wet scrubbers to arrive at a combined daily PM10
emission total.

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

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

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

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

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

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

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:
21

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.2.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
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.2.f.ii.A above apply until such time
as stack testing is conducted as outlined in IX.H.1.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 combustion
listed below. For purposes of this subsection a “day” is defined as a period of 24- hours
commencing at midnight and ending at the following midnight.

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

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

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

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

Emissions (tons/day) = Emission Factor (lb/MMscf) * Plant Gas
Consumption (MMscf/day)/(2,000 lb/ton)
22

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.1.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 of this subsection a “day” is defined as a period of 24-hours commencing at
23
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.

iv. 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 Boilers 8&11:
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
24
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)
g. 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. T o m i n i m i z e f u g i t i v e d u s t o n r o a d s 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 free zing 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. To minimize emissions at the mine, the owner/operator shall:

I. Control emissions from the in-pit crusher with
a baghouse.

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.
25
h. Kennecott Utah Copper (KUC): Power Plant and Tailings Impoundment

i. Utah Power Plant

A. Boilers #1, #2, and #3 shall not operate.

B. Unit #5 shall not exceed the following emission rates to the atmosphere:
Pollutant lb/hr lb/event ppmdv (15% O2 dry)

I. PM10 with duct firing:
Filterable + condensable

18.8
II. NOx: 2.0
Startup/shutdown 395
III. Startup / Shutdown Limitations :

1. The total number of startups and shutdowns together shall not exceed 690
per calendar year.

2. The NOx emissions shall not exceed 395 lbs from each
startup/shutdown event, which shall be determined using
manufacturer data.

3. Definitions:

(i) Startup cycle duration ends when the unit achieves half of the
design electrical generation capacity.

(ii) Shutdown duration cycle begins with the initiation of turbine
shutdown sequence and ends when fuel flow to the gas turbine is
discontinued.

C. Upon commencement of operation of Unit #5*, stack testing to demonstrate
compliance with the emission limitations in IX.H.2.h.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 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.

The limited use of natural gas during maintenance firings and break-in firings
does not constitute operation and does not require stack testing.
26
Pollutant Test Frequency

I. PM10 every year

II. NOx every year

D. The following requirements are applicable to Unit #4 annually.

I. Only natural gas shall be used as a fuel, unless the supplier or transporter
of natural gas imposes a curtailment. The power plant 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. When burning natural gas the emissions to the atmosphere from the
indicated emission point shall not exceed the following rates and
concentrations:

Pollutant grains/dscf ppmdv (3%
O2) 68oF, 29.92 in. Hg

1. PM10 Units #1, #2, #3 and #4
filterable 0.004 filterable +
condensable 0.03

2. NOx*

*NOx emissions from Unit #4 are limited to the more stringent limit
in Part H.12.k.i.

III. When using coal as a fuel during a curtailment of the natural gas supply,
emissions to the atmosphere from the indicated emission point shall not exceed
the following rates and concentrations:

Pollutant grains/dscf ppmdv (3%
O2) 68oF, 29.92 in Hg

1. Unit #4 (i) PM10
filterable 0.029
filterable +
condensable 0.29

(ii) NOx*
27

*NOx emissions from Unit #4 are limited to the more stringent limit
in Part H.12.k.i.
IV. If the units operated during the months specified above, stack testing to show
compliance with the emission limitations in H.2.h.i.D.II and III shall be
performed as follows for the following air contaminants:

Pollutant Test Frequency Initial Test

1. PM10 every year #

# Initial testing shall be performed when burning natural gas and
also when burning coal as fuel. 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.

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

E. The sulfur content of any fuel burned shall not exceed 0.66 lb of sulfur per
million BTU per test.

I. Coal increments will be collected using ASTM 2234, Type I conditions A, B,
or C and systematic spacing.

II. Percent sulfur content and gross calorific value of the coal on a dry basis
will be determined for each gross sample using ASTM D methods 2013,
3177, 3173, and 2015.

III. KUC shall measure at least 95% of the required increments in any one
month that coal is burned in Unit #4.

ii. Tailings Impoundment

A. No more than 50 contiguous acres or more than 5% of the total tailings
area shall be permitted to have the potential for wind erosion.

I. Wind erosion potential is the area that is not wet, frozen,
vegetated, crusted, or treated and has the potential for wind
erosion.

II. KUC shall conduct wind erosion potential grid inspections monthly
between February 15 and November 15. The results of the inspections
shall be used to determine wind erosion potential.
28

III. If KUC or the Director of Utah Division of Air Quality (Director)
determines that the percentage of wind erosion potential is exceeded,
KUC shall meet with the Director, to discuss additional or modified
fugitive dust controls/operational practices, and an implementation
schedule for such, within five working days following verbal notification
by either party.
B. If between February 15 and November 15 KUC’s daily weather forecast using surrounding
area meteorological data is for a wind event (a wind event is defined as wind gusts
exceeding 25 mph for more than one hour) the procedures listed below shall be
followed within 48 hours of issuance of the forecast. KUC shall:

I. Alert the Utah Division of Air Quality promptly.

II. Continue surveillance and coordination of appropriate measures.

C. KUC is subject to the requirements of the most recent federally
approved Fugitive Emissions and Fugitive Dust rules.
i. ennecott Utah Copper (KUC): Smelter & 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. PM10
a. b.

89.5 lbs/hr (filterable) 439 lbs/hr (filterable + condensable)
2. SO2
a. 552 lbs/hr (3 hr. rolling average)
b. 422 lbs/hr (daily average)
3. NOx
a. 154 lbs/hr (daily average)
II. Holman Boiler
1. NOx
a. 14.0 lbs/hr (calendar -dayaverage)

B. Stack testing to show compliance with the emissions limitations of Condition
29
(A) above shall be performed as specified below:

Emission Point Pollutant Test Frequency

I. Main Stack
(Stack No.
11)
PM10
SO2
NOx
every year
CEM
CEM
30
II. Holman Boiler NOx every three years &CEMS or
alternate method according to
NapSpPliScasbtalendards

C. 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:

I. 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

NOx

9.5 lbs/hr
Combined Heat Plant NOx 5.96 lbs/hr

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

Emission Point Pollutant Testing Frequency

Tankhouse Boilers NOx every three
years* Combined Heat Plant NOx every year
*Stack testing shall be performed on boilers that have operated at least 300
hours during a three-year period.
III. 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.
31
j. 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 ppmvd (@ 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.1.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 ppmvd (@ 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.

III. Emissions of NOx shall not exceed 168 ppmvd (@ 3% O2, dry),
applicable between November 1 and February 28/29.

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.1.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
32
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.1.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 600ºF, the stack inlet temperature reaches 570ºF, 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.
33
k. Tesoro Refining & Marketing Company

i. Source-wide PM10 Cap
No later than January 1, 2019, combined emissions of PM10 shall not exceed 2.25
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.2.k.i.B below, the default emission factors
to be used are as follows:

Natural gas:
Filterable PM10: 0.0019 lb/MMBtu
Condensable PM10: 0.0056
lb/MMBtu

Plant gas:
Filterable PM10: 0.0019 lb/MMBtu
Condensable PM10: 0.0056
lb/MMBtu

Fuel Oil: The PM10 emission factor shall be determined from the latest edition
of AP-42 or other EPA-approved methods.

Cooling Towers: The PM10 emission factor shall be determined from the
latest edition of AP-42 or other EPA-approved methods.

FCC Wet Scrubber:
The PM10 emission factors shall be based on the most recent stack test and
verified by parametric monitoring as outlined in IX.H.1.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.2.k.i.A above apply until such time
as stack testing is conducted as provided in IX.H.1.e or as outlined below:

Initial PM10 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.1.e.

Results from any stack testing performed at any other PM10 sources in accordance
34
with IX.H.1.e shall be used where available.

C. Compliance with the Source-wide PM10 Cap shall be determined for each
day as follows:
Total 24-hour PM10 emissions for the emission points shall be calculated by adding
the daily results of the PM10 emissions equations listed below for natural gas, plant
gas, and fuel oil combustion. These emissions shall be added to the emissions
from the cooling towers and wet scrubber to arrive at a combined daily PM10
emission total. For purposes of this subsection a “day” is defined as a period of 24- hours
commencing at midnight and ending at the following midnight.

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

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 unit by the associated emission factor and
summing the results.

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.2.k.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.2.k.ii.A above apply until such time
as stack testing is conducted as provided in IX.H.1.e or as outlined below:

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
35
once every three (3) years following the date of the last test. 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.1.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.1.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.

For purposes of this subsection a “day” is defined 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, 20 19, 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
36
lb/MMBtu
Diesel fuel: shall be determined from the latest edition of AP-42

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, and SRU.

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.1.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.1.g.ii.A, sources may reduce the
H2S 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
37
emissions monitoring requirements of 40 CFR 60.107a and the related
recordkeeping and reporting requirements of 40 CFR 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.

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

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

C. 0.69 tpd for the remainder of the rolling 12-month period.
D. 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.1.f

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.

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)
38

l. University of Utah: University of Utah Facilities

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

Emission Point Pollutant ppmdv (3% O2
dry)
A. Boiler #4* NOx 187
B. Boilers #6 & #7. NOx 9

C. Boilers #9*.

NOx

9
D. Turbine NOx 9
E. Turbine and WHRU Duct burner

NOx

15

*By December 31, 2019, Boiler #4 will be decommissioned and Boiler #9 will
be installed and operational.

ii. Testing to show compliance with the emissions limitations of Condition i above
shall be performed as specified below:

Emission Point Pollutant Initial Test Test Frequency

A. Boiler #4

NOx

*

#
B. Boilers #6 & #7 NOx 2018 #
C. Boilers #9 NOx 2020 #

D. Turbine

NOx

*

#
E. Turbine and WHRU
Duct burner

NOx

*

#

* Initial tests have been performed and the next method test using EPA
approved test methods shall be performed within three (3) years of the last
stack test.

# 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
39
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. Beginning January 2018, annual screening with a portable monitor
must be conducted in those years that a compliance test is not performed.
Screening with a portable monitor shall be performed in accordance with the
portable monitor manufacturer’s specifications. If screening with a portable monitor
indicates a potential exceedance of the concentration limit, a
compliance test must be performed within 90 days of that screening. Records
shall be kept on site which indicate the date, time, and results of each screening
and demonstrate that the potable monitor was operated in accordance with
manufacturer's specifications.
m. Utah Municipal Power Association: West Valley Power Plant.

i. Total emissions of NOx from all five (5) 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 5ppmdv (@ 15% O2, dry) on a 30-day
rolling average.

iii. Total emissions of NOx from all five (5) 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.1.f
40
H.3 Source Specific Emission Limitations in Utah County PM10 Nonattainment/Maintenance Area
a. Brigham Young University: Main Campus

i All central heating plant units shall operate on natural gas from November 1 to February
28 each season beginning in the winter season of 2013-2014. Fuel oil may be used as backup fuel
during periods of natural gas curtailment. The sulfur content of the fuel oil shall not exceed 0.0015
% by weight. BYU must maintain a fuel specification certification document from the fuel supplier
with the sulfur content guarantee. Alternatively, sulfur content may be verified through testing
completed by BYU or the fuel supplier using ASTM Method D-4294-10 or EPA approved equivalent
acceptable to the Director.

ii. Emissions to the atmosphere from the indicated emission point shall not exceedthe
following rates and concentrations:

Emission Point Pollutant ppm (7% O2 dry)* lb/hr

A. Unit #1 NOx 95 36 9.55 5.44
B. Unit #4 NOx 127 36 38.5 19.2
C. Unit #6 NOx 127 36 38.5 19.2

* Unit #1 NOx limit is 95 ppm (9.55 lb/hr) until it operates for more than 300 hours during a rolling 12-month period, then the limit will be 36
ppm (5.44 lb/hr). The NOx limit for units #4 and #6 is 127 ppm (38.5 lb/hr) and starting
on December 31, 2018, the limit will then be 36 ppm (19.2 lb/hr).

Emission Point Pollutant ppm (7% O2 dry) lb/hr
D. Unit #2 NOx 331 37.4
SO2 597 56.0
E. Unit #3 NOx 331 37.4
SO2 597 56.0
F. Unit #5 NOx 331 74.8
SO2 597 112.07

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

Emission Point Pollutant Initial test Test Frequency
A. Unit #1 NOx & every year*
B. Unit #2 NOx # every year*
C. Unit #3 NOx # every year*
D. Unit #4 NOx # every year*
E. Unit #5 NOx # every year*
F. Unit #6 NOx # every year*
41
Stack tests shall be performed in accordance with IX.H.1.e.

& If Unit #1 is operated for more than 100 hours per rolling 12-month period, the stack test shall be
performed within 60 days of exceeding 100 hours of operations. Unit #1 shall only be operated as a back-up boiler to Units #4 and #6 and shall not be operated more than 300 hours per rolling 12-
month period. If Unit #1 operates more than 300 hours per rolling 12-month period, then low NOx
burners with Flue Gas Recirculation shall be installed and tested within 18 months of exceeding 300
hours of operation and the maximum NOx concentration shall be 36 ppm.

# The test shall be performed at least every 3 years based on the date of the
last stack test. Units #4 and #6 shall be retested by March 1, 2018.

* 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. Beginning January 2018, annual screening with a
portable monitor must be conducted in those years that a compliance test is not performed. Screening
with a portable monitor shall be performed in
accordance with the portable monitor manufacturer’s specifications. If
screening with a portable monitor indicates a potential exceedance of the concentration limit, a
compliance test must be performed within 90 days of that screening. Records shall be kept on site
which indicate the date, time, and results of each screening and demonstrate that the potable monitor
was operated in accordance with manufacturer's specifications.

iv. Central Heating Plant Coal-Fired Boilers

A. Startup and shutdown events shall not exceed 216 hours per boiler per 12-month rolling period.

B. The sulfur content of any coal or any mixture of coals burned shall not exceed either of
the following:

I. 0.54 pounds of sulfur per million BTU heat input as determined by
ASTM Method D-4239-85, or EPA-approved equivalent acceptable to the Director.

II. 0.60% by weight as determined by ASTM Method D-4239-85, or EPA-
approved equivalent acceptable to the Director.

For the sulfur content of coal, Brigham Young University shall either:

III. Determine the weight percent sulfur and the fuel heating value by submitting a coal sample to a
laboratory, acceptable to the Director, on no less than a monthly basis; or

IV. For each delivery of coal, inspect the fuel sulfur content expressed as weight
% determined by the vendor using methods of the ASTM; or
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V. For each delivery of coal, inspect documentation provided by the vendor that indirectly
demonstrates compliance with this provision.
b. Geneva Nitrogen Inc.: Geneva Nitrogen Plant i.

Prill Tower:

PM10 emissions (filterable and condensable) shall not exceed 0.236 ton/day
PM2.5 emissions (filterable and condensable) shall not exceed 0.196 ton/day
A day is defined as from midnight to the following midnight.
ii. Testing
A. Stack testing shall be performed as specified below:

I. Frequency: Emissions shall be tested every three years. The test shall be
performed as soon as possible and in no case later than December 31, 2017.

B. The daily limit shall be calculated by multiplying the most recent stack test results by the
appropriate hours of operation for each day.

iii. Montecatini Plant:

NOx emissions shall not exceed 30.8 lb/hr
iv. Weatherly Plant:
NOx emissions shall not exceed 18.4 lb/hr v. Testing

A. Stack testing for NOx shall be performed as specifiedbelow:
I. Stack testing to show compliance with the NOx emission limitations shall be performed as
specified below:

1. Testing and Frequency. Emissions shall be tested every three years using an EPA
approved test method.

II. NOx concentration (ppmdv) shall be used as an indicator to provide a reasonable assurance of compliance with the NOx emission limitation as specifiedbelow:

1. Measurement Approach: NOx concentration (ppmdv) shall be determined by using a continuous
NOx monitoring system.

2. Performance Criteria:
i. QA/QC Practices and Criteria: The continuous monitoring system shall be operated, calibrated,
and maintained in accordance with manufacture's recommendations. Zero and span drift tests shall be
conducted on a daily basis.

47 of 115
III. The EPA approved method test for the Montecatini Plant shall be performed as soon as possible and
in no case later than December 31, 2017, and the test for the Weatherly Plant shall be performed as soon
as possible and in no case later than December 31, 2018.

vi. Start-up/Shut-down

A. Startup / Shutdown Limitations:

I. Planned shut-down and start-up events shall not exceed 50 hours per acid
plant (Montecatini or Weatherly) per 12-month rolling period.

II. Total startup and shutdown events shall not exceed four hours per acid plant in any one calendar
day.
c. PacifiCorp Energy: Lake Side Power Plant

i. Block #1 Turbine/HRSG Stacks:

A. Emissions of NOx shall not exceed 14.9 lb/hr on a 3-hr average basis
B. Compliance with the above conditions shall be demonstrated as follows:
I. NOx monitoring shall be through use of a CEM as outlined in IX.H.1.f
ii. Block #2 Turbine/HRSG Stacks:

A. Emissions of NOx shall not exceed 18.1 lb/hr on a 3-hr average basis
B. Compliance with the above conditions shall be demonstrated as follows:
I. NOx monitoring shall be through use of a CEM as outlined in IX.H.1.f
iii. Startup / Shutdown Limitations:

A. Block #1:

I. Startup and shutdown events shall not exceed 613.5 hours per turbine per 12-
month rolling period.

II. Total startup and shutdown events shall not exceed 14 hours per turbine in any one calendar day.

III. Cumulative short-term transient load excursions shall not exceed 160 hours per 12- month
rolling period.

IV. During periods of transient load conditions, NOx emissions from the Block #1 Turbine/HRSG Stacks shall not exceed 25 ppmvd at 15% O2.
B. Block #2:

I. Startup and shutdown events shall not exceed 553.6 hours per turbine per 12-
month rolling period.
47 of 115

II. Total startup and shutdown events shall not exceed 8 hours per turbine in any one calendar day.

III. Cumulative short-term transient load excursions shall not exceed 160 hours per 12- month
rolling period.

IV. During periods of transient load conditions, NOx emissions from the Block #2 Turbine/HRSG Stacks shall not exceed 25 ppmvd at 15% O2.
C. Definitions:
I. Startup is defined as the period beginning with turbine initial firing until the
unit meets the lb/hr emission limits listed in IX.H.3.c.i and ii above.

II. Shutdown is defined as the period beginning with the initiation of turbine shutdown sequence and
ending with the cessation of firing of the gas turbine engine.
III. Transient load conditions are those periods, not to exceed four consecutive 15- minute
periods, when the 15-minute average NOx concentration exceeds 2.0 ppmv dry @ 15% O2.
Transient load conditions consist of the following:

1. Initiation/shutdown of combustion turbine inlet air-cooling.

2. Rapid combustion turbine load changes.

3. Initiation/shutdown of HRSG duct burners.
4. Provision of Ancillary Services and Automatic Generation Control. IV. For purposes
of this subsection a “day” is defined as a period of 24-hours
commencing at midnight and ending at the following midnight.
e. Payson City Corporation: Payson City Power

i. Emissions of NOx shall be no greater than 1.54 ton per day for all enginescombined.

ii. Compliance with the emission limitation shall be determined by summing the emissions from
all the engines. Emission from each engine shall be calculated from the following equation:

Emissions (tons/day) = (Power production in kW-hrs/day) x (Emission factor in
grams/kW- hr) x (1 lb/453.59 g) x (1 ton/2000 lbs)

A. The NOx emission factor for each engine shall be derived from the most recent stack test.
Stack tests shall be performed in accordance with IX.H.1.e. Each engine shall be tested at least
every three years from the previous test.

B. NOx emissions shall be calculated on a dailybasis.

C. A day is equivalent to the time period from midnight to the following midnight.

D. The number of kilowatt hours generated by each engine shall be recorded on a daily basis
47 of 115
with an electrical meter.
f. Provo City Power: Power Plant

i. NOx emissions from the operation of all engines at the plant shall not exceed 2.45 tons
per day.

ii. Compliance with the emission limitation shall be determined by summing the emissions from
all the engines. Emission from each engine shall be calculated from the following equation:

Emissions (tons/day) = (Power production in kW-hrs/day) x (Emission factor in
grams/kW- hr) x (1 lb/453.59 g) x (1 ton/2000 lbs)

A. The NOx emission factor for each engine shall be derived from the most recent stack test. Stack tests shall be performed in accordance with IX.H.1.e. Each engine shall be tested every 8,760 hours
of operation or at least every three years from the previous test, whichever occurs first.

B. NOx emissions shall be calculated on a dailybasis.

C. A day is equivalent to the time period from midnight to the following midnight.

D. The number of kilowatt hours generated by each engine shall be recorded on a daily basis
with an electrical meter.
g. Springville City Corporation: Whitehead Power Plant

i. NOx emissions from the operation of all engines at the plant shall not exceed 1.68 tons per day.

ii. Internal combustion engine emissions shall be calculated from the operating data recorded by the
CEM. CEM will be performed in accordance with IX.H.1.f. A day is equivalent to the time period
from midnight to the following midnight. Emissions shall be calculated for NOx for each individual engine by the following equation:

D = (X * K)/453.6

Where: X = grams/kW-hr rate for each generator (recorded by CEM)
K = total kW-hr generated by the generator each day (recorded by output
meter) D = daily output of pollutant in lbs/day
46
H.4 Interim Emission Limits and Operating Practices

a. The terms and conditions of this Subsection IX.H.4 shall apply to the sources listed in this
section on a temporary basis, as a bridge between the 1991 PM10 State Implementation Plan and
this PM10 Maintenance Plan. For all other point sources listed in IX.H.2 and IX.H.3 the limits
apply upon approval by the Utah Air Quality Board of the PM10 Maintenance Plan. These bridge
requirements are needed to impose limits on the sources that have time delays for
implementation of controls. During this timeframe, the sources listed in this section may not meet the established limits listed in IX.H.1 and IX.H.2. As the control technology for the
sources listed in this section is installed and operational, the terms and conditions listed in
IX.H.1 and IX.H.2 become applicable and those limits replace the limits in this subsection. In
no case, shall the terms and conditions listed in this Subsection IX.H.4 extend beyond
January 1, 2019.

b. Petroleum Refineries:

i. All petroleum refineries in or affecting the PM10 nonattainment/maintenance area shall, for
the purpose of this PM10 Maintenance Plan:

A. Achieve an emission rate equivalent to no more than 9.8 kg of SO2 per 1,000 kg of coke burn- off from any Catalytic Cracking unit by use of low-SOx catalyst
or equivalent emission reduction techniques or procedures, including those outlined in 40 CFR 60, Subpart J. Unless otherwise specified in IX.H.2, compliance shall
be determined for each day based on a rolling seven-day average.

B. Compliance Demonstrations.

I. Compliance with the maximum daily (24-hr) plant-wide emission limitations
for PM10, SO2, and NOx shall be determined by adding the calculated
emission estimates for all fuel burning process equipment to those from any
stack-tested or CEM-measured source components. NOx and PM10 emission
factors shall be determined from AP-42 or from test data.

For SOx, the emission factors are:

Natural gas: EF = 0.60
lb/MMscf Propane: EF = 0.60
lb/MMscf
Plant gas: the emission factor shall be calculated from the H2S measurement
required in IX.H.1.g.ii.A.

Fuel oils (when permitted): The emission factor 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:

EF (lb SO2/k gal) = density (lb/gal) * (1000 gal/k gal) * wt.% S/100 *
(64 lb SO2/32 lb S)
47
Where mixtures of fuel are used in an affected unit, the above factors shall be
weighted according to the use of each fuel.
II. Daily emission estimates for stack-tested source components shall be made by
multiplying the latest stack-tested hourly emission rate times the logged hours
of operation (or other relevant parameter) for that source component for each
day. This shall not preclude a source from determining emissions through the
use of a CEM that meets the requirements of R307-170.
c. Big West Oil Company
i. PM10 Emissions
A. Combined emissions of filterable PM10 from all external combustion process
equipment shall not exceed the following:

I. 0.377 tons per day, between October 1 and March 31;

II. 0.407 tons per day, between April 1 and September 30.

B. Emissions shall be determined for each day by multiplying the appropriate emission
factor from section IX.H.4.b.i.B by the relevant parameter (e.g. hours of
operation, feed rate, or quantity of fuel combusted) at each affected unit, and
summing the results for the group of affected units.

The daily primary PM10 contribution from the Catalyst Regeneration System
shall be calculated using the following equation:

Emitted PM10 = (Feed rate to FCC in kbbl/time) * (22 lbs/kbbl)

wherein the emission factor (22 lbs/kbbl) may be re-established by stack testing.
Total 24-hour PM10 emissions shall be calculated by adding the daily emissions from
the external combustion process equipment to the estimate for the Catalyst
Regeneration System.

ii. SO2 Emissions

A. Combined emissions of sulfur dioxide from all external combustion process
equipment shall not exceed the following:

I. 2.764 tons/day, between October 1 and March 31;

II. 3.639 tons/day, between April 1 and September 30.

B. Emissions shall be determined for each day by multiplying the appropriate emission
factor from section IX.H.4.b.i.B by the relevant parameter (e.g. hours of
operation, feed rate, or quantity of fuel combusted) at each affected unit, and
48
summing the results for the group of affected units.

The daily SO2 emission from the Catalyst Regeneration System shall
be calculated using the following equation:

SO2 = [43.3 lb SO2/hr / 7,688 bbl feed/day] x [(operational feed rate in
bbl/day) x (wt% sulfur in feed / 0.1878 wt%) x (operating hr/day)]
The FCC feed weight percent sulfur concentration shall be determined by the
refinery laboratory every 30 days with one or more analyses. Alternatively,
SO2 emissions from the Catalyst Regeneration System may be determined
using a Continuous Emissions Monitor (CEM) in accordance with
IX.H.1.f.

Emissions from the SRU Tail Gas Incinerator (TGI) shall be determined for each
day by multiplying the sulfur dioxide concentration in the flue gas by the mass flow
of the flue gas.

Total 24-hour SO2 emissions shall be calculated by adding the daily emissions
from the external combustion process equipment to the values for the
Catalyst Regeneration System and the SRU.

iii. NOx Emissions

A. Combined emissions of NOx from all external combustion process equipment shall
not exceed the following:

I. 1.027 tons per day, between October 1 and March 31;

II. 1.145 tons per day, between April 1 and September 30.

B. Emissions shall be determined for each day by multiplying the appropriate
emission factor from section IX.H.4.b.i.B by the relevant parameter (e.g. hours
of operation, feed rate, or quantity of fuel combusted) at each affected unit,
and summing the results for the group of affected units.

The daily NOx emission from the Catalyst Regeneration System shall be calculated
using the following equation:

NOx = (Flue Gas, moles/hr) x (180 ppm /1,000,000) x (30.006 lb/mole) x
(operating hr/day)

wherein the scalar value (180 ppm) may be re-established by stack testing.
49
Alternatively, NOx emissions from the Catalyst Regeneration System may be
determined using a Continuous Emissions Monitor (CEM) in accordance
with IX.H.1.f.

Total 24-hour NOx emissions shall be calculated by adding the daily emissions
from gas-fired compressor drivers and the external combustion process equipment
to the value for the Catalyst Regeneration System.
d. Chevron Products Company

i. PM10 Emissions

A. Combined emissions of filterable PM10 from all external combustion process
equipment shall be no greater than 0.234 tons per day.

Emissions shall be determined for each day by multiplying the appropriate
emission factor from section IX.H.4.b.i.B by the relevant parameter (e.g. hours
of operation, feed rate, or quantity of fuel combusted) at each affected unit,
and summing the results for the group of affected units.

ii. SO2 Emissions

A. Combined emissions of sulfur dioxide from gas-fired compressor drivers and
all external combustion process equipment, including the FCC CO Boiler
and Catalyst Regenerator, shall not exceed 0.5 tons/day.

Emissions shall be determined for each day by multiplying the appropriate
emission factor from section IX.H.4.b.i.B by the relevant parameter (e.g. hours
of operation, feed rate, or quantity of fuel combusted) at each affected unit,
and summing the results for the group of affected units.

Alternatively, SO2 emissions from the FCC CO Boiler and Catalyst Regenerator
may be determined using a Continuous Emissions Monitor (CEM) in accordance
with IX.H.1.f.

iii. NOx Emissions

A. Combined emissions of NOx from gas-fired compressor drivers and all external
combustion process equipment, including the FCC CO Boiler and Catalyst
Regenerator and the SRU Tail Gas Incinerator, shall be no greater than 2.52
tons per day.

Emissions shall be determined for each day by multiplying the appropriate
emission factor from section IX.H.4.b.i.B by the relevant parameter (e.g. hours
50
of operation, feed rate, or quantity of fuel combusted) at each affected unit,
and summing the results for the group of affected units.

Alternatively, NOx emissions from the FCC CO Boiler and Catalyst Regenerator
may be determined using a Continuous Emissions Monitor (CEM) in accordance
with IX.H.1.f.
iv. Chevron shall be permitted to combust HF alkylation polymer oil in its
Alkylation unit.
e. Holly Refining and Marketing Company

i. PM10 Emissions

A. Combined emissions of filterable PM10 from all combustion sources, shall be no
greater than 0.44 tons per day.

Emissions shall be determined for each day by multiplying the appropriate emission
factor from section IX.H.4.b.i.B, or from testing as described below, by the relevant
parameter (e.g. hours of operation, feed rate, or quantity of fuel combusted) at each
affected unit, and summing the results for the group of affected units.

ii. SO2 Emissions

A. Combined emissions of SO2 from all sources shall be no greater than 4.714 tons
per day.

Emissions shall be determined for each day by multiplying the appropriate emission
factor from sectionIX.H.4.b.i.B by the relevant parameter (e.g. hours of operation,
feed rate, or quantity of fuel combusted) at each affected unit, and summing the
results for the group of affected units.

Emissions from the FCC wet scrubbers shall be determined using a Continuous
Emissions Monitor (CEM) in accordance with IX.H.1.f.

iii. NOx Emissions:

A. Combined emissions of NOx from all sources shall be no greater than 2.20 tons
per day.

Emissions shall be determined for each day by multiplying the appropriate emission
factor from section IX.H.4.b.i.B by the relevant parameter (e.g. hours of operation,
feed rate, or quantity of fuel combusted) at each affected unit, and summing the
results for the group of affected units.
f. Tesoro Refining & Marketing Company
51

i. PM10 Emissions

A. Combined emissions of filterable PM10 from gas-fired compressor drivers and all
external combustion process equipment, including the FCC/CO Boiler (ESP), shall be
no greater than 0.261 tons per day.

Emissions for gas-fired compressor drivers and the group of external combustion
process equipment shall be determined for each day by multiplying the appropriate
emission factor from section IX.H.4.b.i.B by the relevant parameter (e.g. hours
of operation, feed rate, or quantity of fuel combusted) at each affected unit, and
summing the results for the group of affected units.

ii. SO2 Emissions

A. Combined emissions of SO2 from gas-fired compressor drivers and all external
combustion process equipment, including the FCC/CO Boiler (ESP), shall not
exceed the following:

I. November 1 through end of February: 3.699 tons/day.

II. . March 1 through October 31: 4.374 tons/day.

Emissions shall be determined for each day by multiplying the appropriate emission
factor from section IX.H.4.b.i.B by the relevant parameter (e.g. hours of operation,
feed rate, or quantity of fuel combusted) at each affected unit, and summing the
results for the group of affected units.

Emissions from the ESP stack (FCC/CO Boiler) shall be determined by multiplying
the SO2 concentration in the flue gas by the mass flow of the flue gas.

The SO2 concentration in the flue gas shall be determined by a continuous
emission monitor (CEM).

iii. NOx Emissions

A. Combined emissions of NOx from gas-fired compressor drivers and all
external combustion process equipment shall be no greater than 1.988 tons
per day.

Emissions shall be determined for each day by multiplying the appropriate emission
factor from section IX.H.4.b.i.B by the relevant parameter (e.g. hours of operation,
feed rate, or quantity of fuel combusted) at each affected unit, and summing the