DAQ-2025-001223

52
results for
the group of affected units.
H.11. General Requirements: Control Measures for Area and Point
Sources, Emission L imits 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.

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.

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
53
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
54
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
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 inaccordance
with IX.H.11.f.
55

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
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 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.

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.
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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.

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.

57
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 in standby
or emergency equipment is exempt from the limitation of IX.H.11.g.vii.A
above.

h. Catalytic Oxidation for VOC Control

i. Internal Combustion Engines

A. Emissions from each VOC catalytic-controlled IC engine shall be routed through
58
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).

ii. 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.
H.12. Source-Specific Emission L imitations in Salt L ake 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.
59

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
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
60
SIP.

c. Subsequent to initial compliance testing, stack testing is
required every three years.
b. Big West Oil 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:
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.
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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 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: 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

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:
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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.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:

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.

For purposes of this subsection a “day” is defined as a period of 24-hours
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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.

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

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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 readings (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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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-
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.
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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

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
131
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.

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: 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.

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
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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.

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.

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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 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
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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.

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 years
thereafter. Stack testing shall be performed as outlined in IX.H.11.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.11.g.v.B

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vii. 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)
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 UnitPM2.5 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
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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
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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.

vi. 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

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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 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:
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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 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
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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.

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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)

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

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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
of this subsection a “day” is defined as a period of 24-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
131
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.

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
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
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.
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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 +
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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
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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,
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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

NOx

9.5 lbs/hr (before December 2020)
(Upgraded
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

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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.
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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.
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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

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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: 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
131
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. 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 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:
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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.

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.
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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
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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 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:

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

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
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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.
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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,
andmaintenance.

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* NOx 187 B .
Boiler1s)#6 & 7
C.B.
NOx 9
Boiler2)#9* NOx 9
.C
Turbin3e)

NOx

9
.D
131
Turbin4e) and WHRU Duct burner NOx 15

*By DecembE.er 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
DTurbine
.
ETurbine and WHRU
Duc.t Burner

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.

NOx

NOx
2020

*
#

#
NOx * #
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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.
H.13 Source-Specific Emission Limitations in Provo – UT PM2.5
Nonattainment 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 exceed the
following rates and concentrations:
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Emission Point Pollutant ppm (7% O2 dry) * lb/hr

* 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*
& 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.

# 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
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
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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

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

A. 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

V. For each delivery of coal, inspect documentation provided by the vendor that indirectly
demonstrates compliance with this provision.
v. Central Heating Plant Boilers

A. Records shall be kept on site which indicate the date, and time of startup and shutdown.
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.
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B. The daily and rolling 12-month mass emissions shall be calculated by multiplying the most
recent stack test results by the appropriate hours of operation for each day and for each rolling
12- month period.

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 specified below:
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 specified below:
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.

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.

131
II. Total startup and shutdown events shall not exceed four hours per acid plant in any
one calendar day.
c. McWane Ductile - Utah

i. Emissions of VOC from the finishing paint line shall not exceed 1 ton/day.

A. Compliance with the above conditions shall be demonstrated as follows: VOC emissions at
the finishing paint line shall be determined by asphalt paint consumption. Asphalt
paint consumption shall be monitored by liquid level monitoring sensors on the finishing
paint line bulk tanks.

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

ii. The Annealing Oven furnaces are limited to 63.29 MMBtu/hr.

iii. Emissions from the desulfurization and ductile treatment system shall be routed through the
operating baghouse prior to be emitted into the atmosphere.

iv. Emissions from the Special Lining Shotblast operations shall be routed through the operating
baghouse prior to being emitted into the atmosphere.
d. PacifiCorp Energy: Lake Side Power Plant

i. Block #1 Catalytic-controlled 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.11.f

ii. Block #2 Catalytic-controlled 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.11.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.
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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 Catalytic-controlled 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.

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 Catalytic-controlled 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.13.d.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 engines combined.
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:

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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.11.e. Each engine shall be
tested at least every three years from the previous test.

B. NOx emissions shall be calculated on a daily basis.
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.

iii. All engines shall be catalytic-controlled as outlined in IX.H.11.h.
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.11.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 daily basis.
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.

iii. All engines shall be catalytic-controlled as outlined in IX.H.11.h.
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 as outlined in IX.H.11.f. A day is equivalent to the time period from midnight to the following midnight. Emissions of NOx shall be calculated for each individual engine by the following equation:

D = (X * K)/453.6
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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
iii. All engines shall be catalytic-controlled as outlined in IX.H.11.h.
H.21. General Requirements: Control Measures for Area and Point Sources, Emission Limits
and Operating Practices, Regional Haze Requirements
a. Except as otherwise outlined in individual conditions of this Subsection IX.H.21 listed
below, the terms and conditions of this Subsection IX.H.21 shall apply to all sources
subsequently addressed in Subsection IX.H.22. Should any inconsistencies exist
between these two subsections, the source specific conditions listed in IX.H.22
shall take precedence.
b. The definitions contained in R307-101-2, Definitions and R307-170-4,
Definitions, apply to Section IX, Part H. In addition, the following definition also
applies to Section IX, Part H.21 and 22:
Boiler operating day means a 24-hour period between 12 midnight and the following
midnight during which any fuel is combusted at any time in the boiler. It is not
necessary for fuel to be combusted for the entire 24-hour period.
c. The terms and conditions of R307-107-1 and R307-107-2 shall apply to
all sources subsequently addressed in Subsection IX.H.22.
d. 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. All
records required by IX.H.21.c shall be kept for a minimum of five years. Any or all of