DAQ-2024-008065

1/23/24, 11:31 AM State of Utah Mail - Big West Oil Serious Ozone Nonattainment Area RACT Analysis Submission
https://mail.google.com/mail/u/0/?ik=539c285453&view=pt&search=all&permthid=thread-f:1787010517076705329&simpl=msg-f:17870105170767053…1/1
Ana Williams <[e-mail]>
Big West Oil Serious Ozone Nonattainment Area RACT Analysis Submission
1 message
Russell Eric Simdorn <[e-mail]>Tue, Jan 2, 2024 at 1:07 PM
To: "[e-mail]" <[e-mail]>, "[e-mail]" <[e-mail]>
Cc: Faithe Schwartzengraber <[e-mail]>
Dear Bryce Bird and Ana Williams,

Please see the attached RACT Analysis Submission for the Serious Ozone Nonattainment Area in accordance with the DAQ letter
DAQP-042-23. I have also submitted a physical copy via certified mail to your address.

Feel free to contact me anytime at the phone number below or at this email address if you would like to discuss this matter further. You
can also contact Faithe Schwartzengraber at [e-mail] or [phone].

Kind Regards,

Eric Simdorn
Environmental Engineer
Big West Oil LLC
North Salt Lake Refinery
C: 806.335.6595
O: 385.324.1256
[e-mail]

Big West Oil 2024 Ozone SIP RACT Analysis .pdf
2147K

Big West Oil Refinery
Reasonably Available Control Technology (RACT)
Evaluation – Utah Ozone State Implementation Plan
North Salt Lake City, Utah

January 2024

Big West Oil, LLC
333 W Center St.
North Salt Lake, UT 84054

ii

LIST OF ACRONYMS AND ABBREVIATIONS

AFM Additional Feasible Measures
BACT Best Available Control Technology
BWO Big West Oil
CFR Code of Federal Regulations
DGS dry gas scrubber
EF emission factor
EFR external floating roof
EPA Environmental Protection Agency
ESP electrostatic precipitator
FCCU Fluid Catalytic Cracking Unit
FGF flue gas blowback filter
FGR flue gas recirculation
H2S hydrogen sulfide
HDS hydrodesulfurization
hp horsepower
hr hour
IFR internal floating roof
LAER lowest achievable emission rate
lb pound
LDAR Leak Detection and Repair Program
LLC Limited Liability Company
LNB low-NOX burner
MACT maximum achievable control technology
mg milligram
MMBtu million British thermal units MMSCF million standard cubic feet
MSCC millisecond catalytic cracker
MSM Most Stringent Measures
N no
N/A not applicable
NAAQS National Ambient Air Quality Standards
NH3 ammonia
NOX nitrogen oxides
NSPS New Source Performance Standard
O2 oxygen
PM2.5 particulate matter 2.5 microns or less in diameter
ppm parts per million
ppmv parts per million volume
iii

RACT Reasonably Available Control Technology
RBLC RACT/BACT/LAER Clearinghouse
SBAPCD Santa Barbara Air Pollution Control District
SCR selective catalytic reduction
SIP State Implementation Plan
SJUVAPCD San Joaquin Unified Valley Air Pollution Control District
SNCR selective non-catalytic reduction
SO2 sulfur dioxide
SOX sulfur oxides
SWS sour water stripper
tpy tons per year
UDAQ Utah Department of Environmental Quality, Division of Air Quality
UOP company and brand name
VOC volatile organic compound
ULNB ultra-low NOX burner
VRU vapor recovery unit
WGS wet gas scrubber
Y yes

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Table of Contents
1.0 BACKGROUND ............................................................................................................... 1
2.0 APPROACH .................................................................................................................... 3
2.1 RACT ANALYSIS PROCESS .......................................................................................................... 3
2.1.1 Step 1 - Identify Control Technologies .................................................................................. 3
2.1.2 Step 2 - Eliminate Technically Infeasible Technologies ......................................................... 4
2.1.3 Task 3 - Rank Technologies by Control Effectiveness ........................................................... 4
2.1.4 Task 4 - Evaluate Most Effective Controls ............................................................................. 4
2.1.4.1 Energy Impact ................................................................................................................... 4
2.1.4.2 Environmental Impacts ..................................................................................................... 4
2.1.4.3 Cost Evaluation ................................................................................................................. 4
2.1.5 Task 5 - Recommend RACT ................................................................................................... 5
3.0 RACT EVALUATION ........................................................................................................ 6
MSCC Regenerator .................................................................................................................................... 6
3.1 MSCC REGENERATOR ................................................................................................................ 7
3.1.1 MSCC Regenerator – NOX ...................................................................................................... 7
3.1.1.1 NOX-Reducing Additive...................................................................................................... 8
3.1.1.2 Selective Catalytic Reduction ............................................................................................ 8
3.1.1.3 Selective Non-Catalytic Reduction .................................................................................... 9
3.1.1.4 Review of Technically Feasible Controls for MSCC – NOX ............................................... 10
3.1.2 MSCC Regenerator – VOC ................................................................................................... 10
3.1.2.1 CO Boiler ......................................................................................................................... 10
3.1.2.2 Wet Gas Scrubber ........................................................................................................... 10
3.1.2.3 Add-on Catalytic Control ................................................................................................. 10
3.1.2.4 Review of Technically Feasible Controls for MSCC – VOC .............................................. 10
3.2 SULFUR RECOVERY UNIT ......................................................................................................... 10
3.2.1 Sulfur Recovery Unit – NOX ................................................................................................. 10
3.2.1.1 Good Design Methods and Operating Procedures ......................................................... 11
3.2.1.2 LoTOx and Wet Gas Scrubber ......................................................................................... 11
3.2.1.3 Review of Technically Feasible Controls for SRU – NOX .................................................. 11
3.2.2 Sulfur Recovery Unit – VOC ................................................................................................. 11
3.2.2.1 Good Design Methods and Operating Procedures ......................................................... 11
3.2.2.2 Use of Natural Gas .......................................................................................................... 11
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3.2.2.3 Catalytic Oxidation .......................................................................................................... 11
3.2.2.4 Review of Technically Feasible Controls for SRU – VOC ................................................. 11
3.3 HEATERS .................................................................................................................................. 12
3.3.1 Heaters – NOX ...................................................................................................................... 12
3.3.1.1 Low NOX Burner (LNB) ..................................................................................................... 12
3.3.1.2 Ultra-Low NOX Burners (ULNB) ....................................................................................... 12
3.3.1.3 Selective Catalytic Reduction (SCR) ................................................................................ 13
3.3.1.4 Selective Non-Catalytic Reduction (SNCR) ...................................................................... 13
3.3.1.5 Flue Gas Recirculation (FGR) ........................................................................................... 14
3.3.1.6 Review of Technically Feasible Technologies for Heaters – NOX .................................... 14
3.3.2 Heaters – VOC ..................................................................................................................... 14
3.3.2.1 Catalytic Oxidation .......................................................................................................... 15
3.3.2.2 Thermal Oxidation .......................................................................................................... 15
3.3.2.3 Review of Technically Feasible Technologies for Heaters Heaters – VOC ...................... 15
3.4 BOILERS ................................................................................................................................... 15
3.4.1 Boilers – NOX ....................................................................................................................... 15
3.4.1.1 Selective Catalytic Reduction (SCR) ................................................................................ 16
3.4.1.2 Flue Gas Recirculation (FGR) ........................................................................................... 16
3.4.1.3 Selective Non-Catalytic Reduction (SNCR) ...................................................................... 16
Review of ......................................................................................................................... 16
3.4.1.4 Technically Feasible Technologies for Boilers – NOX ...................................................... 16
3.4.2 Boilers – VOC ....................................................................................................................... 17
3.4.2.1 Catalytic Oxidation .......................................................................................................... 17
3.4.2.2 Thermal Oxidation .......................................................................................................... 17
Review of ......................................................................................................................... 17
3.4.2.3 Technically Feasible Technologies for Boilers – VOC ...................................................... 17
3.5 REFINERY FLARES ..................................................................................................................... 17
3.5.1 Refinery Flares – NOX .......................................................................................................... 18
3.5.2 Refinery Flares – VOC .......................................................................................................... 18
3.6 STANDBY (EMERGENCY) ENGINES – NOX ................................................................................ 19
3.7 FUGITIVE EQUIPMENT – VOC .................................................................................................. 19
3.8 TRUCK LOADING RACK – VOC .................................................................................................. 20
3.9 RAILCAR LOADING RACK ......................................................................................................... 21
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3.9.1 RAILCAR LOADING RACK VAPOR COMBUSTION UNIT – NOX .............................................. 21
3.9.2 RAILCAR LOADING RACK – VOC .......................................................................................... 21
3.10 GROUP 1 STORAGE TANKS – VOC ........................................................................................... 21
3.10.1 IFR Tanks ............................................................................................................................. 21
3.10.2 EFR Tanks ............................................................................................................................ 22
3.10.3 RACT Evaluation .................................................................................................................. 23
3.11 GROUP 2 STORAGE TANKS – VOC ........................................................................................... 24
3.12 WASTEWATER TREATMENT SYSTEM – VOC ............................................................................ 24
3.13 COOLING TOWERS – VOC ........................................................................................................ 24
3.14 ENERGY, ENVIRONMENTAL, HEALTH AND SAFETY, AND OTHER CONSIDERATIONS .............. 25

LIST OF FIGURES
Figure 1: Overhead Image of BWO FCCU Operating Area (from Google Earth) ....................... 9
LIST OF Tables
Table 1 DEQ Requirement Incorporation ............................................................................... 1
Table 2 Summary of Emission Unit Limits .............................................................................. 6
LIST OF Attachments
Attachment A: Summary Tables
Attachment B: Potential to Emit
Attachment C: Cost-Effectiveness Calculations
Table A: Potential RACT Technologies for NOX
Table B: Potential RACT Technologies for VOCs
Table C: NOX RACT Cost Effectiveness
Table D: Heaters and Boilers NOX RACT Cost Effectiveness
Table E: Engine NOX RACT Cost Effectiveness
Table F: WWTP VOC RACT Cost Effectiveness
Table G: Tank VOC RACT Cost Effectiveness
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EXECUTIVE SUMMARY
The Utah Division of Air Quality (UDAQ) sent a letter to Big West Oil LLC (BWO, Agency ID 10122) dated
May 31, 2023, describing the anticipated redesignation of the Northern Wasatch Front ozone
nonattainment area from moderate to serious nonattainment status. As a major stationary source in the
nonattainment area, UDAQ is requiring BWO to submit a Reasonable Available Control Technology
(RACT) analysis for NOX and VOC-emitting sources at the refinery. This document serves as the RACT
analysis for the facility.
EPA's five-step top-down process was followed to identify RACT for each source at the refinery emitting
the following:
• Oxides of nitrogen (NOX)
• Volatile organic compounds (VOC)
The applicable sources at the facility, the sources subject to RACT review, were identified as:
• Millisecond Catalytic Cracker (MSCC) regenerator vent,
• Sulfur Recovery Unit (SRU),
• Process heaters and boilers,
• Flares,
• Standby fire pump,
• Valves, pumps, and heat exchangers,
• Loading racks and vapor combustion unit (VCU),
• Storage tanks,
• Wastewater Treatment System, and
• Cooling towers.
As a part of the RACT process, other issues that could adversely impact the environment, safety and
health, and energy demand were included in the evaluation. Any projects that are identified to be
completed outside the normal refinery turnaround maintenance cycle would increase safety and health
risks and energy demand. Significant additional costs would also be associated with taking a refinery
shutdown out of sequence to implement those measures.

1

1.0 BACKGROUND
In 2018, UDAQ identified BWO's North Salt Lake refinery as a major stationary source located in the
Northern Wasatch Front Ozone Nonattainment Area. On November 7, 2022, the United States
Environmental Protection Agency (EPA) reclassified this nonattainment area from marginal to moderate
based on the 2015 8-hour ozone standard. Recent monitoring data indicates the Northern Wasatch
Front Nonattainment Area will not attain the standard and will be reclassified to serious status in
February 2025. A serious designation requires the SIP to include RACT measures for all major stationary
sources in the nonattainment area, including BWO. For ozone, RACT must be evaluated for units
emitting ozone precursors NOX and VOC.
This document provides a written evaluation of each available control technology for BWO ozone
precursor emission sources, taking into account technological, energy, environmental, and economic
feasibility.
On May 31, 2023, the Department of Environmental Quality (DEQ) issued a letter to BWO's North Salt
Lake refinery outlining the requirements of the required RACT analysis. These requirements have been
addressed in the report in the locations outlined in Table 1 below.
Table 1 DEQ Requirement Incorporation
Requirement Location
A list of each NOX and VOCs emission unit at the facility. All
emission units with a potential to emit either NOX or VOCs
must be evaluated.
Attachment A: Summary Tables
A physical description of each emission unit and its
operating characteristics, including but not limited to: the
size or capacity of each affected emission unit; types of fuel
combusted; the types and quantities of materials processed
or produced in each affected emission unit.
Section 3.0, and
Attachment A: Summary Tables
Estimates of the potential and actual NOX and VOC
emissions from each affected source, and associated
supporting documentation.
Attachment A: Summary Tables and
Attachment B: Potential to Emit
The actual proposed alternative NOX RACT requirement(s)
or NOX RACT emissions limitation(s), and/or the actual
proposed VOC requirement(s) or VOC RACT emissions
limitation(s) (as applicable).
Table 2
Supporting documentation for the technical and economic
considerations for each affected emission unit.
Section 3.0, and
Attachment C: Cost-Effectiveness
Calculations
A schedule for completing implementation of the RACT
requirement or RACT emissions limitation by May of 2026,
including start and completion of project and schedule for
initial compliance testing.
Not Applicable

2

Requirement Location
Proposed testing, monitoring, recordkeeping, and reporting
procedures to demonstrate compliance with the proposed
RACT requirement(s) and/or limitation(s).
Table 2
Additional information requested by DAQ necessary for the
evaluation of the RACT analyses.
Not Applicable

3

2.0 APPROACH
Per 40 CFR Part 51, Subpart F, RACT is defined as devices, systems, process modifications, or other
apparatus or techniques that are reasonably available, taking into account social, environmental, and
economic impacts as well as the necessity of imposing such controls in order to attain and maintain a
national ambient air quality standard.
A top-down RACT analysis was completed for all technologies that would reduce ozone precursor
emissions from all regulated sources within the BWO Refinery. The evaluation included assessing the
following emission sources:
• Millisecond Catalytic Cracker (MSCC) regenerator vent,
• Sulfur Recovery Unit (SRU),
• Process heaters and boilers,
• Flares,
• Standby fire pump,
• Valves, pumps, and heat exchangers,
• Loading racks and vapor combustion unit (VCU),
• Storage tanks,
• Wastewater Treatment System, and
• Cooling towers.
2.1 RACT ANALYSIS PROCESS
The RACT analysis was organized into the following steps, which are described in the paragraphs that
follow:
1. Identify control technologies.
2. Eliminate technically infeasible technologies.
3. Rank technologies by control effectiveness.
4. Evaluate controls for economic feasibility.
5. Recommend RACT.
2.1.1 Step 1 - Identify Control Technologies
BWO identified its emission sources for ozone precursors and then identified acceptable control
technologies for these sources. The following clearinghouses and guidelines were searched as part of
Step 1 to identify potentially applicable control technologies for the BWO emission sources:
• U.S. EPA's RACT/BACT/LAER Clearinghouse (RBLC)
• U.S. EPA's New Source Review (NSR) website
• U.S. EPA draft permit review comments on recent PSD permits
• State/local agency air quality permits and the associated agency review documents
• Permit applications and BACT reports for recent projects
• Air pollution control technology vendors and consultants
• Manufacturer's recommendations
• Bay Area Air Quality Management District (BAAQMD)
• South Coast Air Quality Management District (SCAQMD)

4

The emission sources and applicable technologies were documented using a RACT Matrix table for
tracking and presenting the results, as presented in Section 3.0 and the attached tables.
2.1.2 Step 2 - Eliminate Technically Infeasible Technologies
BWO reviewed the technologies to determine whether they were technically feasible at the refinery
based on site-specific (i.e., space limitations/appropriateness, spatial availability, safety concerns) or
operational constraints. The determination of technical feasibility had several criteria that needed to be
met, such as physical constraints, facility fuel gas and natural gas consumption balance, fired equipment
configuration (natural draft), and proven on similar sources.
2.1.3 Task 3 - Rank Technologies by Control Effectiveness
BWO calculated the baseline emissions from currently installed sources using emissions calculated for
2017; for newer equipment not installed in 2017, BWO calculated baseline emissions for the first year
following the source being operational. The potential for additional emission reductions was evaluated
for the applicable technologies using vendor or Environmental Protection Agency (EPA)-provided
removal efficiencies. The amount of emissions reductions that could be achieved for the applicable
technologies were calculated and the technologies were listed according to rank on the RACT Matrix.
2.1.4 Task 4 - Evaluate Most Effective Controls
BWO evaluated each remaining control technology to determine whether the energy, economic, or
environmental impacts from a given technology outweighed their benefits. Information including
control efficiency, anticipated emission rate, expected emissions reduction, and economic,
environmental, and energy impacts were considered.
2.1.4.1 Energy Impact
The energy impact of each evaluated control technology is the energy benefit or penalty resulting from
the operation of the control technology at the source. The costs of the energy impact either additional
fuel costs or the cost of lost power generation, which impacts the cost-effectiveness of the control
technology.
2.1.4.2 Environmental Impacts
Non-air quality environmental impacts were evaluated to determine the cost to mitigate the
environmental impacts, if any, caused by the operation of a control technology.
2.1.4.3 Cost Evaluation
BWO evaluated the controls for economic feasibility using capital and operating cost estimates provided
by the EPA Cost Control Manual, vendor information, and potential project estimates from BWO staff or
contractors. The cost effectiveness calculations utilized the facility estimation factor for capital projects,
which includes a contingency factor due to limited vendor cost input. Published costs from earlier EPA or
published studies were brought up to current costs by using the Bureau of Labor Statistics's inflation
calculator or Chemical Engineering Plant Cost Index (CEPCI). Energy consumption, environmental, and
other impacts were considered for the feasible controls to account for all economic impacts. The
economic feasibility of increased controls was evaluated using the ratio of the cost for the new controls

5

compared with the incremental emission reductions achieved by the new controls versus the baseline
(current) configuration in terms of dollars per ton of emissions reduced.
2.1.5 Task 5 - Recommend RACT
RACT is the technologically and economically feasible control option that can be implemented to
achieve emissions reductions. Based on the evaluation of control technologies, BWO is presenting in this
report its analysis and conclusions regarding the controls it believes are technically and economically
feasible.

6

3.0 RACT EVALUATION
The RACT Evaluation for each source is summarized in the following sections. Table 2 presents a
summary of RACT selections for each pollutant by source. Tables A and B in Attachment C also present
the emission sources for ozone precursors NOX and VOC. For each source, these tables list the identified
control technologies, if they are technically feasible, the baseline emissions, the estimated emissions
reductions, and the cost effectiveness for applicable technologies. Supporting cost effectiveness
calculations are provided in Tables C through G in Attachment C.
Table 2 Summary of Emission Unit Limits
Emission Unit Pollutant Limit Enforceability Comment
MSCC Regenerator NOX Low-NOX regeneration with
low-NOX promoter catalyst -
meets MACT Subpart UUU.
(0077-22)
II.B.3.b
Current
operations meet
RACT; no further
action is
warranted.
VOC Good combustion practices,
no additional controls.
(0077-22) I.5
SRU NOX Existing tail gas incinerator
and refinery-wide NOX limit.
(0077-22)
II.B.8.d
Current
operations meet
RACT; no further
action is
warranted.

VOC NA
Process Heaters
and Boilers
NOX LNB & ULNB required on
various units, and refinery-
wide NOX limit.
(0077-22)
II.B.1.d & II.B.8.d
Current
operations meet
RACT; no further
action is
warranted
VOC Good combustion practices,
no additional controls.
(0077-22) I.5
Refinery Flares NOX Evaluated through control of
flare gases, not through
individual pollutants, the
requirement to meet New
Source Performance
Standards (NSPS) Subpart Ja
and MACT Subpart CC for
flares.
(0077-22) II.B.4
& II.B.7.c
Current
operations meet
RACT; no further
action is
warranted.
VOC
Cooling Towers NOX NA
VOC MACT Subpart CC
requirements on cooling
towers servicing high VOC
heat exchangers.
(0077-22)
II.B.7.a
Current
operations meet
RACT; no further
action is
warranted.
Standby Fire
Pumps

NOX Proper maintenance and
operation and compliance
with applicable NSPS or
MACT requirements.
(0074-19) I.5 Current
operations meet
RACT; no further
action is
warranted.
VOC (0074-19)
II.B.1.c

7

Emission Unit Pollutant Limit Enforceability Comment
Fugitive emissions NOX NA
VOC Low leak LDAR requirements
of NSPS Subpart GGGa.
(0077-22)
II.B.1.a & II.B.7.b
Current
operations meet
RACT; no further
action is
warranted.
Truck Loading
Rack
NOX Good combustion practices,
no additional controls.
N/A Current
operations meet
RACT; no further
action is
warranted.
VOC Vapor recovery unit with
carbon adsorption in
compliance with MACT
Subpart CC.
(0077-22) I.5
Railcar Loading
Rack & Vapor
Combustion Unit
NOX Good combustion practices,
no additional controls.
N/A Current
operations meet
RACT; no further
action is
warranted.

VOC Vapor recovery with vapor
combustion unit in
compliance with MACT
Subpart R.
(0077-22) I.5
Tanks NOX NA
VOC Submerged fill operations
and tank degassing
requirements - eventual
compliance with NSPS
Subpart Kb or MACT Subpart
CC.
(0072-19)
II.B.1.a & II.B.1.b
Current
operations meet
RACT; no further
action is
warranted.
Wastewater
System
NOX NA
VOC API separator with fixed
cover, carbon canisters for
VOC control, 90% removal
efficiency.
N/A Current
operations meet
RACT; no further
action is
warranted.

3.1 MSCC REGENERATOR
BWO operates an MSCC regenerator that produces emissions for NOX and VOC. The MSCC process
differs from a more common Fluidized Catalytic Cracking Unit (FCCU) because the MSCC process utilizes
a shorter contact time between the catalyst and FCCU feed material in the reactor. Any potential control
technology that is demonstrated as appropriate for an FCCU requires additional detailed engineering
review to ensure feasibility with an MSCC process.
3.1.1 MSCC Regenerator – NOX
The predominant NOX species inside an MSCC regenerator is NO, that is further oxidized to NO2 upon
release to the atmosphere. NOX in the regenerator can be formed by two mechanisms: thermal NOX,
produced from the reaction of molecular nitrogen with oxygen, and fuel NOX, which is produced from
the oxidation of nitrogen-containing coke species deposited on the catalyst inside the reactor.

8

The identified control technologies are listed in Attachment C, Table A, including the currently
implemented NOX-reducing UOP high efficiency (low-NOX) combustor design, low-NOX combustion
promoter, and good combustion practices.
The RACT technology review showed potential additional control technologies for the MSCC
regenerator, including adding a NOX-reducing additive, selective catalytic reduction (SCR), and selective
non-catalytic reduction (SNCR).
3.1.1.1 NOX-Reducing Additive
NOX reducing additives affect the availability of nitrogen species to be oxidized and reduced, and
performance of the additives is dependent on the application. Multiple evaluations of NOX-reducing
additives have been conducted by BWO to determine the effectiveness of NOX reduction from the MSCC
regenerator. All tests to date have proven ineffective in reducing NOX emissions from the MSCC reaction
and regeneration process.
Use of a NOX-reducing additive is determined to be technically infeasible for the MSCC.
3.1.1.2 Selective Catalytic Reduction
SCR is a post-combustion control technology that injects ammonia in the flue gas in the presence of a
catalyst (typically vanadium or tungsten oxides) to produce N2 and H2O. The ideal temperature range
for an SCR is 600⁰ to 750⁰F with guaranteed NOX removal rates of 90+%. Design considerations include
targeted NOX removal level, service life, pressure drop limitation, ammonia slip, space limitation, flue
gas temperature, composition, and SO2 oxidation limit.
An SCR requires three diameters in length of straight pipe before the catalyst bed and one diameter
after the catalyst bed in order to stabilize the flue gas flow and achieve good contact within the catalyst
bed. The unobstructed height would have to be approximately 36 feet minimum above grade. It also
requires two horizontal, long radius elbows that would swing out approximately 18 feet to make the
appropriate turns needed to approach the SCR without excessive pressure drop and erosion of the pipe
elbows. The pipe diameter after the pall filter is 6 feet, therefore 9 feet of length is needed for each long
radius turn. The SCR would be slightly wider than the pipe diameter and is assumed to be 7-foot
diameter by 3 feet wide for this flow rate. The SCR would have to be located after the Pall filter to
prevent plugging of the catalyst.
An Ammonia storage tank and vaporizer would also be required. Approximately 150 square feet are
needed for the SCR system, and 50 feet of vertical clearance are needed for this area. As shown in Figure
1, there is not enough area to include the minimum of two 9-foot-long radius elbows and the SCR
system near the Pall Filter.

9

Figure 1: Overhead Image of BWO FCCU Operating Area (from Google Earth)
A SCR system is determined to be technically infeasible for the MSCC regenerator.
3.1.1.3 Selective Non-Catalytic Reduction
SNCR is a post-combustion control technology that reacts urea or ammonia with flue gas without the
presence of a catalyst to produce N2 and H2O. The typical operating temperature range for an SNCR is
1,600⁰ to 2,000⁰F. The SNCR temperature range is sensitive as the reagents can produce additional NOX
if the temperature is too high or removes too little NOX if the reaction proceeds slowly due to the
temperature being too low.
The flow dynamics required for an SNCR could not be met due to the installed blowback filter. As such,
an SNCR is determined to be technically infeasible for the MSCC regenerator.

10

3.1.1.4 Review of Technically Feasible Controls for MSCC – NOX
Attachment C, Table A ranks the technically feasible technologies according to reported achievable
emission reductions and shows their annualized costs to support the economic feasibility evaluation.
Control technologies that may be technically feasible were evaluated as a conservative approach. The
economic feasibility evaluation showed that control technologies were economically infeasible. Detailed
costs are summarized in Attachment C, Table C. Therefore, the current controls, UOP high efficiency
(low-NOX) combustor design, low-NOX combustion promoter, and good combustion practices are
considered RACT for the MSCC regenerator.
3.1.2 MSCC Regenerator – VOC
The MSCC is a complete combustion unit; therefore, much less VOC is generated than typical catalytic
combustion units. The RACT technology review showed potential additional control technologies for the
MSCC regenerator, including adding a CO boiler, wet gas scrubber, and add-on catalytic control.
3.1.2.1 CO Boiler
CO Boilers are not utilized for full-burn catalytic combustion units and are considered technically
infeasible.
3.1.2.2 Wet Gas Scrubber
The MSCC is equipped with a dry control system. A wet gas scrubber would require significant
infrastructure modifications. This technology is considered cost-prohibitive with significant
environmental impacts due to generation of wastewater and is not evaluated further.
3.1.2.3 Add-on Catalytic Control
Catalytic control has not been demonstrated on the outlet of an MSCC.
3.1.2.4 Review of Technically Feasible Controls for MSCC – VOC
Attachment C, Table B ranks the technically feasible technologies according to reported achievable
emission reductions and shows their annualized costs to support the economic feasibility evaluation.
Good combustion practices are considered RACT for the MSCC. VOC is assumed to be present in low
concentrations within the outlet stream of the MSCC. Therefore, add-on VOC control technology is
infeasible and is not considered further.
3.2 SULFUR RECOVERY UNIT
BWO operates a Sulfur Recovery Plant (SRP) that has a tail gas incinerator and currently achieves the
required 95 percent sulfur recovery. In addition, the refinery has added caustic scrubber to treat fuel gas
during SRP outages.
3.2.1 Sulfur Recovery Unit – NOX
There are three mechanisms by which NOX production occurs during combustion, including thermal,
fuel, and prompt NOX formation. In the case of Claus sulfur recovery, the SRU reaction furnace is

11

operated in a reducing environment, where ammonia in the acid gas feed is reduced to N2. A negligible
amount of NOX is formed from thermal or fuel formation mechanisms.
3.2.1.1 Good Design Methods and Operating Procedures
RACT for NOX from the SRU is using good design methods and operating procedures. During unit startup
or shutdown, good operating practices will be followed in order to minimize NOX emissions.
3.2.1.2 LoTOx and Wet Gas Scrubber
The HF Sinclair refinery in West Bountiful utilizes LoTOx and a Wet Gas Scrubber to control NOX
emissions from their FCCU and SRU combined. However, this is not technically feasible at BWO’s
refinery. The Wet Gas Scrubber was not designed with sufficient capacity to handle the exhaust stream
from the SRU.
3.2.1.3 Review of Technically Feasible Controls for SRU – NOX
NOX is assumed to be present in low concentrations within the outlet stream of the SRU unit, lower than
add-on control technology is able to achieve. Therefore, add-on NOX control technology is infeasible and
is not considered further.
3.2.2 Sulfur Recovery Unit – VOC
VOCs are introduced into the SRU from the acid gas feed streams. VOC emissions from the SRU are a
result of incomplete combustion of the fuel in the incinerator.
3.2.2.1 Good Design Methods and Operating Procedures
RACT for VOC from the SRU is using good design methods and operating procedures. The exhaust from
the SRU is sent to the Tail Gas Incinerator.
3.2.2.2 Use of Natural Gas
The use of a clean fuel, natural gas, instead of refinery fuel gas is not feasible for BWO. Importing
natural gas for combustion in the incinerator would result in diversion of the excess fuel gas to the flare,
which may result in flow rates to the flares in excess of the permitted refinery flare cap and no facility-
wide net reduction in emissions.
3.2.2.3 Catalytic Oxidation
The application of catalytic oxidation technology is not feasible, as the elevated sulfur levels can poison
oxidation catalysts.
3.2.2.4 Review of Technically Feasible Controls for SRU – VOC
VOC is assumed to be present in low concentrations within the outlet stream of the Tail Gas Incinerator.
Therefore, add-on VOC control technology is infeasible and is not considered further.

12

3.3 HEATERS
Refinery process heaters combust refinery fuel gas and/or natural gas to heat or vaporize hydrocarbon
mixtures for processing in downstream units, including distillation, reforming, and hydrotreating.
Process heaters generate emissions through fuel combustion. BWO operates the following process
heaters:
• H-101 MSCC Heater
• H-301 Alkylation Unit Deisobutanizier Reboiler Heater
• H-402 Crude Heater
• H-403 Crude Preflash Heater
• H-404 #1 Crude Heater
• H-601 Unifiner Heater
• H-621, H-622, H-624 Reformer Heaters
• H-1001 MIDW Heater
• H-1002 HDS Reboiler
• H-1003 HDS Heater
• H-1102 SRU and Tail Gas Incinerator
3.3.1 Heaters – NOX
During combustion, NOX emissions are generated via thermal, fuel, and prompt NOX formation. The
primary mechanism during gaseous fuel combustion for NOX is through thermal formation. The
identified control technologies for NOX are listed in Attachment C, Table A, including the currently
implemented use of only natural gas or refinery fuel gas for combustion (i.e., no oil burning) and low
NOX burners (LNBs).
The RACT technology review showed potential additional control technologies, including low NOX burner
(LNB), ultra-low NOX burner (ULNB), selective catalytic reduction (SCR), selective non-catalytic reduction
(SNCR), and flue gas recirculation (FGR). These technologies are further described in the sections below.
While further evaluation, such as physical space considerations, would be required before making a final
determination on the technical feasibilities of these technologies, BWO conservatively evaluated costs
for all potential control technologies for the heaters. The cost evaluations, also summarized in
Attachment C, Table A, show control costs are well above any precedent for feasibility under RACT.
3.3.1.1 Low NOX Burner (LNB)
All process heaters at BWO operate with a low or ultra-low NOX burner, with the exception of MSCC
Heater H-101. Because of the unique operation of the MSCC, as described in Section 3.1, heater H-101
requires a burner study to determine if the heater could operate with an LNB.
3.3.1.2 Ultra-Low NOX Burners (ULNB)
All heaters, with the exception of H-101 and H-404, are currently fitted with LNB. Heater H-404 is
already fitted with a ULNB. ULNBs for the other process heaters are not likely technically feasible due to
the design constraints of the heaters, which cannot physically accommodate the flame path. Regardless,
BWO performed a cost evaluation for ULNB implementation and determined ULNB to be economically
infeasible.

13

3.3.1.3 Selective Catalytic Reduction (SCR)
SCR is a process that involves the post-combustion removal of NOX from flue gas with a catalytic reactor.
In the SCR process, ammonia injected into the exhaust gas reacts with NOX and O2 to form nitrogen and
water. The reactions take place on the surface of the catalyst. The application of SCR is limited to
heaters that have both a flue gas temperature appropriate for the catalytic reaction and space for a
catalyst bed large enough to provide sufficient resident time for the reaction to occur. Optimum NOX
reduction occurs at catalyst bed temperatures of 600⁰ to 750⁰F for vanadium or titanium-based
catalysts and 470⁰ to 510⁰F for platinum catalysts.1
Sulfur content of the fuel can be of concern for systems that employ SCR. Catalyst systems promote
partial oxidation of sulfur dioxide to sulfur trioxide, which combines with water to form sulfuric acid.
Sulfur trioxide and sulfuric acid react with excess ammonia to form ammonia salt. These salts may
condense as the flue gas cools, leading to increased particulate emissions.
The SCR process also causes the catalyst to deactivate over time. Catalyst deactivation occurs through
physical deactivation and chemical poisoning. To achieve high NOX reduction rates, SCR vendors suggest
a higher ammonia injection rate than stoichiometrically required, which results in ammonia slip. This slip
leads to an emissions trade-off between NOX and ammonia.
An SCR requires three diameters in length of straight pipe before the catalyst bed and one diameter
after the catalyst bed in order to stabilize the flow and achieve good contact within the catalyst bed. The
unobstructed height would have to be approximately 36 feet minimum above grade. It also requires two
horizontal, long radius elbows that would swing out approximately 18 feet to make the appropriate
turns needed to approach the SCR without excessive pressure drop and erosion of the pipe elbows. An
Ammonia storage tank and vaporizer would be required.
Despite potential technical infeasiblities for SCR installation at the heaters, BWO prepared cost
evaluations for SCR at its process heaters and determined SCR to be economically infeasible.
3.3.1.4 Selective Non-Catalytic Reduction (SNCR)
SNCR was shown as a potential additional control technology for heaters H-101, H-301, H-402, H-403, H-
601, H-1001, H-1002, H-1003, and H-1102.
SNCR is a post-combustion NOX control technology based on the reactions of ammonia and NOX. SNCR
involves injecting urea/ammonia into the combustion gas to reduce the NOX to nitrogen and water. The
optimum exhaust gas temperature range for implementation of SNCR is 1,600⁰ to 1,750⁰F for ammonia
and from 1,000⁰ to 1,900⁰F for urea-based reagents. Operating temperatures below this range result in
ammonia slip, which forms additional NOX. In addition, the ammonia/urea must have sufficient resident
time, approximately 3 to 5 seconds, at the optimum operating temperatures for efficient NOX reduction.
Unreacted ammonia in the emissions is known as slip and is potentially higher in SNCR systems than in
SCR systems due to higher reactant injection rates.

1 Midwest Regional Planning Organization, Petroleum Refinery Best Available Retrofit Technology
(BART) Engineering Analysis, March 30, 2005.

14

A significant issue with the use of SNCR is that as the load changes, the optimum injection temperature
window moves. If ammonia is injected too hot, then more NOX is produced. If ammonia is injected too
cold, then ammonia does not react, resulting in ammonia being emitted to the atmosphere. The exhaust
temperatures of the heaters and boilers vary, and no process control method has been developed that
can match the temperature and rate of ammonia injection with flue gas rate, temperate, and other
variable to ensure optimum emission control.
Additionally, an SNCR is similar to an SCR as described in Sections 3.1.1.2 and 3.3.1.3, with the difference
being that five stack diameters in length are required to provide a steady state flow before the injection
of ammonia.
There is insufficient heating temperature for the SNCR to be applied to heaters H-101, H-301, H-402, H-
403, H-601, H-1001, H-1002, H-1003, and H-1102H-403 and H-101. Therefore, an SNCR system is
determined to be technically infeasible for these units.
3.3.1.5 Flue Gas Recirculation (FGR)
FGR was shown as a potential additional control technology for heaters H-101 and H-403.
FGR recirculates flue gas using a fan and external ducting. The flue gas is mixed with the combustion air
stream, thereby reducing the flame temperature and decreasing NOX formation. External flue gas
recirculation only works with mechanical draft heaters with burners that can accommodate increased
gas flows. FGR has not been demonstrated to function efficiently on units that are subject to highly
variable loads and that burn fuels with variable heat value.
An FGR system would require a Tee added into the stack at the top of the boilers and heaters, dampers
on the Tee outlets, and re-piping with long-radius elbows for return to the inlet combustion air. An inlet
damper system would also be required, including a forced draft fan. As shown in Figure 1, there is not
sufficient area adjacent to the boilers and heaters for an FGR. Approximately 500 ft2 would be needed
per FGR system.
An FGR system is determined to be technically infeasible for heaters H-101 and H-403.
3.3.1.6 Review of Technically Feasible Technologies for Heaters – NOX
Attachment C, Table A ranks the technically feasible technologies according to reported achievable
emission reductions and shows their annualized costs to support the economic feasibility evaluation.
The economic feasibility evaluation showed in Attachment C, Table D that control technologies
determined to be technically implementable were economically infeasible. Therefore, the current
controls, LNB (or ULNB for H-404), are considered RACT for the heaters.
3.3.2 Heaters – VOC
Process heaters generate VOC emissions as a result of incomplete combustion of refinery fuel gas. The
identified control technologies for VOC are listed in Attachment C, Table B, including the currently
implemented use of good design methods and operating procedures.
The RACT technology review showed potential additional control technologies, including catalytic and
thermal oxidation.

15

3.3.2.1 Catalytic Oxidation
Catalytic oxidation utilizes catalyst to promote the oxidation of VOCs to CO2 and water. An important
factor in the use of catalytic oxidation is the operating temperature. Saturated hydrocarbon removal is
best achieved at high temperatures between 650 and 1,000°F2, which will be above the normal
operating range of the majority of heaters, making catalytic oxidation ineffective for VOC control. For
those heaters that do have sufficient heat, the cost effectiveness is inherently not feasible.
Catalytic oxidation is determined to be technically and economically infeasible for the process heaters at
BWO.
3.3.2.2 Thermal Oxidation
Thermal oxidation is similar to catalytic oxidation in that it converts VOC emissions to CO2 and water.
However, rather than the use of a catalyst, thermal oxidation controls and converts these emissions via
combustion. The effectiveness of thermal oxidation is highly dependent on exhaust gas VOC
concentration. Required outlet concentrations for thermal oxidation systems are typically 20 ppmv. The
VOC concentration in process heater exhaust streams are estimated to be below 20 ppmv, making
thermal oxidation ineffective.
Thermal oxidation is determined to be technically infeasible for the process heaters at BWO.
3.3.2.3 Review of Technically Feasible Technologies for Heaters Heaters – VOC
Attachment C, Table B ranks the technically feasible technologies according to reported achievable
emission reductions and shows their annualized costs to support the economic feasibility evaluation.
Due to insufficient operating temperatures and low VOC concentrations within the outlet stream,
additional VOC control technologies are considered infeasible. Therefore, the current use of good
combustion practices are considered RACT for heaters.
3.4 BOILERS
Boilers combust refinery fuel gas and/or natural gas to generate steam for process use at the refinery.
BWO owns and operates Boilers 1 and 6. BWO also owns Boiler 2, though it is no longer operated
(enforceable via permit); the rental Wabash Boiler is operated in its place. BWO does not own the
Wabash Boiler.
3.4.1 Boilers – NOX
BWO operates three boilers that produce emissions for NOX. The identified control technologies for NOX
are listed in Attachment C, Table A, including the currently implemented use of only natural gas or
refinery fuel gas for combustion (i.e., no oil burning). Boilers 1 and 6 are configured with ULNB, while
the Wabash Boiler is configured with LNB and FGR.

2 EPA Webpage. https://www.epa.gov/air-emissions-monitoring-knowledge-base/monitoring-control-
technique-catalytic-
oxidizer#:~:text=Catalytic%20oxidizers%2C%20also%20known%20as,%2C%20increase%20the%20
kinetic%20rate).

16

The RACT technology review showed potential additional control technologies, including SCR, FGR, and
SNCR. These technologies are further described in the sections below. While further evaluation, such as
physical space considerations, would be required before making a final determination on the technical
feasibilities of these technologies, BWO conservatively evaluated costs for all potential control
technologies for the boilers. The cost evaluations, also summarized in Attachment C, Table A, show
control costs are well above any precedent for feasibility under RACT.
3.4.1.1 Selective Catalytic Reduction (SCR)
SCR for heaters and boilers is described in Section 3.3.1.3.
An SCR requires three diameters in length of straight pipe before the catalyst bed and one diameter
after the catalyst bed in order to stabilize the flow and achieve good contact within the catalyst bed. The
unobstructed height would have to be approximately 36 feet minimum above grade. It also requires two
horizontal, long radius elbows that would swing out approximately 18 feet to make the appropriate
turns needed to approach the SCR without excessive pressure drop and erosion of the pipe elbows. An
Ammonia storage tank and vaporizer would be required. There is not adequate space to house an SCR
system for the boilers.
Despite potential technical infeasiblities for SCR installation at the boilers, BWO prepared cost
evaluations for SCR at its process heaters and determined SCR to be economically infeasible regardless
of technical feasibility concerns.
3.4.1.2 Flue Gas Recirculation (FGR)
FGR for heaters and boilers is described in Section 3.3.1.5.
As shown in Figure 1 , there is not sufficient area adjacent to the boilers and heaters for an FGR.
Approximately 500 ft2 would be needed per FGR system.
Furthermore, an FGR system on its own may not comply with the stringent NOX requirements of R307-
316.
An FGR system is determined to be technically infeasible for the boilers.
3.4.1.3 Selective Non-Catalytic Reduction (SNCR)
SNCR for heaters and boilers is described in Section 3.3.1.4
As shown on Figure 1, there is not enough area for the long radius elbows and SNCR injection system at
the boilers.
Based on the issues identified, an SNCR system is determined to be technically infeasible for the boilers.
3.4.1.4 Review of Technically Feasible Technologies for Boilers – NOX
Attachment C, Table A ranks the technically feasible technologies according to reported achievable
emission reductions and shows their annualized costs to support the economic feasibility evaluation.
Control technologies that may be technically feasible were evaluated as a conservative approach. The
economic feasibility evaluation in Attachment C, Table D showed that control technologies were

17

economically infeasible. Therefore, the current controls, use of ULNB (for Boilers 1 and 6) or LNB and
FGR (for Wabash Boiler), are considered RACT for the boilers.
3.4.2 Boilers – VOC
Boilers generate VOC emissions as a result of incomplete combustion of refinery fuel gas. The identified
control technologies for VOC are listed in Attachment C, Table B, including the currently implemented
use of good design methods and operating procedures.
The RACT technology review showed potential additional control technologies, including catalytic and
thermal oxidation.
3.4.2.1 Catalytic Oxidation
Catalytic oxidation utilizes catalyst to promote the oxidation of VOCs to CO2 and water. An important
factor in the use of catalytic oxidation is the operating temperature. Saturated hydrocarbon removal is
best achieved at high temperatures between 650 and 1,000°F3, which will be above the normal
operating range of the boilers, making catalytic oxidation ineffective for VOC control.
Catalytic oxidation is determined to be technically infeasible for the boilers at BWO.
3.4.2.2 Thermal Oxidation
Thermal oxidation is similar to catalytic oxidation in that it converts VOC emissions to CO2 and water.
However, rather than the use of a catalyst, thermal oxidation controls and converts these emissions via
combustion. The effectiveness of thermal oxidation is highly dependent on exhaust gas VOC
concentration. Required outlet concentrations for thermal oxidation systems are typically 20 ppmv. The
VOC concentration in boiler exhaust streams are estimated to be below 20 ppmv, making thermal
oxidation ineffective.
Thermal oxidation is determined to be technically infeasible for the boilers at BWO.
3.4.2.3 Review of Technically Feasible Technologies for Boilers – VOC
Attachment C, Table B ranks the technically feasible technologies according to reported achievable
emission reductions and shows their annualized costs to support the economic feasibility evaluation.
Due to insufficient operating temperatures and low VOC concentrations within the outlet stream,
additional VOC control technologies are considered infeasible. Therefore, the current use of good
combustion practices are considered RACT for boilers.
3.5 REFINERY FLARES
BWO operates two refinery flares, designated as the South and West Flares. The current operation
differs from the 2017 baseline year as the West Flare came into service in 2020 to replace the now-

3 EPA Webpage. https://www.epa.gov/air-emissions-monitoring-knowledge-base/monitoring-control-
technique-catalytic-
oxidizer#:~:text=Catalytic%20oxidizers%2C%20also%20known%20as,%2C%20increase%20the%20
kinetic%20rate).

18

demolished North Flare. The refinery flares emit NOX and VOCs, and each pollutant has different control
technologies to be evaluated.
BWO has a program of continuous improvement to optimize its operations, including flare minimization.
BWO’s continuous efforts to identify, assess, and minimize material combusted at the flares are set
forth in the following subsections. BWO examines discharges to each flare from process units, ancillary
equipment, and fuel gas systems for flare minimization opportunities. To that end, BWO conducted a
flare minimization study to identify opportunities for minimization. To date, BWO has spent more than
$2.5 million to scope and implement various flare minimization activities identified as part of that study.
These have included the following activities:
• Updated preventative maintenance schedules;
• Updated startup, shutdown, and emergency procedures;
• Acoustic valve monitoring; and
• Upgrades to improve equipment reliability and recovery of various contributions which would
otherwise be sent to one of the North Salt Lake Refinery’s flares.
The PM2.5 SIP at Part IX.H.11.g.v requires that flares are either served by a flare gas recovery system or
limited to no more than 500,000 scf/day per affected flare during normal operations. BWO does not
operate flare gas recovery system, so the quantity of flared gas is limited during normal operations.
In addition, BWO has implemented a combustion control management system to comply with the
provisions of 40 CFR 63 Subpart CC. This includes the use of continuous monitoring systems for flare gas
composition, vent gas flow rate, supplemental gas flow rates, steam flow rate, and process controls to
ensure effective combustion.
3.5.1 Refinery Flares – NOX
BWO operates two refinery flares that produce emissions for NOX. The identified control technologies
are listed in Attachment C, Table A, including the currently implemented NOX reduction by complying
with flaring provisions of NSPS Subpart Ja, the PM2.5 SIP at Part IX.H.11.g.v, and MACT Subpart CC
flaring provisions.
The RACT technology review showed potential additional control technologies for the refinery flares,
including flare gas recovery. Flare gas recovery is not currently technically feasible. BWO is fuel-gas-long,
meaning that it generates more refinery fuel gases than it can consume in its process heaters and
boilers. Surplus fuel gas is combusted at the flare. Installing flare gas recovery is not technically feasible
without the installation of additional fuel-gas combustion devices to correct fuel-gas-long operations.
Attachment C, Table A ranks the technically feasible technologies according to reported achievable
emission reductions and shows their annualized costs to support the economic feasibility evaluation.
However, no additional controls are classified as technically feasible for the refinery flares. Therefore,
the current controls, compliance with NSPS Subpart Ja, the PM2.5 SIP, MACT Subpart CC flaring
provisions, and ongoing flare gas minimization efforts are considered RACT for the refinery flares.
3.5.2 Refinery Flares – VOC
BWO operates two refinery flares that produce emissions for VOCs. The identified control technologies
are listed in Attachment C, Table B, including the currently implemented VOC reduction by complying

19

with flaring provisions of NSPS Subpart Ja, the PM2.5 SIP at Part IX.H.11.g.v, and MACT Subpart CC
flaring provisions.
As identified in Section 3.5.1, Flare Gas Recovery is not technically feasible. No additional technologies
were identified as technically feasible.
Therefore, the current controls, compliance with NSPS Subpart Ja, the PM2.5 SIP, MACT Subpart CC
flaring provisions, and ongoing flare gas minimization efforts are considered RACT for the refinery flares.
3.6 STANDBY (EMERGENCY) ENGINES – NOX
BWO operates six emergency engines, which are configured and designed as follows:
• P-8908 Firewater Pump, 526 hp – Tier 3
• P-8909 Firewater Pump, 526 hp – Tier 3
• P-8910 Firewater Pump, 526 hp – Tier 3
• P-8911 Firewater Pump, 526 hp – Tier 3
• Backup Firewater Generator, 96 hp – Tier 3
• Backup Admin Building Generator, 237 hp – Tier 3
All engines are classified as emergency engines for purposes of compliance with MACT Subpart ZZZZ. Per
40 CFR 63.6640(f), they are limited to operations during non-emergency scenarios for up to 100 hours
per year (for maintenance and readiness testing purposes). Furthermore, any operation other than
emergency operation, maintenance and testing, and operation in non-emergency situations for 50 hours
per year, as described in 63.6640(f)(1) – (f)(4), is prohibited.
The RACT technology review showed that no additional control technologies were feasible for the
engines, including the currently implemented good combustion practices for Tier 3 engines. The
identified control technologies for NOX are listed in Attachment C, Table A. The RACT technology review
identified an SCR as a potential add-on control to reduce NOX emissions.
Attachment C, Table E ranks the technically feasible technologies according to reported achievable
emission reductions and shows their annualized costs to support the economic feasibility evaluation.
The economic feasibility evaluation demonstrated that the SCR is economically infeasible. Therefore, the
current Tier 3 configurations, classification as a Tier 3 engine, and good combustion practices are
considered RACT for the emergency engines.
3.7 FUGITIVE EQUIPMENT – VOC
The refinery equipment and piping components that contribute to the fugitive VOC emissions are
currently monitored under a Leak Detection and Repair (LDAR) Program at the refinery. This program
requires that when an allowable leak rate is exceeded, the component must be repaired or replaced to
eliminate that leak. BWO’s LDAR program consists of requirements from 40 CFR 60 Subpart GGGa, 40
CFR 63 Subpart CC, Utah R307-326, and a consent decree. The Consent Decree implements an enhanced
LDAR program consisting of the following elements:
• Maintain a written facility-wide LDAR program with periodic updates.

20

• Provide LDAR training to new and existing employees with LDAR-related responsibilities and/or
maintain copies of contractor training records.
• Conduct LDAR audits every two years alternating between internal and third party, and
implement corrective action plans.
• Comply with enhanced leak definitions for valves in light liquid or gas/vapor service and pumps
in light liquid service.
• Calibrate LDAR monitoring equipment prior to each monitoring day and a drift assessment is
required at the end of each monitoring shift.
• Sign-off on delays of repair must be by the plant manager or responsible official. Drill and tap
repairs must also be attempted where feasible.
• Purchase certified low-leak technology (CLLT) valves for new and replacement equipment.
• Track valve leak history, identify those that qualify as “chronic leakers” and replace or repack all
valves that meet that criteria.
• Use a tracking program or MOC when new valves or pumps are added into the LDAR program or
removed from the LDAR program.
• Implement a QA/QC program.
• Of note, BWO has implemented additional measures to reduce emissions from fugitive piping
equipment that is part of the refinery’s LDAR program. Examples include:
• Implementation of additional monitoring to utilize site-specific monitoring data instead of use of
published correlation equations.
• Additional review of the LDAR database to confirm accuracy and classification of identified
piping components.
• Updating composition information in the LDAR database to improve accuracy of calculated
emissions to better represent the characteristics of the fugitive emissions.
Due to the aforementioned additional measures, BWO has demonstrated significant emissions
reductions since 2017. Annual totals for 2017, 2018, 2019, 2020, and 2021 are 225,92 tpy, 136.75 tpy,
132.30 tpy, 127.67 tpy, and 104.63 tpy, respectively.
No additional technologies were identified as technically feasible. No economic analysis was conducted.
Therefore, the current controls, LDAR program in compliance with NSPS Subpart GGGa, are considered
RACT for fugitive equipment.
3.8 TRUCK LOADING RACK – VOC
The truck rack is used for gasoline and diesel product loading. VOC vapors are discharged from the
tankers as they are filled. The loading rack is operated with a vapor recovery unit with carbon adsorption
as the control device.
The RACT technology review identified vapor recovery with carbon and vapor recovery with combustion
as potential control technologies. The refinery currently implements the use of vapor recovery with
carbon at the Truck Load Rack. The identified control technologies are listed in Attachment C, Table B.
Use of vapor recovery and thermal oxidation results in combustion-related emissions from the
controlled VOC, and the degree of VOC control is comparable to that of carbon. It is not technically
feasible to install vapor combustion after the existing VRU. As no additional technologies were identified
as technically feasible, no economic analysis was conducted. Therefore, the current controls, vapor
recovery, and carbon are considered RACT the Truck Loading Rack.

21

3.9 RAILCAR LOADING RACK
The railcar load rack is used for product loading into and out of railcars. The railcar load rack is currently
controlled with vapor combustion unit.
3.9.1 RAILCAR LOADING RACK VAPOR COMBUSTION UNIT – NOX
NOX emissions are not generated from the railcar loading itself but rather from the railcar loading rack's
vapor combustion unit (VCU). Reducing NOX would involve modification of the current VOC control
technology utilized at the railcar loading rack. Implementing add-on controls to control emissions from a
control device is not practical, given the very low actual NOX emissions from the VCU.
RACT for NOX from the railcar loading rack vapor combustion Unit (VCU) is using good design methods
and operating procedures. During unit startup or shutdown, good operating practices will be followed in
order to minimize NOX emissions.
3.9.2 RAILCAR LOADING RACK – VOC
The RACT technology review identified vapor recovery and vapor combustors as potential control
technologies. The refinery currently implements these technologies for product loading racks. The
identified control technologies are listed in Attachment C, Table B.
As no additional technologies were identified as technically feasible, no economic analysis was
conducted. Therefore, the current controls, vapor recovery, and vapor combustor are considered RACT
for fugitive equipment.
Use of vapor recovery results in comparable emissions from the controlled vapor combustor unit. It is
not technically feasible to install vapor recovery and carbon after the existing vapor combustion unit. As
no additional technologies were identified as technically feasible, no economic analysis was conducted.
Therefore, the current controls, consisting of vapor recovery and vapor combustion units, are
considered RACT for the Railcar Load Rack.
3.10 GROUP 1 STORAGE TANKS – VOC
BWO has both external and internal floating storage tanks that produce emissions for VOCs. The
identified control technologies are listed in Attachment C, Table B, including the currently implemented
VOC emissions reductions by complying with requirements of MACT Subpart CC and WW for Group 1
Storage Vessels. Additional clarification is provided below for requirements of Group 1 Storage Tanks by
configuration: internal floating roof (IFR) and external floating roof (EFR).
3.10.1 IFR Tanks
An IFR tank has a permanent roof with a floating roof on the inside of the tank that floats on the surface
of the liquid. Emissions from a floating roof tank come from both withdrawal losses and standing losses.
Withdrawal losses are generally due to liquid level fluctuations associated with adding material into the
tank and removing material from the tank, and standing storage losses originate from the rim seal(s),
floating roof deck fittings, and the deck seams (for non-welded tanks). All internal floating roof tanks are
subject to NSPS Subpart Kb or MACT Subpart CC.

22

Several IFR tanks have been upgraded to meet controls required by recent revisions to Subpart CC under
the Refinery Sector Rule (RSR). Under RSR, a new section of tank-specific requirements has been added
at 40 CFR 63.660. This new section contains new and additional requirements for floating roof seals,
deck fitting controls, inspections, recordkeeping, and reporting.
RSR requires that the next time the vessel is emptied and degassed or by February 1, 2026, whichever
comes first, the tank is upgraded to meet the deck fitting controls of 40 CFR Subpart WW, which is the
method of compliance under 40 CFR 63.660 for tanks that are not configured with closed-vent systems
and control devices. The deck fitting control upgrades (or commonly referred to below as Upgrades to
RSR Controls) for IFR tanks from 40 CFR 63.646 to 40 CFR 63.660 compliance include:
• IFR openings must be gasketed (i.e., deck openings other than for vents, drains, or legs) and have
1/8" max gap criteria.
• IFR vents must be gasketed (vacuum breakers, rim vents) with 1/8" max gap criteria.
• Deck openings other than those for vents must project into liquid to eliminate an uncontrolled
emissions path from below the roof.
• Access hatches and gauge float well covers are required to be bolted and gasketed.
• Emergency roof drains must have seals covering at least 90% of the floating roof deck opening.
• IFR column wells (for cone-roof tanks) must have a gasketed cover or flexible fabric sleeve.
• Unslotted guidepoles are required to have a pole wiper at the deck fitting and a gasketed cap at the
top of the pole.
• Slotted guidepoles must have an external pole wiper and an internal pole float or equivalent.
• Each opening through a floating roof for a ladder having at least one slotted leg shall be equipped
with one of the following configurations:
o A pole float in the slotted leg and pole wipers for both legs. The wiper or seal of the pole
float must be at or above the height of the pole wiper.
o A ladder sleeve and pole wipers for both legs of the ladder.
o A flexible enclosure device and either a gasketed or welded cap on the top of the slotted leg.
In addition, during the removal of the tank from service, tank degassing emissions must be controlled by
portable using a control device, as required by the Utah SIP Section IX.H.11.g.vi.
Note that baseline emissions reflect RY2017 emissions (as reported in the Air Emissions Inventory),
except that adjustment to reflect the expected benefit after implementing controls after
implementation. These controls are already federally required and will be completely implemented by
February 1, 2026. Additional adjustments have been made to incorporate the use of site-specific
monitoring data (e.g., tank-specific RVP data instead of assumed RVP data) or tank component
configuration.
3.10.2 EFR Tanks
An external floating roof (EFR) tank is an open-topped tank with a roof floating on the surface of the
liquid. Emissions from a floating roof tank come from both withdrawal losses and standing losses.
Withdrawal losses are generally due to liquid level fluctuations, and standing storage losses originate
from the rim seal and deck fittings. All external floating roofs currently meet the double seal standard
from 40 CFR Part 60 Subpart Kb or 40 CFR Part 63 Subpart CC (Existing MACT CC).

23

Some of the tanks have been upgraded to meet RSR controls. Refer to Section 3.10.1 for additional
background on compliance with RSR.
RSR requires that the next time the vessel is emptied and degassed or by February 1, 2026, whichever
comes first, the tank is upgraded to meet the deck fitting controls of 40 CFR Subpart WW, which is the
method of compliance under 40 CFR 63.660. The deck fitting control upgrades (or commonly referred to
below as Upgrades to RSR Controls) for external floating roof tanks from 40 CFR 63.646 to 40 CFR 63.660
compliance include:
• EFR well covers must be gasketed (i.e., deck openings other than for vents, drains, or legs) 1/8" max
gap criteria.
• EFR vents to be gasketed (vacuum breakers, rim vents) 1/8" max gap criteria.
• Deck openings other than for vents must project into liquid.
• Access hatches and gauge float well covers must be bolted and gasketed.
• Emergency roof drains must have seals covering at least 90% of the floating roof deck opening.
• Guidepole wells must have gasketed deck cover and a pole wiper.
• Unslotted guidepoles are required to have a cap at the top of the pole.
• Slotted guidepoles must have an internal float or equivalent.
In addition, during the removal of the tank from service, tank degassing emissions must be controlled by
portable using a control device, as required by the Utah SIP Section IX.H.11.g.vi.
Note that baseline emissions reflect RY2017 emissions (as reported in the Air Emissions Inventory),
except that adjustment to reflect the expected benefit after implementing controls after
implementation. These controls are already federally required and will be completely implemented by
February 1, 2026. Additional adjustments have been made to incorporate the use of site-specific
monitoring data (e.g., tank-specific RVP data instead of assumed RVP data) or tank component
configuration.
3.10.3 RACT Evaluation
The RACT technology review evaluated potential additional control technologies for the storage tanks,
including the addition of a dome to EFR tanks, retrofitting IFR tanks with secondary seals, vapor recovery
unit to carbon, and vapor recovery to combustor are evaluated for all Group 1 tanks. Technical feasibility
for retrofitting EFRs with a dome is to be evaluated on a case-by-case basis as to whether the tank shell
and foundation can support the additional weight of a geodesic dome. Potential exists that the tanks
would require a complete rebuild to accommodate the additional weight.
Attachment C, Table B ranks the technically feasible technologies according to reported achievable
emission reductions and shows their annualized costs to support the economic feasibility evaluation.
Additional supporting information is provided in Attachment C, Table G. The economic feasibility
evaluation in Attachment C, Table G showed that control technologies determined to be technologically
implementable were economically infeasible. Therefore, the current controls (compliance with NSPS
Subpart Kb and/or MACT Subparts CC/WW, R307-327, and degassing to a vapor combustion device
before opening and venting to the atmosphere for inspection and maintenance, are considered RACT for
the Group 1 storage tanks.

24

3.11 GROUP 2 STORAGE TANKS – VOC
BWO has vertical fixed-roof storage tanks that produce emissions for VOCs. Fixed roof tanks are either
vented with a gooseneck or have a pressure/vacuum vent. Emissions from fixed roof tanks are in the
form of working losses and standing losses. Standing losses occur through tank temperature fluctuations
while working losses occur primarily from liquid level changes. Fixed roof tanks are only used to store
liquids with low vapor pressures, such as diesel, kerosene, and other heavy oils, given their low potential
for emissions generation. The identified control technologies are listed in Attachment C, Table B,
including the current controls of pressure/vacuum relief valves.
The RACT technology review showed potential additional control technologies for the storage tanks,
including installing IFRs on existing vertical fixed roof tanks, vapor recovery unit to carbon, and vapor
recovery to combustor. Installing an internal floating roof requires detailed evaluation on a tank-by-tank
basis of whether it is technically feasible; BWO conservatively assumes it is technically feasible for
purposes of this study and to evaluate economic feasibility.
Attachment C, Table B ranks the technically feasible technologies according to reported achievable
emission reductions and shows their annualized costs to support the economic feasibility evaluation.
The economic feasibility evaluation showed that control technologies determined to be technologically
implementable were economically infeasible. Therefore, the current controls are considered RACT for
the Group 2 Storage Tanks.
3.12 WASTEWATER TREATMENT SYSTEM – VOC
BWO operates a Wastewater Treatment System that produces emissions for VOCs. All wastewater and
storm water streams within the refinery is treated in the Wastewater Treatment Plant (WWTP). Oil is
recovered from the WWTP and is stored and/or reprocessed in the refinery. The WWTP is configured
with carbon canisters on the API separator fixed cover. The identified control technologies are listed in
Attachment C, Table F, including the currently implemented VOC reduction of a fixed cover with carbon
canister on the API separator that controls emissions from the surfaces.
The RACT technology review showed potential additional control technologies for the system, including
thermal oxidizers as potential add-on controls. Attachment C, Table B ranks the technically feasible
technologies according to reported achievable emission reductions and shows their annualized costs to
support the economic feasibility evaluation. The thermal oxidizer determined to be technologically
implementable was not economically feasible as the system is already controlled using carbon canisters;
the use of a combustion device adds safety risk to the refinery as it would be located near the storage
tank area. Therefore, the current controls, API fixed cover, and carbon canister installations are
considered RACT for the Wastewater Treatment System.
3.13 COOLING TOWERS – VOC
BWO operates cooling towers that produce emissions for VOCs. The identified control technologies are
listed in Attachment C, Table B, including the currently implemented monitoring heat exchanger El Paso
sampling and hydrocarbon analysis program and work practice standards to detect and minimize leaks
into cooling water systems within MACT Subpart CC and high-efficiency drift eliminators that minimize
any secondary particulate formation.

25

Calculated VOC emissions from the refinery's cooling towers in 2017 totaled approximately 143 tons.
Over 95% of these emissions are attributable to a heat exchanger leak event that caused a heat
exchange system to leak into the Alky Cooling Tower. BWO has implemented internal corrective actions
and work practices to reduce leaks from heat exchangers into the cooling tower heat exchange system
and ensure that leaks are promptly corrected. This is evident in annual emissions totals from the
following years; annual total VOC emissions in RY2018, RY2019, RY2020, and RY2021 totaled 5.46 tpy,
0.56 tpy, 1.28 tpy, and 1.84 tpy, respectively.
The RACT technology review did not identify any additional feasible control technologies. As no
additional technologies were identified as technically feasible, no economic analysis was conducted.
Therefore, the current controls, monitoring, and high-efficiency drift eliminators are considered RACT
for the cooling.
3.14 ENERGY, ENVIRONMENTAL, HEALTH AND SAFETY, AND OTHER
CONSIDERATIONS
The RACT Evaluation must consider impacts to increased energy usage that increase direct and indirect
emissions for the refinery. Some technologies like low NOX and ultra-low NOX burners result in slightly
higher fuel gas consumption. New pumps for wet scrubbers, new controllers for oxygen trim systems,
and new electrostatic precipitators all increase electricity consumption. Use of vapor recovery systems
on storage tanks significantly require greater electricity to run blower systems. Furthermore, use of
carbon canisters and offsite regeneration uses energy offsite but should be a consideration in the overall
determination of RACT.
Environmental impacts were identified for the final disposal of the SOX-reducing catalyst, caustic
scrubber wastewater disposal, and low NOX additives disposal.
Additional safety and health concerns of workers include but are not limited to the handling of caustic
and additives used by some of the control devices. The use of combustion technologies (e.g., thermal
oxidation) near storage tanks is a significant process safety risk.
Other cost considerations include attempting to install add-on control devices within the refinery during
out-of-sequence maintenance turnarounds. Turnaround planning is very detailed and requires intricate
coordination of materials, staffing resources, and technical expertise. In addition, significant time and
resources are required to safely design and engineer changes to process configuration and equipment.
Significant lead time is required to procure equipment associated with various emissions control
technologies. Any requirements to expedite schedule and minimize time to procure materials for
installation incur large cost impacts to the refinery. This opportunity cost would need to be evaluated
and added to any projects that are identified to be included in the Ozone SIP.

Attachment A: Summary Tables

Big West Oil LLC
Serious Ozone Nonattainment
NOX Emission Unit Summary
ID Name Fuels Materials Processed/Produced Baseline Actual
D-103
MSCC Catalyst
Regenerator 33,000 bbl/day N/A MSCC Feed 18.56
BLR-1 #1 Boiler 83 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 5.34
BLR-6 #6 Boiler 42 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 2.88
Wabash Wabash Boiler 92.3 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 5.59
H-101 MSCC Heater 53.8 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 3.60
H-301 Alky Feed Heater 16.9 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 8.24
H-402 Crude Furnace 30 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 9.05
H-403 Preflash Furnace 16.2 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 7.94
H-404 Crude Heater 27.9 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 2.90
H-601
Unifiner Charge
Heater 22.6 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 6.45
H-621,
622, 624 Reformer Heater 50.4 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 24.83
H-1001 MIDW Heater 3.8 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 2.39
H-1002 HDS Heater 2.2 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 1.43
H-1003 HDS Heater 6.6 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 1.65
H-1102
SRU/TGU
Incinerator 3 MMBtu/hr
Refinery Fuel Gas
Natural Gas
SRU Tail Gas N/A 0.78
FL-South South Flare 297 MMscf/yr
Process Gas
Natural Gas N/A 3.06
FL-West West Flare1 918 MMscf/yr
Process Gas
Natural Gas N/A 4.73
2
Railcar Loading
Rack VCU 6.9 MMscf/day N/A Various 0.53
488 hp
526 hp
Admin Emergency
Engine 206.4 bhp
Ultra-low sulfur
diesel N/A 7.75E-04
1 - West Flare baseline emissions are from calendar year 2021 since the unit was not operational in 2017.
2 - Emergency Fire Pump baseline emissions are from calendar year 2020 since the pump configuration changed from 2017.
Capacity
Emission Unit Description Emissions (tpy)
0.53
Emergency Fire
Pump2
Ultra-low sulfur
diesel N/A
Big West Oil LLC
Serious Ozone Nonattainment
VOC Emission Unit Summary
ID Name Fuels Materials Processed/Produced Baseline Actual
D-103
MSCC Catalyst
Regenerator 33,000 bbl/day N/A MSCC Feed 9.39
BLR-1 #1 Boiler 83 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 0.41
BLR-6 #6 Boiler 42 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 0.18
Wabash Wabash Boiler 92.3 MMBtu/hr N/A N/A 0.46
H-101 MSCC Heater 53.8 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 0.06
H-301 Alky Feed Heater 16.9 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 0.14
H-402 Crude Furnace 30 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 0.40
H-403 Preflash Furnace 16.2 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 0.18
H-404 Crude Heater 27.9 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 0.40
H-601
Unifiner Charge
Heater 22.6 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 0.29
H-621,
622, 624 Reformer Heater 50.4 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 1.13
H-1001 MIDW Heater 3.8 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 0.08
H-1002 HDS Heater 2.2 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 0.05
H-1003 HDS Heater 6.6 MMBtu/hr
Refinery Fuel Gas
Natural Gas N/A 0.06
H-1102
SRU/TGU
Incinerator 3 MMBtu/hr
Refinery Fuel Gas
Natural Gas
SRU Tail Gas N/A 0.01
FL-South South Flare 297 MMscf/yr
Process Gas
Natural Gas N/A 25.69
FL-West West Flare1 918 MMscf/yr
Process Gas
Natural Gas N/A 17.08
Fugitive Equipment N/A N/A 225.92
Truck Loading Rack 384 MMgal/yr N/A Various 1.98
2
Railcar Loading
Rack 122.6 MMgal/yr Various 0.06
Tanks See Attachement B N/A Various 49.26
-
Wastewater
Treatment System 480,596 Mgal/yr N/A Wastewater 15.56
FG-10
Crude Cooling
Tower 6,800 gpm N/A Cooling Water 4.70
FG-12
MSCC Cooling
Tower 5,700 gpm N/A Cooling Water 0.14
FG-13 Alky Cooling Tower 3,760 gpm N/A Cooling Water 138.22
488 hp
526 hp
Admin Emergency
Engine 206.4 bhp
Ultra-low sulfur
diesel N/A 6.18E-05
1 - West Flare baseline emissions are from calendar year 2021 since the unit was not operational in 2017.
2 - Emergency Fire Pump baseline emissions are from calendar year 2020 since the pump configuration changed from 2017.
4.24E-02
Emergency Fire
Pump2
Ultra-low sulfur
diesel N/A
Capacity
Emission Unit Description Emissions (tpy)

Attachment B: Potential to Emit

Big West Oil LLC
North Salt Lake Refinery
Ozone RACT: Potential to Emit
Source Source Description Units NOX VOC
BLR-1 Boiler #1 tpy 11.46 1.90
BLR-2 Boiler #2 / Shutdown tpy ----
BLR-6 Boiler #6 tpy 5.83 0.96
Wabash Wabash Boiler tpy 14.55 1.62
H-101 MSCC Heater tpy 31.42 1.23
H-301 Alkylation Unit Deisobutanizer Reboiler Heater tpy 10.10 0.40
H-402 #2 Crude Heater tpy 10.01 0.69
H-403 Preflash Heater tpy 9.46 0.37
H-404 #1 Crude Heater tpy 2.45 0.64
H-601 Unifiner Charge Heater tpy 18.92 0.74
H-621 Reformer Heater tpy 11.48 0.79
H-622 Reformer Heater tpy 3.30 0.23
H-624 Reformer Heater tpy 2.05 0.14
H-1001 MIDW Heater tpy 3.00 0.21
H-1002 HDS Heater tpy 2.20 0.15
H-1003 HDS Heater tpy 2.20 0.15
H-1102 SRU Tail Gas Incinerator tpy 1.00 0.07
FL-North North Flare / Shutdown tpy ----
FL-South South Flare tpy 10.30 86.34
FL-West West Flare tpy 23.74 48.88
-Natural Gas to Pilots, Sweep Gas tpy 0.28 0.02
R-102 Catalyst Regeneration System tpy 37.04 26.50
FG-10 Crude Cooling Tower tpy --4.45
FG-12 MSCC Cooling Tower tpy --3.73
FG-13 Alky Cooling Tower tpy --2.46
1-A/1-B Light Oil Dock - Truck tpy --15.93
2 Railcar Loading Facility and Vapor Combustor Unit tpy 12.12 5.12
4 Uncontrolled, Heavy Oil Loading - Rail tpy --4.06
-Fugitives - Piping Components tpy --167.93
-Fugitives - Paved Roads tpy ----
-Wastewater Treatment Plant tpy --48.06
-Emergency Fire Pump tpy 0.98 0.03
-Admin Emergency Engine tpy 1.60 0.13
-Tanks tpy --188.86
tpy 228.68 444.95
tpy 396.70
tpy 431.02
Total
Permit Emission Cap
Potential to Emit (Permit emission cap plus non-cap sources)
Big West Oil LLC
North Salt Lake Refinery
Ozone RACT: Potential to Emit - Tanks
Tank ID Tank Type
Tank Volume
(gal)
Total Loss
(ton
VOC/yr)
Tank 01B VFRT 46,666 0.86
Tank 03 EFRT 3,360,000 5.32
Tank 04 IFRT 1,260,000 10.41
Tank 05 EFRT 2,436,000 5.26
Tank 06 IFRT 3,360,000 4.51
Tank 09 IFRT 853,018 1.89
Tank 18 VFRT 1,260,000 0.62
Tank 20 IFRT 1,260,000 8.57
Tank 21 VFRT 2,439,092 0.95
Tank 22 VFRT 2,439,092 0.96
Tank 23 VFRT 817,535 0.45
Tank 24 VFRT 835,307 0.40
Tank 25 VFRT 1,680,000 0.88
Tank 28 EFRT 3,360,000 8.78
Tank 29 IFRT 1,680,000 9.53
Tank 30 VFRT 434,000 0.23
Tank 31 VFRT 456,000 0.29
Tank 33 VFRT 296,956 0.13
Tank 34 VFRT 630,000 0.22
Tank 35 IFRT 546,000 5.10
Tank 40 VFRT 840,000 0.34
Tank 42 IFRT 1,260,000 4.57
Tank 43 EFRT 3,360,000 9.11
Tank 44 IFRT 3,360,000 4.54
Tank 45 IFRT 1,680,000 11.68
Tank 50 IFRT 1,127,000 6.31
Tank 51 EFRT 420,000 4.80
Tank 52 EFRT 420,000 2.04
Tank 53 EFRT 420,000 8.53
Tank 54 EFRT 3,360,000 19.05
Tank 56 IFRT 304,542 1.80
Tank 59 IFRT 1,302,000 4.42
Tank 62 EFRT 840,000 5.33
Tank 65 IFRT 546,000 5.14
Tank 72 EFRT 420,000 7.87
Tank 75 IFRT 538,000 5.27
Tank 87 IFRT 57,007 16.54
Tank 90 IFRT 853,018 3.87
Tank 95 IFRT 1,260,000 2.30
188.86 Total:

Attachment C: Cost-Effectiveness Calculations

Table A
Big West Oil LLC
North Salt Lake Refinery
Ozone RACT: Cost Evaluation for NOx Sources
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible?
(Y / N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
UOP High Efficiency
(Low-NOx) Combustor
Design
Yes 18.56 Baseline N/A
Low-NOX Combustion
Promoter (non-
platinum)
40CFR 60.102a(b)(2)
80 ppmv 7-day rolling
average
Yes 18.56 Baseline N/A
NOX Reducing
Additive1
No N/A N/A N/A
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Selective Catalytic
Reduction (SCR)
No N/A N/A N/A
Fuel Gas Only -- no oil
burning
current SIP Yes 5.34 Baseline N/A
Ultra-Low Nox Burners
(w/ FGR)2
Yes 5.34 Baseline N/A
Selective Catalytic
Reduction (SCR)
Potentially 5.34 3.57 $440,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Flue Gas Recirculation No N/A N/A N/A
MSCC Unit Regenerator
R-102
BLR-1
Table A
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible?
(Y / N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
Fuel Gas Only -- no oil
burning
current SIP Yes 5.59 Baseline N/A
Low NOx Burners (w/
FGR)
NSPS Subpart Dc
NOI - 0.036 lb/MMBtu
Yes 5.59 Baseline N/A
Ultra-Low Nox Burners
(w/ FGR)2
Yes 5.59 Baseline N/A
Selective Catalytic
Reduction (SCR)
Potentially 5.59 3.66 $440,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Fuel Gas Only -- no oil
burning
current SIP Yes 2.88 Baseline N/A
Ultra-Low NOx Burners
(w/ FGR)2
Yes 2.88 Baseline N/A
Selective Catalytic
Reduction (SCR)
Potentially 2.88 1.93 $700,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Flue Gas Recirculation No N/A N/A N/A
Wabash Boiler (as
replacement to Boiler #2)
BLR-6
Table A
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible?
(Y / N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
Fuel Gas Only -- no oil
burning
current SIP Yes 3.60 Baseline N/A
Low NOx Burners
(staged)
Potentially 3.60 1.80 $250,000
Ultra Low NOx Burners
(staged)
Potentially 3.60 2.41 $190,000
Selective Catalytic
Reduction (SCR)
Potentially 3.60 3.28 $430,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Flue Gas Recirculation No N/A N/A N/A
Fuel Gas Only -- no oil
burning
current SIP Yes 8.24 Baseline N/A
Low NOx Burners
(staged)
Yes 8.24 Baseline N/A
Ultra Low Nox Burners
(staged)
Unknown 8.24 5.52 $72,000
Selective Catalytic
Reduction (SCR)
Potentially 8.24 7.50 $160,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Flue Gas Recirculation No N/A N/A N/A
H-101 FCC Heater
H-301 17.29 MMBtu/hr
Alkylation Unit
Deisobutanizer Reboiler
Heater
Table A
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible?
(Y / N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
Fuel Gas Only -- no oil
burning
current SIP Yes 9.05 Baseline N/A
Low NOx Burners
(staged)
Yes 9.05 Baseline N/A
Ultra Low NOx Burners
(staged)
Unknown 9.05 2.86 $150,000
Selective Catalytic
Reduction (SCR)
Potentially 9.05 7.36 $170,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Flue Gas Recirculation No N/A N/A N/A
Fuel Gas Only -- no oil
burning
current SIP Yes 7.94 Baseline N/A
Low NOx Burners
(staged)
Yes 7.94 3.97 $110,000
Ultra Low Nox Burners
(staged)
Potentially 7.94 5.22 $75,000
Selective Catalytic
Reduction (SCR)
Potentially 7.94 7.20 $170,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Flue Gas Recirculation No N/A N/A N/A
H-402 #2 Crude Heater
H-403 Crude Preflash Heater
Table A
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible?
(Y / N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
Fuel Gas Only -- no oil
burning
current SIP Yes 2.90 Baseline N/A
Ultra Low Nox Burners
(staged)
Yes 2.90 Baseline N/A
Selective Catalytic
Reduction (SCR)
Potentially 2.90 1.23 $1,000,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Flue Gas Recirculation No N/A N/A N/A
Fuel Gas Only -- no oil
burning
current SIP Yes 6.45 Baseline N/A
Low NOx Burners
(staged)
Yes 6.45 Baseline N/A
Ultra Low Nox Burners
(staged)
Potentially 6.45 2.04 $210,000
Selective Catalytic
Reduction (SCR)
Potentially 6.45 5.24 $250,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Flue Gas Recirculation No N/A N/A N/A
H-601 32.4 MMBtu/hr
Unifiner Heater
H-404 #1 Crude Heater with
Ultra-Low Nox Burners
(ULNB)
Table A
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible?
(Y / N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
Fuel Gas Only -- no oil
burning
current SIP Yes 24.83 Baseline N/A
Low NOx Burners
(staged)
Yes 24.83 Baseline N/A
Ultra Low Nox Burners
(staged)
Potentially 24.83 20.00 $64,000
Selective Catalytic
Reduction (SCR)
Potentially 24.83 20.00 $69,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Flue Gas Recirculation No N/A N/A N/A
H-621, 622, 624
Table A
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible?
(Y / N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
Fuel Gas Only -- no oil
burning
current SIP Yes 2.39 Baseline N/A
Low NOx Burners
(staged)
Yes 2.39 Baseline N/A
Ultra Low Nox Burners
(staged)
Potentially 2.39 0.79 $560,000
Selective Catalytic
Reduction (SCR)
Potentially 2.39 2.00 $600,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Flue Gas Recirculation No N/A N/A N/A
Fuel Gas Only -- no oil
burning
current SIP Yes 1.43 Baseline N/A
Low NOx Burners
(staged)
Yes 1.43 Baseline N/A
Ultra Low Nox Burners
(staged)
Potentially 1.43 0.49 $760,000
Selective Catalytic
Reduction (SCR)
Potentially 1.43 1.20 $980,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Flue Gas Recirculation No N/A N/A N/A
H-1001 (MIDW) Heater
H-1002 Hydrodesulfurization
(HDS) Reboiler
Table A
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible?
(Y / N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
Fuel Gas Only -- no oil
burning
current SIP Yes 1.65 Baseline N/A
Low NOx Burners
(staged)
Yes 1.65 Baseline N/A
Ultra Low Nox Burners
(staged)
Potentially 1.65 0.56 $640,000
Selective Catalytic
Reduction (SCR)
Potentially 1.65 1.40 $850,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
Flue Gas Recirculation No N/A N/A N/A
Fuel Gas Only -- no oil
burning
Yes 0.78 Baseline N/A
Low NOx Burners
(staged)
Potentially 0.78 0.39 $1,200,000
Ultra Low Nox Burners
(staged)
Potentially 0.78 0.26 $1,400,000
Selective Catalytic
Reduction (SCR)
Potentially 0.78 0.71 $1,600,000
Selective Non-Catalytic
Reduction (SNCR)
No N/A N/A N/A
H-1003 HDS Heater
H-1102 SRU and Tail Gas
Incinerator
Table A
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible?
(Y / N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
Compliance with NSPS
Subpart Ja flaring
provisions
40CFR 60.103a - Flare
Management Plan
Yes 3.06 Baseline N/A
Compliance with PM2.5
SIP Provisions
Part IX.H.11.g.v -
500,000 scfd vent gas per
flare
Yes 3.06 Baseline N/A
Compliance with RSR
flare operation
requirements - ensure
adequate combustion
efficiency
40 CFR 63.670 and
63.671
Yes 3.06 Baseline N/A
Flare Gas Recovery No N/A N/A N/A
South Refinery Flare
Table A
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible?
(Y / N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
Compliance with NSPS
Subpart Ja flaring
provisions
40CFR 60.103a - Flare
Management Plan
Yes 4.73 Baseline N/A
Compliance with PM2.5
SIP Provisions
Part IX.H.11.g.v -
500,000 scfd vent gas per
flare
Yes 4.73 Baseline N/A
Compliance with RSR
flare operation
requirements - ensure
adequate combustion
efficiency
40 CFR 63.670 and
63.671
Yes 4.73 Baseline N/A
Flare Gas Recovery No N/A N/A N/A
MACT Subpart ZZZZ -
Emergency
Classification
40 CFR 63.6640(f)
100 hr/yr operation in
non-emergency
scenarios.
Yes 0.00 Baseline N/A
Tier 3 classification Yes 0.00 Baseline N/A
Selective Catalytic
Reduction
Yes 0.00 0.00 $4,000,000,000
MACT Subpart ZZZZ -
Emergency
Classification
40 CFR 63.6640(f)
100 hr/yr operation in
non-emergency
scenarios.
Yes 0.14 Baseline N/A
Tier 3 classification Yes 0.14 Baseline N/A
Selective Catalytic
Reduction
Yes 0.14 0.13 $22,000,000
P-8908 Firewater Pump
526 hp
Admin Generator
237 hp
West Refinery Flare
Table A
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible?
(Y / N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
MACT Subpart ZZZZ -
Emergency
Classification
40 CFR 63.6640(f)
100 hr/yr operation in
non-emergency
scenarios.
Yes 0.11 Baseline N/A
Tier 3 classification Yes 0.11 Baseline N/A
Selective Catalytic
Reduction
Yes 0.11 0.10 $29,000,000
MACT Subpart ZZZZ -
Emergency
Classification
40 CFR 63.6640(f)
100 hr/yr operation in
non-emergency
scenarios.
Yes 0.11 Baseline N/A
Tier 3 classification Yes 0.11 Baseline N/A
Selective Catalytic
Reduction
Yes 0.11 0.10 $27,000,000
MACT Subpart ZZZZ -
Emergency
Classification
40 CFR 63.6640(f)
100 hr/yr operation in
non-emergency
scenarios.
Yes 0.11 Baseline N/A
Tier 3 classification Yes 0.11 Baseline N/A
Selective Catalytic
Reduction
Yes 0.11 0.10 $27,000,000
MACT Subpart ZZZZ -
Emergency
Classification
40 CFR 63.6640(f)
100 hr/yr operation in
non-emergency
scenarios.
Yes 0.04 Baseline N/A
Tier 3 classification Yes 0.04 Baseline N/A
Selective Catalytic
Reduction
Yes 0.04 0.03 $86,000,000
1) Based on reduction to 40 ppm from 50 ppm annual average.
2) Based on 0.035 lb/mbtu limit for ULNB on Boilers 1 and 6.
Backup Firewater Generator
96 hp
P-8911 Firewater Pump
526 hp
P-8910 Firewater Pump
526 hp
P-8909 Firewater Pump
526 hp
Table B
Big West Oil LLC
North Salt Lake Refinery
Ozone RACT: Cost Evaluation for VOC Sources
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible? (Y
/ N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
Compliance with NSPS
Supart Ja flaring
provisions
40 CFR 60.103a - Flare
Management Plan
Yes 25.69 Baseline currently implemented
Compliance with PM2.5
SIP Provisions
Part IX.H.11.g.v -
500,000 scfd vent gas per
flare
Yes 25.69 Baseline currently implemented
Compliance with RSR
flare operation
requirements - ensure
combustion efficiency
40 CFR 63.670 and
63.671
Yes 25.69 Baseline currently implemented
Flare Gas Recovery No N/A N/A N/A
Compliance with NSPS
Supart Ja flaring
provisions
40 CFR 60.103a - Flare
Management Plan
Yes 17.08 Baseline currently implemented
Compliance with PM2.5
SIP Provisions
Part IX.H.11.g.v -
500,000 scfd vent gas per
flare
Yes 17.08 Baseline currently implemented
Compliance with RSR
flare operation
requirements - ensure
combustion efficiency
40 CFR 63.670 and
63.671
Yes 17.08 Baseline currently implemented
Flare Gas Recovery No N/A N/A N/A
South Refinery Flare
West Refinery Flare
Table B
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible? (Y
/ N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
Compliance with 40 CFR
60 Subpart GGGa
40 CFR 60 Subpart
GGGa
Yes 225.92 Baseline currently implemented
Compliance with:
40 CFR 63 Subpart CC
40 CFR 63 Subpart CC Yes 225.92 Baseline currently implemented
Compliance with:
Utah R307-326
Utah R307-326 Yes 225.92 Baseline currently implemented
Compliance with:
Consent Decree
Consent Decree Yes 225.92 Baseline currently implemented
Vapor Recovery Unit
and Backup VRU
MACT Subpart CC:
10 mg/L
Yes 1.98 N/A currently implemented
Vapor Combustor Unit MACT Subpart CC:
10 mg/L
No N/A N/A N/A
Vapor Combustor Unit MACT Subpart CC:
10 mg/L
Yes 0.06 N/A currently implemented
Vapor Recovery Unit MACT Subpart CC:
10 mg/L
No N/A N/A N/A
Storage Tanks
Degassing to a vapor
combustion device
PM2.5 SIP Yes Baseline N/A currently implemented
Compliance with
Federal and State
Regulations
40 CFR 60 Subparts Kb,
MACT Subparts
CC/WW, R307-327
Yes Baseline N/A currently implemented
Fugitive Emissions that
are part of a LDAR
program
Truck Load Rack
Railcar Load Rack
Group 1 Tanks (Floating
Roof)
Table B
Source / Process Area Control Technology Rule / Emission Limit Technically Feasible? (Y
/ N)
Baseline
(TPY)
Incremental Emissions
Reduction (TPY)
Incremental Cost
Effectiveness ($/ton)
Group 2 Tanks (Fixed
Roof)
Pressure vacuum relief
valves Yes Baseline N/A currently implemented
API fixed cover Yes 15.56 Baseline currently implemented
Carbon canisters Yes 15.56 Baseline currently implemented
Thermal oxidizer Yes 15.56 15.0 $1,500,000
Monthly monitoring for
Heat Exchanger leaks
with Modified El Paso
stripper method
MACT Subpart CC
6.2 ppm VOC at cooling
water return
Yes 143.06 Baseline currently implemented
Drift Eliminators Yes 143.06 Baseline currently implemented
1) Assumes prorated reduction from current leak definition of 10,000 ppm (2010 AEI).
Fugitive Emissions --
Heat Exchange System
& Cooling Towers
Wastewater Treatment
System
Table C-1
Big West Oil LLC U
North Salt Lake Refinery
Ozone RACT: Cost Evaluation for MSCC - NOx
Unit
Control
Alternative
Reported
Reduction
(%)
Annual NOx
Emissions
(tpy)
NOx
Removed
(tpy)
Total Annualized
Cost
($)
Total Cost
Effectiveness
($/ton CO)
Adverse
Environmental
Impact
Health and
Safety Impact
Energy
Impacts
UOP High
Efficiency (Low-
NOx) Combustor
Design
0%18.56 0
Low-NOx
Combustion
Promoter (non-
platinum)
0%18.56 0 Additional
waste catalyst
NOx Reducing
Additive
25%18.56 4.6 3,173,319$ 683,905$ Additional
chemical
handling
R-102
Table C-2
Big West Oil LLC
North Salt Lake Refinery
Ozone RACT: Cost Evaluation for NOx Sources
NOx Control Options Costs
NOx Reducing
Additive1
Direct
Unit cost 69,142$
Foundations & support
Handling & erection
Electrical
Piping
Insulation
Gas supply
Painting
Total Direct Costs 70,000$
Indirect
Shipping
Engineering
Construction and field exp
Contractor fees
Startup
Performance testing
Contingencies 100%
Total Indirect Costs 138,284$
ANNUAL COSTS
Direct Annual Costs
Operating Labor 18,067$
Supervisor 3,881$
Operating Materials
Maintenance Labor
Material 1,784,407$
Utilities
Electricity
Natural Gas
Total Operating and Maintenance Costs 1,806,355$
Indirect Annual Costs
Overhead 1,324,633$
Property Tax 845$
Insurance 11,831$
Capital Recovery 29,656$
Total Annualized Cost 3,173,319$
Inflation costs were determined using the Bureau of Labor Statis
1Costs based on values received from BWO ($56,572, $20/lb, 200
Table D
Big West Oil LLC U
North Salt Lake Refinery
Ozone RACT: Cost Evaluation for Heaters and Boilers
iption Control Alternative
Reported
Reduction
(%)
Annual NOx
Emissions
(tpy)
NOx
Removed
(tpy)
Total Annualized
Cost
($)
Total Cost
Effectiveness
($/ton)
Adverse
Environmental
Impact
Health and
Safety Impact
Energy
Impacts
Heaters
Fuel Gas Only -- no oil
burning
0 3.60 0 -----
Low NOx Burners
(staged)
50%3.60 1.80 455,071.93$ 252,537$
Ultra Low NOx Burners
(staged)
67%3.60 2.41 448,051$ 185,726$ No No N/A
Selective Catalytic
Reduction (SCR)
91%3.60 3.28 1,407,950$ 429,458$ Yes Yes Energy
demand
Fuel Gas Only -- no oil
burning
0 8.24 0 -----
Low NOx Burners
(staged)
0%8.24 0.00 -
Ultra Low NOx Burners
(staged)
67%8.24 5.52 396,355$ 71,850$ No No N/A
Selective Catalytic
Reduction (SCR)
91%8.24 7.50 1,212,482$ 161,738$ Yes Yes Energy
demand
Fuel Gas Only -- no oil
burning
0 9.05 0 -----
Low NOx Burners
(staged)
0%9.05 0.00 -
Ultra Low NOx Burners
(staged)
32%9.05 2.86 420,661$ 147,050$ No No N/A
Selective Catalytic
Reduction (SCR)
81%9.05 7.36 1,280,245$ 173,924$ Yes Yes Energy
demand
Fuel Gas Only -- no oil
burning
0 7.94 0 -----
Low NOx Burners
(staged)
50%7.94 3.97 455,071.93$ 114,628$
Ultra Low NOx Burners
(staged)
66%7.94 5.22 393,578$ 75,333$ No No N/A
Selective Catalytic
Reduction (SCR)
91%7.94 7.20 1,206,546$ 167,621$ Yes Yes Energy
demand
Fuel Gas Only -- no oil
burning
--------
Ultra Low Nox Burners
(staged)
0%2.90 0.00 -
Selective Catalytic
Reduction (SCR)
42%2.90 1.23 1,266,039$ 1,028,421$ Yes Yes Energy
demand
H-101
H-301
H-402
H-403
H-404
Table D
Big West Oil LLC U
North Salt Lake Refinery
Ozone RACT: Cost Evaluation for Heaters and Boilers
iption Control Alternative
Reported
Reduction
(%)
Annual NOx
Emissions
(tpy)
NOx
Removed
(tpy)
Total Annualized
Cost
($)
Total Cost
Effectiveness
($/ton)
Adverse
Environmental
Impact
Health and
Safety Impact
Energy
Impacts
Fuel Gas Only -- no oil
burning
0 6.45 0 -----
Low NOx Burners
(staged)
0%6.45 0.00 -
Ultra Low NOx Burners
(staged)
32%6.45 2.04 424,172$ 208,160$ No No N/A
Selective Catalytic
Reduction (SCR)
81%6.45 5.24 1,292,667$ 246,533$ Yes Yes Energy
demand
Fuel Gas Only -- no oil
burning
0 24.83 0 -----
Low NOx Burners
(staged)
0%24.83 0.00 -
Ultra Low Nox Burners
(staged)
81%24.83 20.19 1,292,667$ 64,019$ No No N/A
Selective Catalytic
Reduction (SCR)
82%24.83 20.29 1,392,289$ 68,603$ Yes Yes Energy
demand
Fuel Gas Only -- no oil
burning
0 2.39 0 -----
Low NOx Burners
(staged)
0%2.39 0.00 -
Ultra Low NOx Burners
(staged)
33%2.39 0.79 444,903$ 562,705$ No No N/A
Selective Catalytic
Reduction (SCR)
82%2.39 1.96 1,166,592$ 596,365$ Yes Yes Energy
demand
Fuel Gas Only -- no oil
burning
0 1.43 0 -----
Low NOx Burners
(staged)
0%1.43 0.00 -
Ultra Low NOx Burners
(staged)
34%1.43 0.49 369,370$ 760,191$ No No N/A
Selective Catalytic
Reduction (SCR)
82%1.43 1.18 1,153,566$ 981,646$ Yes Yes Energy
demand
Fuel Gas Only -- no oil
burning
0 1.65 0 -----
Low NOx Burners
(staged)
0%1.65 0.00 -
Ultra Low NOx Burners
(staged)
34%1.65 0.56 357,202$ 639,225$ No No N/A
Selective Catalytic
Reduction (SCR)
82%1.65 1.35 1,153,602$ 853,581$ Yes Yes Energy
demand
Fuel Gas Only -- no oil
burning
0 0.78 0 -----
Low NOx Burners
(staged)
50%0.78 0.39 455,071.93$ 1,165,357$
Ultra Low NOx Burners
(staged)
34%0.78 0.26 357,202$ 1,350,172$ No No N/A
Selective Catalytic
Reduction (SCR)
91%0.78 0.71 1,134,226$ 1,596,492$ Yes Yes Energy
demand
H-621
H-622
H-624
H-1001
H-1002
H-1003
H-1102
H-601
Table D
Big West Oil LLC U
North Salt Lake Refinery
Ozone RACT: Cost Evaluation for Heaters and Boilers
iption Control Alternative
Reported
Reduction
(%)
Annual NOx
Emissions
(tpy)
NOx
Removed
(tpy)
Total Annualized
Cost
($)
Total Cost
Effectiveness
($/ton)
Adverse
Environmental
Impact
Health and
Safety Impact
Energy
Impacts
Boilers
Fuel Gas Only -- no oil
burning
-5.34 ------
Low NOx Burners
(staged)
-5.34 ------
Ultra Low NOx Burners
(staged)
0 5.34 0.00 -
Selective Catalytic
Reduction (SCR)
67%5.34 3.57 1,561,571$ 437,149$ Yes Yes Energy
demand
Fuel Gas Only -- no oil
burning
-5.59 ------
Low NOx Burners
(staged)
-5.59 ------
Ultra Low NOx Burners
(staged)
0 5.59 0.00 -----
Selective Catalytic
Reduction (SCR)
65%5.59 3.66 1,611,006$ 440,500$ Yes Yes Energy
demand
Fuel Gas Only -- no oil
burning
-2.88 ------
Low NOx Burners
(staged)
-2.88 ------
Ultra Low NOx Burners
(staged)
0 2.88 0.00 -
Selective Catalytic
Reduction (SCR)
67%2.88 1.93 1,342,468$ 695,830$ Yes Yes Energy
demand
BLR-
2/Wabash
BLR-6
BLR-1
Table D‐1
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
H-101 FCC Heater
Unit H-101
Parameter Value Units Basis
Design Duty 53.8 MMBtu/hr
2017 Natural Gas Throughput 0.6 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 71.5 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 824.9 Btu/scf 2017 GHG reporting data
2017 Effective HHV 826.6 Btu/scf Calculated
2017 NOx Emissions 3.6 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.121 lb NOx/MMBtu Calculated
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 91% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $12,526,556
Direct Operating Costs
Maintenance $62,633
Operator $87,600
Reagent $680
Electricity $19,847
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$9,819
Total Direct Operating Costs $180,579
Indirect Operating Costs
Administration $3,380
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$1,223,991
Total Indirect Operating Costs $1,227,370
Total Annual Cost $1,407,950
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)3.60 91.0% 0.33 3.28 $429,458
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)53.8 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 27.7 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)53.8 MMBtu/hr
NOX Removal Efficiency (nNOx)0.91 fraction
NOX Efficiency Adjustment Factor (nadj)1.2 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.121 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)133.2 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
6,557 143 1.05 150 2,549 8760 0.29 $680
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
0.29 19% 1.53 58 7.75 0.20 0.00
Ammonia Consumption
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
0.29 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
27.66 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
Table D‐2
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
H-301 Alkylation Unit Deisobutanizer Reboiler Heater
Unit H-301
Parameter Value Units Basis
Design Duty 17.3 MMBtu/hr
2017 Natural Gas Throughput 1.3 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 163.5 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 824.9 Btu/scf 2017 GHG reporting data
2017 Effective HHV 826.6 Btu/scf Calculated
2017 NOx Emissions 8.2 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.121 lb NOx/MMBtu Calculated
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 91% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $10,811,973
Direct Operating Costs
Maintenance $54,060
Operator $87,600
Reagent $1,555
Electricity $6,378
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$3,156
Total Direct Operating Costs $152,749
Indirect Operating Costs
Administration $3,277
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$1,056,456
Total Indirect Operating Costs $1,059,733
Total Annual Cost $1,212,482
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)8.24 91.0% 0.74 7.50 $161,738
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)17.3 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 8.9 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)17.3 MMBtu/hr
NOX Removal Efficiency (nNOx)0.91 fraction
NOX Efficiency Adjustment Factor (nadj)1.2 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.121 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)42.8 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
14,993 326 1.05 342 5,828 8760 0.67 $1,555
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
0.67 19% 3.53 58 7.75 0.45 0.01
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
0.67 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
8.89 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
Ammonia Consumption
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Table D‐3
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
H-402 Crude Heater
Unit H-402
Parameter Value Units Basis
Design Duty 30.0 MMBtu/hr
2017 Natural Gas Throughput 48.8 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 313.3 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 825.3 Btu/scf 2017 GHG reporting data
2017 Effective HHV 855.0 Btu/scf Calculated
2017 NOx Emissions 9.1 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.058 lb NOx/MMBtu Calculated
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 81% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $11,408,860
Direct Operating Costs
Maintenance $57,044
Operator $87,600
Reagent $1,527
Electricity $11,067
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$4,915
Total Direct Operating Costs $162,153
Indirect Operating Costs
Administration $3,313
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$1,114,779
Total Indirect Operating Costs $1,118,091
Total Annual Cost $1,280,245
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)9.05 81.3% 1.69 7.36 $173,924
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)30.0 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 15.4 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)30.0 MMBtu/hr
NOX Removal Efficiency (nNOx)0.81 fraction
NOX Efficiency Adjustment Factor (nadj)1.1 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.058 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)66.7 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
14,722 320 1.05 336 5,722 8760 0.65 $1,527
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
0.65 19% 3.42 58 7.75 0.44 0.01
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
0.65 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
15.43 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
Ammonia Consumption
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Table D‐4
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
H-403 Crude Preflash Heater
Unit H-403
Parameter Value Units Basis
Design Duty 16.2 MMBtu/hr
2017 Natural Gas Throughput 21.4 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 137.4 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 825.3 Btu/scf 2017 GHG reporting data
2017 Effective HHV 855.0 Btu/scf Calculated
2017 NOx Emissions 7.9 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.117 lb NOx/MMBtu Calculated
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 91% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $10,760,784
Direct Operating Costs
Maintenance $53,804
Operator $87,600
Reagent $1,493
Electricity $5,976
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$2,945
Total Direct Operating Costs $151,818
Indirect Operating Costs
Administration $3,274
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$1,051,454
Total Indirect Operating Costs $1,054,728
Total Annual Cost $1,206,546
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)7.94 90.7% 0.74 7.20 $167,621
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)16.2 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 8.3 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)16.2 MMBtu/hr
NOX Removal Efficiency (nNOx)0.91 fraction
NOX Efficiency Adjustment Factor (nadj)1.2 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.117 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)39.9 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
14,396 313 1.05 329 5,596 8760 0.64 $1,493
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
0.64 19% 3.37 58 7.75 0.43 0.01
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
0.64 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
8.33 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
Ammonia Consumption
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Table D‐5
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
H-404 #1 Crude Heater
Unit H-404
Parameter Value Units Basis
Design Duty 27.9 MMBtu/hr
2017 Natural Gas Throughput 48.6 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 311.4 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 825.3 Btu/scf 2017 GHG reporting data
2017 Effective HHV 855.0 Btu/scf Calculated
2017 NOx Emissions 2.9 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.019 lb NOx/MMBtu Stack Test Data
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 42% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $11,310,240
Direct Operating Costs
Maintenance $56,551
Operator $87,600
Reagent $255
Electricity $10,292
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$2,891
Total Direct Operating Costs $157,590
Indirect Operating Costs
Administration $3,307
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$1,105,143
Total Indirect Operating Costs $1,108,449
Total Annual Cost $1,266,039
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)2.90 42.5% 1.67 1.23 $1,028,421
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)27.9 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 14.3 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)27.9 MMBtu/hr
NOX Removal Efficiency (nNOx)0.42 fraction
NOX Efficiency Adjustment Factor (nadj)0.7 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.019 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)39.2 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
2,462 54 1.05 56 957 8760 0.11 $255
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
0.11 19% 0.58 58 7.75 0.07 0.00
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
0.11 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
14.35 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
Ammonia Consumption
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Table D‐6
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
H-601 Unifiner Heater
Unit H-601
Parameter Value Units Basis
Design Duty 32.4 MMBtu/hr
2017 Natural Gas Throughput 34.8 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 223.1 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 825.3 Btu/scf 2017 GHG reporting data
2017 Effective HHV 855.0 Btu/scf Calculated
2017 NOx Emissions 6.4 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.058 lb NOx/MMBtu Calculated
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 81% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $11,521,569
Direct Operating Costs
Maintenance $57,608
Operator $87,600
Reagent $1,088
Electricity $11,953
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$5,308
Total Direct Operating Costs $163,556
Indirect Operating Costs
Administration $3,319
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$1,125,792
Total Indirect Operating Costs $1,129,111
Total Annual Cost $1,292,667
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)6.45 81.3% 1.21 5.24 $246,533
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)32.4 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 16.7 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)32.4 MMBtu/hr
NOX Removal Efficiency (nNOx)0.81 fraction
NOX Efficiency Adjustment Factor (nadj)1.1 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.058 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)72.0 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
10,487 228 1.05 239 4,076 8760 0.47 $1,088
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
0.47 19% 2.47 58 7.75 0.32 0.01
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
0.47 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
16.66 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
Ammonia Consumption
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
Table D‐7
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
H-621, 622, 624 Reformer Heater
Unit H-621
Parameter Value Units Basis
Design Duty 50.4 MMBtu/hr
2017 Natural Gas Throughput 131.0 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 840.3 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 825.3 Btu/scf 2017 GHG reporting data
2017 Effective HHV 855.0 Btu/scf Calculated
2017 NOx Emissions 24.8 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.060 lb NOx/MMBtu Calculated
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 82% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $12,366,885
Direct Operating Costs
Maintenance $61,834
Operator $87,600
Reagent $4,210
Electricity $18,593
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$8,292
Total Direct Operating Costs $180,530
Indirect Operating Costs
Administration $3,370
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$1,208,389
Total Indirect Operating Costs $1,211,759
Total Annual Cost $1,392,289
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)24.83 81.7% 4.54 20.29 $68,603
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)50.4 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 25.9 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)50.4 MMBtu/hr
NOX Removal Efficiency (nNOx)0.82 fraction
NOX Efficiency Adjustment Factor (nadj)1.2 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.060 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)112.5 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
40,590 882 1.05 926 15,777 8760 1.80 $4,210
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
1.80 19% 9.47 58 7.75 1.22 0.02
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
1.8 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
25.92 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
Ammonia Consumption
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
Table D‐8
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
H-1001 MIDW Heater
Unit H-1001
Parameter Value Units Basis
Design Duty 9.0 MMBtu/hr
2017 Natural Gas Throughput 0.7 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 94.8 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 824.9 Btu/scf 2017 GHG reporting data
2017 Effective HHV 826.6 Btu/scf Calculated
2017 NOx Emissions 2.4 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.060 lb NOx/MMBtu Calculated
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 82% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $10,422,658
Direct Operating Costs
Maintenance $52,113
Operator $87,600
Reagent $406
Electricity $3,320
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$1,484
Total Direct Operating Costs $144,923
Indirect Operating Costs
Administration $3,253
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$1,018,415
Total Indirect Operating Costs $1,021,669
Total Annual Cost $1,166,592
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)2.39 81.9% 0.43 1.96 $596,365
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)9.0 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 4.6 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)9.0 MMBtu/hr
NOX Removal Efficiency (nNOx)0.82 fraction
NOX Efficiency Adjustment Factor (nadj)1.2 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.060 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)20.1 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
3,912 85 1.05 89 1,521 8760 0.17 $406
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
0.17 19% 0.89 58 7.75 0.12 0.00
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
0.17 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
4.63 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
Ammonia Consumption
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Table D‐9
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
H-1002 HDS Reboiler
Unit H-1002
Parameter Value Units Basis
Design Duty 6.6 MMBtu/hr
2017 Natural Gas Throughput 0.4 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 56.9 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 824.9 Btu/scf 2017 GHG reporting data
2017 Effective HHV 826.6 Btu/scf Calculated
2017 NOx Emissions 1.4 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.060 lb NOx/MMBtu Calculated
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 82% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $10,309,949
Direct Operating Costs
Maintenance $51,550
Operator $87,600
Reagent $244
Electricity $2,435
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$1,088
Total Direct Operating Costs $142,917
Indirect Operating Costs
Administration $3,247
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$1,007,402
Total Indirect Operating Costs $1,010,649
Total Annual Cost $1,153,566
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)1.43 81.9% 0.26 1.18 $981,646
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)6.6 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 3.4 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)6.6 MMBtu/hr
NOX Removal Efficiency (nNOx)0.82 fraction
NOX Efficiency Adjustment Factor (nadj)1.2 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.060 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)14.8 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
2,350 51 1.05 54 914 8760 0.10 $244
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
0.10 19% 0.53 58 7.75 0.07 0.00
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
0.1 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
3.39 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
Ammonia Consumption
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Table D‐10
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
H-1003 HDS Heater
Unit H-1003
Parameter Value Units Basis
Design Duty 6.6 MMBtu/hr
2017 Natural Gas Throughput 0.5 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 65.5 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 824.9 Btu/scf 2017 GHG reporting data
2017 Effective HHV 826.6 Btu/scf Calculated
2017 NOx Emissions 1.6 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.060 lb NOx/MMBtu Calculated
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 82% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $10,309,949
Direct Operating Costs
Maintenance $51,550
Operator $87,600
Reagent $280
Electricity $2,435
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$1,088
Total Direct Operating Costs $142,953
Indirect Operating Costs
Administration $3,247
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$1,007,402
Total Indirect Operating Costs $1,010,649
Total Annual Cost $1,153,602
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)1.65 81.9% 0.30 1.35 $853,581
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)6.6 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 3.4 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)6.6 MMBtu/hr
NOX Removal Efficiency (nNOx)0.82 fraction
NOX Efficiency Adjustment Factor (nadj)1.2 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.060 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)14.8 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
2,703 59 1.05 62 1,051 8760 0.12 $280
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
0.12 19% 0.63 58 7.75 0.08 0.00
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
0.12 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
3.39 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
Ammonia Consumption
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Table D‐11
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
H-1102 SRU and Tail Gas Incinerator
Unit H-1102
Parameter Value Units Basis
Design Duty 3.0 MMBtu/hr
2017 Natural Gas Throughput 0.1 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 15.5 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 824.9 Btu/scf 2017 GHG reporting data
2017 Effective HHV 826.6 Btu/scf Calculated
2017 NOx Emissions 0.8 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.121 lb NOx/MMBtu Calculated
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 91% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $10,140,886
Direct Operating Costs
Maintenance $50,704
Operator $87,600
Reagent $147
Electricity $1,107
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$548
Total Direct Operating Costs $140,106
Indirect Operating Costs
Administration $3,236
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$990,883
Total Indirect Operating Costs $994,119
Total Annual Cost $1,134,226
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)0.78 91.0% 0.07 0.71 $1,596,492
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)3.0 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 1.5 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)3.0 MMBtu/hr
NOX Removal Efficiency (nNOx)0.91 fraction
NOX Efficiency Adjustment Factor (nadj)1.2 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.121 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)7.4 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
1,421 31 1.05 32 552 8760 0.06 $147
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
0.06 19% 0.32 58 7.75 0.04 0.00
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
0.06 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
1.54 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
Ammonia Consumption
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Table D‐12
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
BLR-1
Unit BLR-1
Parameter Value Units Basis
Design Duty 83.0 MMBtu/hr
2017 Natural Gas Throughput 45.4 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 291.2 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 825.3 Btu/scf 2017 GHG reporting data
2017 Effective HHV 855.0 Btu/scf Calculated
2017 NOx Emissions 5.3 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.033 lb NOx/MMBtu Stack Test Data
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 67% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $13,897,846
Direct Operating Costs
Maintenance $69,489
Operator $87,600
Reagent $741
Electricity $30,619
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$11,677
Total Direct Operating Costs $200,127
Indirect Operating Costs
Administration $3,462
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$1,357,982
Total Indirect Operating Costs $1,361,444
Total Annual Cost $1,561,571
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)5.34 66.9% 1.77 3.57 $437,149
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)83.0 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 42.7 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)83.0 MMBtu/hr
NOX Removal Efficiency (nNOx)0.67 fraction
NOX Efficiency Adjustment Factor (nadj)1.0 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.033 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)158.4 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
7,144 155 1.05 163 2,777 8760 0.32 $741
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
0.32 19% 1.68 58 7.75 0.22 0.00
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
0.32 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
42.68 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
Ammonia Consumption
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Table D‐13
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
Wabash Boiler
Unit Wabash Boiler
Parameter Value Units Basis
Design Duty 92.3 MMBtu/hr
2017 Natural Gas Throughput 55.8 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 357.7 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 825.3 Btu/scf 2017 GHG reporting data
2017 Effective HHV 855.0 Btu/scf Calculated
2017 NOx Emissions 5.6 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.032 lb NOx/MMBtu Calculated
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 65% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $14,334,593
Direct Operating Costs
Maintenance $71,673
Operator $87,600
Reagent $759
Electricity $34,050
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$12,779
Total Direct Operating Costs $206,861
Indirect Operating Costs
Administration $3,488
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$1,400,657
Total Indirect Operating Costs $1,404,145
Total Annual Cost $1,611,006
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)5.59 65.4% 1.93 3.66 $440,500
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)92.3 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 47.5 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)92.3 MMBtu/hr
NOX Removal Efficiency (nNOx)0.65 fraction
NOX Efficiency Adjustment Factor (nadj)1.0 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.032 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)173.3 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
7,314 159 1.05 167 2,843 8760 0.32 $759
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
0.32 19% 1.68 58 7.75 0.22 0.00
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
0.32 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
47.46 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
Ammonia Consumption
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Table D‐14
Big West Oil LLC
Ozone RACT Analysis
Selective Catalytic Reduction (SCR)
BLR-6
Unit BLR-6
Parameter Value Units Basis
Design Duty 42.0 MMBtu/hr
2017 Natural Gas Throughput 1.6 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 202.9 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 824.9 Btu/scf 2017 GHG reporting data
2017 Effective HHV 826.6 Btu/scf Calculated
2017 NOx Emissions 2.9 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.033 lb NOx/MMBtu Stack Test Data
SCR NOx Emission Rate 0.011 lb NOx/MMBtu Assuming 9 ppm at 3% O2
Design Control Efficiency 67% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $11,972,404
Direct Operating Costs
Maintenance $59,862
Operator $87,600
Reagent $400
Electricity $15,494
Future Worth Factor (8.5%, 4 year life)0.22
Catalyst Replacement (8.5%, 4 year life)$5,922
Total Direct Operating Costs $169,278
Indirect Operating Costs
Administration $3,346
Capital Recovery Factor (8.5%, 25 year life)0.10
Capital Recovery (8.5%, 25 year life)$1,169,844
Total Indirect Operating Costs $1,173,190
Total Annual Cost $1,342,468
Emission Control Cost Calculation
2017 Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx)2.88 67.1% 0.95 1.93 $695,830
Assumptions
Space is available for installation of SCR unit
Exhaust temperature allows implementation of SCR without reheating
Power Consumption Value Units Basis
Fuel Natural Gas
Coal Type Oil and Natural Gas
Maximum Heat Rate Input (QB)42.0 MMBtu/hr
Net Plant Heat Rate (NPHR) 8.2 MMBtu/MW Default factor for Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Coal Factor (CoalF) 1 Default factor for Oil and Natural Gas as listed in EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Heat Rate Factor (HRF) 0.82 HRF = NPHR/10 per Eq. 2.6 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Power Consumption (P) 21.6 kW
P = 0.1*QB*1,000*0.0056*(CoalF*HRF)^0.43 per Eq. 2.61 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Catalyst Consumption Value Units Basis
Maximum Heat Rate Input (QB)42.0 MMBtu/hr
NOX Removal Efficiency (nNOx)0.67 fraction
NOX Efficiency Adjustment Factor (nadj)1.0 nadj = 0.2869+(1.058*nNOx) per Eq. 2.23 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Ammonia Slip (Slip) 10.0 ppm Assumed ammonia slip of 10 parts per million
Ammonia Slip Adjustment Factor (Slipadj)0.7 Slipadj = 1.2835-(0.0567*Slip) per Eq. 2.24 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Inlet NOX Level (NOXin)0.033 lb/MMBtu
NOX Adjustment Factor (NOXadj)0.9 NOXadj = 0.8524+(0.3208*NOXin) per Eq. 2.25 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Sulfur Content of Fuel (S) 0.0 fraction
Sulfur in Coal Adjustment Factor (Sadj)0.964 Sadj = 0.9636+(0.0455*S) per Eq. 2.26 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Gas Temperature at SCR Inlet (T) 650 °F Assumed temperature of 650°F
Temperature Adjustment Factor (T adj)1.15 Tadj = 15.16-(0.03937*T)+(2.74E-05*T^2) per Eq. 2.27 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Number of SCR Reactor Chambers (n SCR)1
Catalyst Volume (Volcatalyst)80.3 ft3 Volcatalyst = 2.81*QB*nadj*Slipadj*NOXadj*Sadj*Tadj/NSCR per Eq. 2.22 of EPA Air Pollution Control Cost Manual Section 4.2 Ch. 2 for Selective Catalytic Reduction
Cost of Catalyst (CCreplace)334.7 $/ft3 EPA default value of $227 for the catalyst cost based on 2016 prices, adjusted to 2023 pricing using CEPCI values of 541.7 for 2016 and 798.7 for 2023.
Ammonia demand neat
NOx Reduction SRF lb-mole/yr lb/yr Op Hours lb/hr neat Annual cost at $/lb
lbs/yr lb mole/yr hr/yr $0.267
3,859 84 1.05 88 1,500 8760 0.17 $400
Aqua Ammonia Use Rate Density Aqua Ammonia
lb/hr neat Wt% NH3 Lb/hr lb/ft3 lb/gal gal/hr gal/min
0.17 19% 0.89 58 7.75 0.12 0.00
EPA Air Pollution Control Cost Manual Section 4, Chapter 2, Response to Comments.
= 365 days/yr * $60/hr operator rate * 4 hr/day.
Operator rate of $60/hr from EPA's SCR Cost Calculation Spreadsheet
Basis
Calculated based on correlation formula from Fig. B-4 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.57). = 0.5% of TCI
0.17 lb/hr anhydrous ammonia and estimated reagent rates based on current market ($0.267/lb ammonia)
21.6 kW usage based on EPA Air Pollution Control Cost Manual estimate and $0.0819/kWh US EIA August 2022 Industrial Costs for Utah
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.65). = i*(1/((1+i)^y-1), where i is the prime rate and y is the term in years.
All layers replaced per 4-year replacement period including future worth factor calculation
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.69). = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost), where
Operator Cost = 365 days/yr * $60/hr operator rate * 4 hr/day
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.71). = (i*(1+i)^n) / ((1+i)^n-1), where i is the prime rate and n is the equipment life.
EPA Air Pollution Control Cost Manual (Chapter 2, Equation 2.70). = capital recovery factor * total capital investment
Note A: EPA methodology for ammonia consumption was used according to the following formula: ((Uncontrolled NOx lb/hr) x (Removal efficiency) x SRF x MW-NH3)/MW-NOx, where SRF = Stoichiometric ratio factor = 1.05, MW-NH3 = 17.03, MW-NOx =
46.01. Reagent costs are estimated based on current market. Platts Ammonia price chart, December 2023, US, gray ammonia https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/energy-transition/051023-interactive-ammonia-price-
chart-natural-gas-feedstock-europe-usgc-black-sea
Ammonia Consumption
Basis
Control efficiency based upon improvement from 2017 performance to 9 ppm at 3% O2.
Table D‐15
Big West Oil LLC
Ozone RACT Analysis
Ultra-Low NOx Burners (ULNB)
H-101 FCC Heater
Unit H-101
Parameter Value Units Basis
Design Duty MMBtu/hr 53.8
2017 Natural Gas Throughput 0.6 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 71.5 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 824.9 Btu/scf 2017 GHG reporting data
2017 Effective HHV 826.6 Btu/scf Calculated
2017 NOx Emissions 3.6 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.121 lb NOx/MMBtu Calculated
ULNB NOx Emission Rate 0.04 lb NOx/MMBtu Conservative emission rate estimate; actual emission rate would require analysis and guarantee by equipment vendor
Design Control Efficiency 67% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $3,075,774
Direct Operating Costs
Maintenance and Operation $0
Indirect Operating Costs
Overhead (60% of Maintenance and Operation) $0
Administration (2% total capital costs) $61,515
Property tax (1% total capital costs) $30,758
Insurance (1% total capital costs) $30,758
Capital Recovery Factor (8.5%, 20 year life) 0.11
Capital Recovery (8.5%, 20 year life) $325,020
Total Indirect Operating Costs $448,051
Total Annual Cost $448,051
Emission Control Cost Calculation
Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx) 3.60 66.9% 1.19 2.41 $185,726 Controlled emissions based on 0.04 lb/MMBtu.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.7
Basis
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Calculated based on correlation formula from Fig. B-7 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
Assumed negligible change from current burners.
Table D‐16
Big West Oil LLC
Ozone RACT Analysis
Ultra-Low NOx Burners (ULNB)
H-301 Alkylation Unit Deisobutanizer Reboiler Heater
Unit H-301
Parameter Value Units Basis
Design Duty MMBtu/hr 17.3
2017 Natural Gas Throughput 1.3 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 163.5 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 824.9 Btu/scf 2017 GHG reporting data
2017 Effective HHV 826.6 Btu/scf Calculated
2017 NOx Emissions 8.2 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.121 lb NOx/MMBtu Calculated
ULNB NOx Emission Rate 0.04 lb NOx/MMBtu Conservative emission rate estimate; actual emission rate would require analysis and guarantee by equipment vendor
Design Control Efficiency 67% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $2,720,895
Direct Operating Costs
Maintenance and Operation $0
Indirect Operating Costs
Overhead (60% of Maintenance and Operation) $0
Administration (2% total capital costs) $54,418
Property tax (1% total capital costs) $27,209
Insurance (1% total capital costs) $27,209
Capital Recovery Factor (8.5%, 20 year life) 0.11
Capital Recovery (8.5%, 20 year life) $287,520
Total Indirect Operating Costs $396,355
Total Annual Cost $396,355
Emission Control Cost Calculation
Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx) 8.24 66.9% 2.72 5.52 $71,850
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Calculated based on correlation formula from Fig. B-7 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
Assumed negligible change from current burners.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.7
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
Controlled emissions based on 0.04 lb/MMBtu.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Table D‐17
Big West Oil LLC
Ozone RACT Analysis
Ultra-Low NOx Burners (ULNB)
H-402 Crude Heater
Unit H-402
Parameter Value Units Basis
Design Duty MMBtu/hr 30.0
2017 Natural Gas Throughput 48.8 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 313.3 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 825.3 Btu/scf 2017 GHG reporting data
2017 Effective HHV 855.0 Btu/scf Calculated
2017 NOx Emissions 9.1 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.058 lb NOx/MMBtu Calculated
ULNB NOx Emission Rate 0.04 lb NOx/MMBtu Conservative emission rate estimate; actual emission rate would require analysis and guarantee by equipment vendor
Design Control Efficiency 32% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $2,887,747
Direct Operating Costs
Maintenance and Operation $0
Indirect Operating Costs
Overhead (60% of Maintenance and Operation) $0
Administration (2% total capital costs) $57,755
Property tax (1% total capital costs) $28,877
Insurance (1% total capital costs) $28,877
Capital Recovery Factor (8.5%, 20 year life) 0.11
Capital Recovery (8.5%, 20 year life) $305,151
Total Indirect Operating Costs $420,661
Total Annual Cost $420,661
Emission Control Cost Calculation
Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx) 9.05 31.6% 6.19 2.86 $147,050
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Calculated based on correlation formula from Fig. B-7 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
Assumed negligible change from current burners.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.7
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
Controlled emissions based on 0.04 lb/MMBtu.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Table D‐18
Big West Oil LLC
Ozone RACT Analysis
Ultra-Low NOx Burners (ULNB)
H-403 Crude Preflash Heater
Unit H-403
Parameter Value Units Basis
Design Duty MMBtu/hr 16.2
2017 Natural Gas Throughput 21.4 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 137.4 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 825.3 Btu/scf 2017 GHG reporting data
2017 Effective HHV 855.0 Btu/scf Calculated
2017 NOx Emissions 7.9 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.117 lb NOx/MMBtu Calculated
ULNB NOx Emission Rate 0.04 lb NOx/MMBtu Conservative emission rate estimate; actual emission rate would require analysis and guarantee by equipment vendor
Design Control Efficiency 66% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $2,701,827
Direct Operating Costs
Maintenance and Operation $0
Indirect Operating Costs
Overhead (60% of Maintenance and Operation) $0
Administration (2% total capital costs) $54,037
Property tax (1% total capital costs) $27,018
Insurance (1% total capital costs) $27,018
Capital Recovery Factor (8.5%, 20 year life) 0.11
Capital Recovery (8.5%, 20 year life) $285,505
Total Indirect Operating Costs $393,578
Total Annual Cost $393,578
Emission Control Cost Calculation
Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx) 7.94 65.8% 2.72 5.22 $75,333
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Calculated based on correlation formula from Fig. B-7 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
Assumed negligible change from current burners.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.7
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
Controlled emissions based on 0.04 lb/MMBtu.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Table D‐19
Big West Oil LLC
Ozone RACT Analysis
Ultra-Low NOx Burners (ULNB)
H-601 Unifiner Heater
Unit H-601
Parameter Value Units Basis
Design Duty MMBtu/hr 32.4
2017 Natural Gas Throughput 34.8 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 223.1 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 825.3 Btu/scf 2017 GHG reporting data
2017 Effective HHV 855.0 Btu/scf Calculated
2017 NOx Emissions 6.4 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.058 lb NOx/MMBtu Calculated
ULNB NOx Emission Rate 0.04 lb NOx/MMBtu Conservative emission rate estimate; actual emission rate would require analysis and guarantee by equipment vendor
Design Control Efficiency 32% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $2,911,849
Direct Operating Costs
Maintenance and Operation $0
Indirect Operating Costs
Overhead (60% of Maintenance and Operation) $0
Administration (2% total capital costs) $58,237
Property tax (1% total capital costs) $29,118
Insurance (1% total capital costs) $29,118
Capital Recovery Factor (8.5%, 20 year life) 0.11
Capital Recovery (8.5%, 20 year life) $307,698
Total Indirect Operating Costs $424,172
Total Annual Cost $424,172
Emission Control Cost Calculation
Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx) 6.45 31.6% 4.41 2.04 $208,160
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Calculated based on correlation formula from Fig. B-7 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
Assumed negligible change from current burners.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.7
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
Controlled emissions based on 0.04 lb/MMBtu.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Table D‐20
Big West Oil LLC
Ozone RACT Analysis
Ultra-Low NOx Burners (ULNB)
H-621, 622, 624 Reformer Heater
Unit H-621
Parameter Value Units Basis
Design Duty MMBtu/hr 50.4
2017 Natural Gas Throughput 131.0 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 840.3 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 825.3 Btu/scf 2017 GHG reporting data
2017 Effective HHV 855.0 Btu/scf Calculated
2017 NOx Emissions 24.8 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.060 lb NOx/MMBtu Calculated
ULNB NOx Emission Rate 0.04 lb NOx/MMBtu Conservative emission rate estimate; actual emission rate would require analysis and guarantee by equipment vendor
Design Control Efficiency 33% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $3,054,165
Direct Operating Costs
Maintenance and Operation $0
Indirect Operating Costs
Overhead (60% of Maintenance and Operation) $0
Administration (2% total capital costs) $61,083
Property tax (1% total capital costs) $30,542
Insurance (1% total capital costs) $30,542
Capital Recovery Factor (8.5%, 20 year life) 0.11
Capital Recovery (8.5%, 20 year life) $322,737
Total Indirect Operating Costs $444,903
Total Annual Cost $444,903
Emission Control Cost Calculation
Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx) 24.83 33.1% 16.61 8.22 $54,100
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Calculated based on correlation formula from Fig. B-7 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
Assumed negligible change from current burners.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.7
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
Controlled emissions based on 0.04 lb/MMBtu.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Table D‐21
Big West Oil LLC
Ozone RACT Analysis
Ultra-Low NOx Burners (ULNB)
H-1001 MIDW Heater
Unit H-1001
Parameter Value Units Basis
Design Duty MMBtu/hr 9.0
2017 Natural Gas Throughput 0.7 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 94.8 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 824.9 Btu/scf 2017 GHG reporting data
2017 Effective HHV 826.6 Btu/scf Calculated
2017 NOx Emissions 2.4 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.060 lb NOx/MMBtu Calculated
ULNB NOx Emission Rate 0.04 lb NOx/MMBtu Conservative emission rate estimate; actual emission rate would require analysis and guarantee by equipment vendor
Design Control Efficiency 34% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $2,535,643
Direct Operating Costs
Maintenance and Operation $0
Indirect Operating Costs
Overhead (60% of Maintenance and Operation) $0
Administration (2% total capital costs) $50,713
Property tax (1% total capital costs) $25,356
Insurance (1% total capital costs) $25,356
Capital Recovery Factor (8.5%, 20 year life) 0.11
Capital Recovery (8.5%, 20 year life) $267,944
Total Indirect Operating Costs $369,370
Total Annual Cost $369,370
Emission Control Cost Calculation
Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx) 2.39 33.9% 1.58 0.81 $456,672
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Calculated based on correlation formula from Fig. B-7 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
Assumed negligible change from current burners.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.7
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
Controlled emissions based on 0.04 lb/MMBtu.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Table D‐22
Big West Oil LLC
Ozone RACT Analysis
Ultra-Low NOx Burners (ULNB)
H-1002 HDS Reboiler
Unit H-1002
Parameter Value Units Basis
Design Duty MMBtu/hr 6.6
2017 Natural Gas Throughput 0.4 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 56.9 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 824.9 Btu/scf 2017 GHG reporting data
2017 Effective HHV 826.6 Btu/scf Calculated
2017 NOx Emissions 1.4 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.060 lb NOx/MMBtu Calculated
ULNB NOx Emission Rate 0.04 lb NOx/MMBtu Conservative emission rate estimate; actual emission rate would require analysis and guarantee by equipment vendor
Design Control Efficiency 34% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $2,452,114
Direct Operating Costs
Maintenance and Operation $0
Indirect Operating Costs
Overhead (60% of Maintenance and Operation) $0
Administration (2% total capital costs) $49,042
Property tax (1% total capital costs) $24,521
Insurance (1% total capital costs) $24,521
Capital Recovery Factor (8.5%, 20 year life) 0.11
Capital Recovery (8.5%, 20 year life) $259,117
Total Indirect Operating Costs $357,202
Total Annual Cost $357,202
Emission Control Cost Calculation
Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx) 1.43 33.9% 0.95 0.49 $735,159
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Calculated based on correlation formula from Fig. B-7 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
Assumed negligible change from current burners.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.7
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
Controlled emissions based on 0.04 lb/MMBtu.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Table D‐23
Big West Oil LLC
Ozone RACT Analysis
Ultra-Low NOx Burners (ULNB)
H-1003 HDS Heater
Unit H-1003
Parameter Value Units Basis
Design Duty MMBtu/hr 6.6
2017 Natural Gas Throughput 0.5 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 65.5 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 824.9 Btu/scf 2017 GHG reporting data
2017 Effective HHV 826.6 Btu/scf Calculated
2017 NOx Emissions 1.6 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.060 lb NOx/MMBtu Calculated
ULNB NOx Emission Rate 0.04 lb NOx/MMBtu Conservative emission rate estimate; actual emission rate would require analysis and guarantee by equipment vendor
Design Control Efficiency 34% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $2,452,114
Direct Operating Costs
Maintenance and Operation $0
Indirect Operating Costs
Overhead (60% of Maintenance and Operation) $0
Administration (2% total capital costs) $49,042
Property tax (1% total capital costs) $24,521
Insurance (1% total capital costs) $24,521
Capital Recovery Factor (8.5%, 20 year life) 0.11
Capital Recovery (8.5%, 20 year life) $259,117
Total Indirect Operating Costs $357,202
Total Annual Cost $357,202
Emission Control Cost Calculation
Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx) 1.65 33.9% 1.09 0.56 $639,275
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Calculated based on correlation formula from Fig. B-7 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
Assumed negligible change from current burners.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.7
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
Controlled emissions based on 0.04 lb/MMBtu.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Table D‐24
Big West Oil LLC
Ozone RACT Analysis
Ultra-Low NOx Burners (ULNB)
H-1102 SRU and Tail Gas Incinerator
Unit H-1102
Parameter Value Units Basis
Design Duty MMBtu/hr 3.0
2017 Natural Gas Throughput 0.1 MMscf 2017 AEI reporting data
2017 Fuel Gas Throughput 15.5 MMscf 2017 AEI reporting data
2017 Natural Gas HHV 1045.8 Btu/scf 2017 GHG reporting data
2017 Fuel Gas HHV 824.9 Btu/scf 2017 GHG reporting data
2017 Effective HHV 826.6 Btu/scf Calculated
2017 NOx Emissions 0.8 tons/year 2017 AEI reporting data
2017 NOx Emission Rate 0.121 lb NOx/MMBtu Calculated
ULNB NOx Emission Rate 0.04 lb NOx/MMBtu Conservative emission rate estimate; actual emission rate would require analysis and guarantee by equipment vendor
Design Control Efficiency 67% Calculated
Control Equipment Costs
Category Value
Total Capital Investment $2,251,952
Direct Operating Costs
Maintenance and Operation $0
Indirect Operating Costs
Overhead (60% of Maintenance and Operation) $0
Administration (2% total capital costs) $45,039
Property tax (1% total capital costs) $22,520
Insurance (1% total capital costs) $22,520
Capital Recovery Factor (8.5%, 20 year life) 0.11
Capital Recovery (8.5%, 20 year life) $237,966
Total Indirect Operating Costs $328,044
Total Annual Cost $328,044
Emission Control Cost Calculation
Emissions
Control
Efficiency
Controlled
Emissions
Emission
Reduction
Control
Costs
Pollutant (tpy) (%) (tpy) (tpy) ($/ton)
Nitrous Oxides (NOx) 0.78 66.9% 0.26 0.52 $627,497
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Calculated based on correlation formula from Fig. B-7 of SCAQMD report on NOx emissions from petroleum refineries (Oct. 2021)
Assumed negligible change from current burners.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.7
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.6.5.8
Controlled emissions based on 0.04 lb/MMBtu.
EPA Air Pollution Control Cost Manual, Chapter 2, Sec 2.5.4.2
Basis
Table E
Big West Oil LLC U
North Salt Lake Refinery
Ozone RACT: Cost Evaluation for Engines
iption
Control
Alternative
Reported
Reduction
(%)
Annual NOx
Emissions
(tpy)
NOx
Removed
(tpy)
Total Annualized
Cost
($)
Total Cost
Effectiveness
($/ton NOx)
Incremental Cost
Effectiveness
($/ton)
Adverse
Environmental
Impact
Health and
Safety Impact
Energy
Impacts
Admin
Generator
Selective
Catalytic
Reduction
90%0.00 0.0006975 2,799,405$ 4,013,483,665$
P-8908
Firewater
Pump
Selective
Catalytic
Reduction
90%0.14 0.13016131 2,799,405$ 21,507,196$
P-8909
Firewater
Pump
Selective
Catalytic
Reduction
90%0.11 0.09523832 2,799,405$ 29,393,680$
P-8910
Firewater
Pump
Selective
Catalytic
Reduction
90%0.11 0.10279476 2,799,405$ 27,232,953$
P-8911
Firewater
Pump
Selective
Catalytic
Reduction
90%0.11 0.10279476 2,799,405$ 27,232,953$
FW
Generator
Selective
Catalytic
Reduction
90%0.04 0.03267648 2,799,405$ 85,670,331$
Table F-1
Big West Oil LLC
North Salt Lake Refinery
Ozone RACT: Cost Evaluation for WWTP
Control
Alternative
Reported
Reduction
(%)
Annual VOC
Emissions
(tpy)
VOC
Removed
(tpy)
Total Annualized
Cost
($)
Total Cost
Effectiveness
($/ton CO)
Adverse
Environmental
Impact
Health and
Safety
Impact
Energy
Impacts
API fixed cover baseline 15.56
Carbon canisters baseline 15.56
Thermal oxidizer 98%15.56 15.2 1,549,054$ 101,605$ Additional criteria
pollutants from
combustion
Additional
Natural Gas
usage
Table F-2
Big West Oil LLC 2017 to 2022 Inflation:1.222197
North Salt Lake Refinery
Ozone RACT: Cost Evaluation for WWTP
VOC Control Options Costs
Vapor Recovery
and Combustor2
Direct
Unit cost 1,918,849$
Foundations & support
Handling & erection
Electrical
Piping
Insulation
Gas supply
Painting
Total Direct Costs 1,918,849$
Indirect
Shipping
Engineering
Construction and field exp
Contractor fees
Startup
Performance testing
Contingencies 100%
Total Indirect Costs 15,350,789$
ANNUAL COSTS
Direct Annual Costs
Operating Labor 24,089$
Supervisor 5,175$
Operating Materials
Maintenance Labor 2,464$
Material
Utilities
Electricity1
Natural Gas
Total Operating and Maintenanc 31,728$
Indirect Annual Costs
Overhead 19,037$
Property Tax 76,754$
Insurance 1,074,555$
Capital Recovery 1,896,034$
Total Annualized Cost 3,098,108$
Inflation costs were determined using the Bureau of Labor Statistics website - http://www.bls.gov/data/inflation_calculator.htm
1BWO Electric cost: $0.032/kW-hr
2Unit cost based on John Zink estimates from the 2013 U.S. Oil & Refining Co. Tacoma Refnery Vapor Control System Project BACT
Table G-1
Big West Oil, LLC - NSL Refinery
Ozone SIP Support - RACT Evaluation for NOx and VOC
Ozone RACT: Cost Evaluation for Storage Tanks
Installation of Secondary Seals on IFRs
Tank Type Diameter (ft)
Reported
RY2017 Actual
Emissions
(tpy)
RSR Upgrades Completed
by RY2017?
Adjusted
RY2017
Actual
Emissions
(tpy)
Secondary
Seal
Installed?
Installation Cost
($)
Cleaning and
Degassing ($)
Additional
Retrofit Costs
(See Notes)
Property Taxes,
Insurance, and
Administrative
Charges
Total Capital
Investment ($)
Rubber
Replacement Costs
($/yr)Annualized Cost
Emissions
Reduction from
Secondary Seal (tpy
VOC)
Cost Effectiveness
($/ton)
TK-04 IFRT 78.0 3.12 Yes 3.12 No 53,910$ 90,000$ 26,955$ 6,835$ 177,699$ 1,569$ 20,346$ 1.54 13,240$
TK-06 IFRT 120.0 0.12 Yes 0.12 No 82,938$ 475,363$ 41,469$ 23,991$ 623,761$ 2,413$ 68,327$ 0.06 1,197,532$
TK-09 IFRT 55.0 1.64 N/A-Kb 1.64 No 38,013$ 90,000$ 19,007$ 5,881$ 152,901$ 1,106$ 17,263$ 0.80 21,461$
TK-29 IFRT 80.0 4.76 N/A-Kb 4.76 No 55,292$ 90,000$ 27,646$ 6,918$ 179,856$ 1,609$ 20,614$ 2.34 8,810$
TK-35 IFRT 48.0 2.26 No - Upgrades Req'd 2.00 No 33,175$ 90,000$ 16,588$ 5,591$ 145,353$ 965$ 16,325$ 0.98 16,626$
TK-42 IFRT 78.0 3.10 No - Upgrades Req'd 2.74 No 53,910$ 90,000$ 26,955$ 6,835$ 177,699$ 1,569$ 20,346$ 1.35 15,076$
TK-44 IFRT 120.0 1.69 No - Upgrades Req'd 1.50 No 82,938$ 475,363$ 41,469$ 23,991$ 623,761$ 2,413$ 68,327$ 0.74 92,675$
TK-45 IFRT 85.0 5.27 N/A-Kb 5.27 No 58,748$ 90,000$ 29,374$ 7,125$ 185,247$ 1,709$ 21,285$ 2.59 8,212$
TK-50 IFRT 73.0 0.28 Yes 0.28 No 50,454$ 90,000$ 25,227$ 6,627$ 172,308$ 1,468$ 19,676$ 0.14 144,815$
TK-56 IFRT 36.0 1.42 N/A-Kb 1.42 No 24,881$ 90,000$ 12,441$ 5,093$ 132,415$ 724$ 14,716$ 0.70 21,087$
TK-65 IFRT 48.0 2.28 No - Upgrades Req'd 2.02 No 33,175$ 90,000$ 16,588$ 5,591$ 145,353$ 965$ 16,325$ 0.99 16,438$
TK-75 IFRT 48.0 4.13 No - Upgrades Req'd 3.65 No 33,175$ 90,000$ 16,588$ 5,591$ 145,353$ 965$ 16,325$ 1.80 9,084$
TK-87 IFRT 21.0 0.17 N/A-Kb 0.17 No 14,514$ 90,000$ 7,257$ 4,471$ 116,242$ 422$ 12,706$ 0.08 152,197$
TK-90 IFRT 55.0 2.83 N/A-Kb 2.83 No 38,013$ 90,000$ 19,007$ 5,881$ 152,901$ 1,106$ 17,263$ 1.39 12,403$
TK-95 IFRT 73.0 1.43 N/A-Kb 1.43 No 50,454$ 90,000$ 25,227$ 6,627$ 172,308$ 1,468$ 19,676$ 0.70 28,024$
All N/A 34.48 N/A 32.93 N/A 703,591$ 2,120,727$ 351,796$ 127,045$ 3,303,158$ 20,472$ 369,520$ 16.20
Parameters:Basis
Capital Recovery Factor (CRF) = 0.1057
where: n = Equipment Life and i= Interest Rate
Current Prime Bank Rate 8.50
Expected Equipment Life 20 SCAQMD Proposed Rule 1178
Retrofit cost:$220 per linear foot SCAQMD Proposed Rule 1178
Rubber replacement:$42 per linear foot SCAQMD Proposed Rule 1178
Equipment life:10 years SCAQMD Proposed Rule 1178
CRF:0.1524
Cleaning and degassing costs $90,000
y = $190,963 * exp(0.0076 * diameter in ft)Crude tanks: SCAQMD Proposed Rule 1178
RSR Control Efficiency 12%
Sec. Seal Control Efficiency (on RSR compliant tank)49%
Notes:
Property taxes, insurance, and administrative charges assumes 4% of the total capital investment per EPA Control Cost Manual cost procedures.
New storage tank TK-20 will be installed with secondary seals and is not evaluated further.
Annualized costs are shown above ($/lf * lf * CRF)
Non-crude tanks: Engineering estimate from site-specific degassing proposal for degassing, plus safety factor to account for tank cleaning costs.
Assumed 50% of direct capital cost as additional retrofit costs for activities such as fitting/accessibility modifications, contractor coordination, contract inspection, confined space emergency response, blinding, stripping, touch-up painting, tank dike re-grading, project overhead, and fuel. Elevated cost
due to reduced capital cost compared to larger capital-intensive tanks projects.
Based upon multiple scenarios of Tank 62 retrofit analysis as IFRT, assumed as representative of all IFRTs.
Based upon multiple scenarios of Tank 62 retrofit analysis as IFRT, assumed as representative of all IFRTs.
Table G‐2
Big West Oil, LLC ‐ NSL Refinery
Ozone SIP Support ‐ RACT Evaluation for NOx and VOC
Ozone RACT: Cost Evaluation for Storage Tanks
Conversion of FR to IFR
Tank Type
Baseline 
Actual 
Emissions
(tpy)
Diameter 
(ft)
IFR Direct 
Installation 
Cost ($)
Hydrotest, 
Clean/Degas, 
Additional 
Retrofit Costs 
(See Notes)
Property Taxes, 
Insurance, and 
Administrative 
Charges
Annualized 
Cost
Emissions 
Reduction (tpy 
VOC)
IFR Cost 
Effectiveness
($/ton)
TK‐01A VFRT 0.70            19                170,422$        144,084$              12,580$               34,564$           0.69                   50,185$           
TK‐13 VFRT 0.00            60                508,124$        211,625$              28,790$               79,099$           0.00                   20,681,213$   
TK‐14 VFRT 0.00            60                508,124$        211,625$              28,790$               79,099$           0.00                   20,738,383$   
TK‐16 VFRT 0.03            73                615,200$        233,040$              33,930$               93,220$           0.03                   2,750,672$     
TK‐17 VFRT 0.02            120              1,002,321$     310,464$              52,511$               144,272$         0.02                   6,115,458$     
TK‐18 VFRT 0.68            78                656,383$        241,277$              35,906$               98,651$           0.67                   146,488$         
TK‐19 VFRT 0.01            60                508,124$        211,625$              28,790$               79,099$           0.01                   5,571,669$     
TK‐21 VFRT 0.82            95                796,405$        269,281$              42,627$               117,117$         0.82                   143,565$         
TK‐22 VFRT 0.93            95                796,405$        269,281$              42,627$               117,117$         0.92                   127,037$         
TK‐23 VFRT 0.45            55                466,940$        203,388$              26,813$               73,668$           0.44                   166,723$         
TK‐24 VFRT 0.12            55                466,940$        203,388$              26,813$               73,668$           0.12                   630,881$         
TK‐25 VFRT 0.29            88                738,749$        257,750$              39,860$               109,513$         0.28                   386,728$         
TK‐30 VFRT 0.21            45                384,574$        186,915$              22,860$               62,805$           0.21                   305,306$         
TK‐31 VFRT 0.27            50                425,757$        195,151$              24,836$               68,237$           0.27                   257,331$         
TK‐33 VFRT 0.06            36                310,445$        172,089$              19,301$               53,029$           0.06                   963,313$         
TK‐34 VFRT 0.11            50                425,757$        195,151$              24,836$               68,237$           0.11                   644,488$         
TK‐40 VFRT 0.20            60                508,124$        211,625$              28,790$               79,099$           0.20                   404,805$         
TK‐85 VFRT 0.00            21                186,895$        147,379$              13,371$               36,736$           0.00                   25,637,937$   
TK‐86 VFRT 0.00            21                186,895$        147,379$              13,371$               36,736$           0.00                   25,350,687$   
Total VFRT 4.90            N/A 9,662,583$     4,022,517$           547,404$             1,503,963$      4.85                   310,028$         
Table G‐2
Big West Oil, LLC ‐ NSL Refinery
Ozone SIP Support ‐ RACT Evaluation for NOx and VOC
Ozone RACT: Cost Evaluation for Storage Tanks
Conversion of FR to IFR
Parameters:Value:Notes:
Capital Recovery Factor (CRF) = 0.1057
where:  n = Equipment Life and i= Interest Rate
Current Prime Bank Rate 8.50
Expected Equipment Life 20
Control Efficiency 99% AP‐42 Chapter 7.1 (range given as 50‐99%)
Linear Regression for Estimated Roof Cost: Based on two cost quotes.  Includes capital cost only.
Y = mx+b, where:
Y = Capital Cost (S) Calculated
m = Slope ($/ft) 8,237               
x = Tank Diameter (ft) Variable
b = Intercept ($) 13,926            
Additional Costs not captured in regression above:
Hydrotesting $20,000
Cleaning and degassing costs $90,000
Notes:
IFR direct installation cost does not include additional costs associated with installation or operation (e.g., inspections and maintenance).
Tanks Tk‐D2 and Tk‐UL have diameters less than 16 feet and are omitted from this evaluation due to technical infeasibility.
Property taxes, insurance, and administrative charges assumes 4% of the total capital investment per EPA Control Cost Manual cost procedures.
Assumed 20% of direct capital cost additional retrofit costs for activities such as fitting/accessibility modifications, contractor coordination, contract 
inspection, confined space emergency response, blinding, stripping, touch‐up painting, tank dike re‐grading, project overhead, and fuel.
Minimum diameter for IFRT is ~16 feet due to buoyancy requirements.  Do not use 
correlation below this diameter.
Engineering estimate from site‐specific degassing proposal for degassing, plus safety 
factor to account for tank cleaning costs.
Table G‐3
Big West Oil LLC
North Salt Lake Refinery
Ozone RACT: Cost Evaluation for Storage Tanks
Installation of Domes on EFRs
Tank Type Diameter (ft)
Baseline 
Actual 
Emissions
(tpy)
Baseline 
Standing 
Losses (tpy)
Baseline 
Working 
Losses (tpy)
Uncontrolled 
Guidepole 
Controls in 
RY2017?
Adjusted RY2017 
Actual Emissions 
with RSR Controls 
(tpy)
Installation 
Cost ($)
Cleaning and 
Degassing Costs 
($)
Fire 
Suppression 
($)
Additional 
Retrofit Costs 
(See Notes)
Property Taxes, 
Insurance, and 
Administrative 
Charges
Total Capital 
Investment ($)
O&M Costs 
($/yr)
Annualized 
Cost ($/yr)
Emissions 
Reduction 
(tpy VOC)
Cost 
Effectiveness
($/ton)
TK‐03 EFRT 120.0             0.72            0.04            0.68            N 0.72 821,124$         475,363$            105,000$         164,225$            62,629$             1,628,341$       14,324$             173,432$        0.59                292,630$         
TK‐05 EFRT 100.0             0.37            0.02            0.34            Y 0.35 723,072$         408,332$            105,000$         144,614$            55,241$             1,436,258$       12,591$             152,930$        0.29                533,410$         
TK‐28 EFRT 110.0             0.01            0.01            0.01            N 0.01 770,334$         440,575$            105,000$         154,067$            58,799$             1,528,774$       13,458$             162,837$        0.01                13,970,387$    
TK‐43 EFRT 120.0             5.97            5.51            0.46            Y 1.05 821,124$         475,363$            105,000$         164,225$            62,629$             1,628,341$       14,324$             173,432$        0.87                199,147$         
TK‐51 EFRT 42.0                12.22          12.20          0.01            Y 1.32 506,957$         90,000$              105,000$         101,391$            32,134$             835,483$          7,563$               89,200$           1.09                81,944$            
TK‐52 EFRT 42.0                2.63            2.61            0.02            Y 0.29 506,957$         90,000$              105,000$         101,391$            32,134$             835,483$          7,563$               89,200$           0.24                366,464$         
TK‐53 EFRT 43.0                4.42            4.31            0.10            Y 0.56 509,970$         90,000$              105,000$         101,994$            32,279$             839,243$          7,650$               89,654$           0.47                192,569$         
TK‐54 EFRT 120.0             15.09          14.94          0.15            Y 1.74 821,124$         90,000$              105,000$         164,225$            47,214$             1,227,563$       14,324$             134,272$        1.44                93,268$            
TK‐62 EFRT 60.0                16.96          16.76          0.20            Y 1.99 564,653$         90,000$              105,000$         112,931$            34,903$             907,487$          9,124$               97,796$           1.65                59,410$            
TK‐72 EFRT 42.0                17.18          17.16          0.02            Y 1.85 506,957$         90,000$              105,000$         101,391$            32,134$             835,483$          7,563$               89,200$           1.53                58,314$            
Total EFRT N/A 75.56          73.57          1.99            N/A 9.88                            6,552,272$      2,339,633$         1,050,000$      1,310,454$        450,094$          11,702,454$     108,485$          1,251,952$     8.17                153,148$         
Parameters:Basis
Capital Recovery Factor (CRF) = 0.0977
where:  n = Equipment Life and i= Interest Rate
Current Prime Bank Rate 8.50 https://www.federalreserve.gov/releases/h15/Accessed on 12/13/2023
Expected Equipment Life 25 Engineering estimate
Installation cost: y = $308,149* exp(0.0072 * diameter in ft)SCAQMD Proposed Rule 1178
Cleaning and degassing costs $90,000
y = $190,963 * exp(0.0076 * diameter in ft)Crude tanks: SCAQMD Proposed Rule 1178
Fire Suppression $105,000 SCAQMD Proposed Rule 1178
O&M Costs (every 20 years) y = $820.28 * (diameter in ft) + $37,123 SCAQMD Proposed Rule 1178
CRF for 20 year maintenance frequency 0.1057
RSR Upgrade Control Efficiency 89% Based upon Tank T59 and T62 as representative of all EFRTs
Dome Control Efficiency 83% Based upon Tank T59 and T62 as representative of all EFRTs
Notes:
Adjusted RY2017 actual emissions incorporate controls required by January 2026 under 40 CFR 63 Subpart CC (referred to as RSR). 
Control effectiveness was modeled using Tank T62 as representative following AP‐42 methodology. Guidepole controls under RSR and doming affects only standing losses, not working losses.
Assumed 20% of direct capital cost additional retrofit costs for activities such as fitting/accessibility modifications, contractor coordination, contract inspection, confined space emergency response, blinding, stripping, touch‐up painting, tank dike re‐grading, project overhead, and fuel.
Property taxes, insurance, and administrative charges assumes 4% of the total capital investment per EPA Control Cost Manual cost procedures.
Does not account for loss of capacity or production. BWO reserves the right to incorporate additional costs on a case‐by‐case basis if controls were required outside of the planned shutdown schedule.
Non‐crude tanks:  Engineering estimate from site‐specific degassing proposal for degassing, plus safety 
factor to account for tank cleaning costs.
Table G‐4
Big West Oil LLC Flag if under:
North Salt Lake Refinery
Ozone RACT: Cost Evaluation for Storage Tanks
Installation of Vapor Recovery Unit
Case One: Independent Control Device for Each Tank Cap Cap Cap Cap Operating Operating Cap Operating Both Both
Cost Effectiveness Methodology:A B C D E F G H I J K L TOER CER
=(A+B+C+G+H+I+K)/
TOER
=(A+B+C+D+E+F+J+L)/
CER
Tank Type
Tank 
Diameter
RY2017 
Actual 
Emissions
(tpy)
Uncontrolled 
Guidepole in 
RY2017?
Adjusted 
RY2017 Actual 
Emissions with 
RSR Controls 
(tpy)
Vapor Space 
Displacement 
(ACFM)
Tank Vapor 
Pipe 
Distance (ft)
Count of 
Elbows:
Tank Vapors 
Pipe Cost Ann. Pipe Cost
Common Inf. 
Costs (excl. 
Vapor Piping)
Ann. Common 
Inf./Piping 
Costs
EFRT Roof 
Retrofit to 
Steel Fixed 
Roof Cost
Ann. EFR 
Roof Retrofit 
Cost
Carbon Utility 
Inst. and Site 
Prep Costs
Ann. Carbon 
Utility Inst. and 
Site Prep Costs
Ann. Carbon 
Utility 
Usage
Ann. CCM 
Carbon 
Usage (lb/yr)
Ann. Spent 
Carbon 
Waste Mgmt. 
Cost
TO Utility 
Piping, 
Service, and 
Site Prep 
Costs (excl 
cap. TO costs)
Ann. TO Piping, 
Service, and 
Site Prep Costs 
(excl cap. TO 
costs)
Ann. TO Utility 
Usage
For TO: Property 
Taxes, Insurance, and 
Administrative 
Charges
For Carbon: Property 
Taxes, Insurance, and 
Administrative 
Charges
Ann. TO Cost (via 
EPA CCM)
Ann. Carbon Canister 
Cost (via EPA CCM)
TO 
Emissions 
Reduction 
(tpy VOC)
Carbon 
Emissions 
Reduction 
(tpy VOC)
TO Cost Effectiveness
($/ton)
Carbon Canister Cost 
Effectiveness
($/ton)
TK‐01A VFRT 19 0.70              N 0.70                  0.05                  484               5              163,631$       17,291$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 1,070            3,206$           30,000$          3,170$              Within ''K'' 818                               692                               113,283$                    69,744$                      0.69             0.68             195,379$                        133,377$                              
TK‐03 EFRT 120 0.72              N 0.72                  78.47                1,705           6              557,900$       58,954$           121,000$          1,628,341$       173,432$        ‐‐‐ ‐‐‐Within ''L'' 1,098            3,218$           30,000$          3,170$              Within ''K'' 9,422                           9,295                           113,283$                    70,678$                      0.71             0.70             505,246$                        449,591$                              
TK‐04 IFRT 78 3.12              N 3.12                  61.00                520               5              175,209$       18,514$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 4,392            4,535$           30,000$          3,170$              Within ''K'' 867                               741                               113,283$                    180,090$                    3.09             3.06             43,926$                          66,604$                                
TK‐05 EFRT 100 0.37              Y 0.04                  61.17                900               5              297,417$       31,428$           121,000$          1,436,258$       152,930$        ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 7,501                           7,374                           113,283$                    39,968$                      0.04             0.04             7,679,885$                     5,903,966$                          
TK‐05RSR EFRT
TK‐06 IFRT 120 0.12              N 0.12                  53.84                1,755           6              573,980$       60,653$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 2,553                           2,426                           107,352$                    43,396$                      0.11             0.11             1,513,113$                     962,538$                              
TK‐09 IFRT 55 1.64              N 1.64                  30.82                850               5              281,337$       29,729$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 2,355            3,720$           30,000$          3,170$              Within ''K'' 1,316                           1,189                           107,352$                    112,439$                    1.62             1.60             87,455$                          91,787$                                
TK‐13 VFRT 60 0.00              N 0.00                  30.73                521               5              175,530$       18,548$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 869                               742                               107,352$                    38,301$                      0.00             0.00             33,974,103$                   15,983,354$                        
TK‐14 VFRT 60 0.00              N 0.00                  30.73                571               5              191,610$       20,248$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 937                               810                               107,352$                    38,300$                      0.00             0.00             34,531,338$                   16,495,456$                        
TK‐16 VFRT 73 0.03              N 0.03                  68.45                598               5              200,294$       21,165$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 973                               847                               107,352$                    39,681$                      0.03             0.03             3,914,486$                     1,926,083$                          
TK‐17 VFRT 120 0.02              N 0.02                  81.57                1,187           6              391,311$       41,350$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 1,781                           1,654                           107,352$                    39,208$                      0.02             0.02             6,513,114$                     3,645,547$                          
TK‐18 VFRT 78 0.68              N 0.68                  17.81                448               5              152,054$       16,068$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 1,049            3,198$           30,000$          3,170$              Within ''K'' 770                               643                               107,352$                    69,042$                      0.67             0.67             189,118$                        133,431$                              
TK‐19 VFRT
TK‐21 VFRT 95 0.82              N 0.82                  24.24                1,408           11            470,362$       49,704$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 1,245            3,277$           30,000$          3,170$              Within ''K'' 2,115                           1,988                           107,352$                    75,576$                      0.82             0.81             199,003$                        161,658$                              
TK‐22 VFRT 95 0.93              N 0.93                  26.48                1,408           11            470,362$       49,704$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 1,392            3,335$           30,000$          3,170$              Within ''K'' 2,115                           1,988                           107,352$                    80,449$                      0.92             0.91             176,091$                        148,450$                              
TK‐23 VFRT 55 0.45              N 0.45                  32.15                548               5              184,214$       19,466$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 728                3,070$           30,000$          3,170$              Within ''K'' 905                               779                               107,352$                    58,410$                      0.44             0.44             296,236$                        186,845$                              
TK‐24 VFRT 55 0.12              N 0.12                  30.44                421               5              143,370$       15,150$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 733                               606                               107,352$                    43,486$                      0.12             0.12             1,082,520$                     537,800$                              
TK‐25 VFRT 88 0.29              N 0.29                  58.49                548               5              184,214$       19,466$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 509                2,982$           30,000$          3,170$              Within ''K'' 905                               779                               107,352$                    51,125$                      0.28             0.28             462,231$                        265,242$                              
TK‐28 EFRT 110 0.01              N 0.01                  9.17                  1,351           8              447,245$       47,261$           121,000$          1,528,774$       162,837$        ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 8,531                           8,404                           107,352$                    38,765$                      0.01             0.01             23,602,880$                   18,848,144$                        
TK‐29 IFRT 80 4.76              N 4.76                  26.86                1,351           8              447,245$       47,261$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 6,625            5,429$           30,000$          3,170$              Within ''K'' 2,017                           1,890                           107,352$                    254,297$                    4.71             4.66             33,937$                          66,266$                                
TK‐30 VFRT 45 0.21              N 0.21                  19.19                648               5              216,374$       22,864$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 402                2,939$           30,000$          3,170$              Within ''K'' 1,041                           915                               107,352$                    47,569$                      0.21             0.20             653,475$                        364,806$                              
TK‐31 VFRT 50 0.27              N 0.27                  16.80                498               5              168,134$       17,767$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 484                2,972$           30,000$          3,170$              Within ''K'' 837                               711                               107,352$                    50,299$                      0.27             0.26             486,958$                        273,336$                              
TK‐33 VFRT 36 0.06              N 0.06                  5.08                  571               5              191,610$       20,248$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 937                               810                               107,352$                    40,652$                      0.06             0.05             2,392,540$                     1,186,069$                          
TK‐34 VFRT 50 0.11              N 0.11                  5.08                  571               5              191,610$       20,248$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 937                               810                               107,352$                    42,986$                      0.11             0.10             1,243,960$                     638,940$                              
TK‐35 IFRT 48 2.26              Y 2.03                  4.75                  957               8              320,534$       33,871$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 2,896            3,937$           30,000$          3,170$              Within ''K'' 1,482                           1,355                           107,352$                    130,406$                    2.01             1.99             72,571$                          85,219$                                
TK‐40 VFRT 60 0.20              N 0.20                  17.34                448               5              152,054$       16,068$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 388                2,934$           30,000$          3,170$              Within ''K'' 770                               643                               107,352$                    47,096$                      0.20             0.19             651,790$                        345,039$                              
TK‐42 IFRT 78 3.10              Y 2.79                  26.71                1,007           8              336,614$       35,570$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 3,936            4,353$           30,000$          3,170$              Within ''K'' 1,550                           1,423                           107,352$                    164,964$                    2.76             2.73             53,438$                          75,435$                                
TK‐43 EFRT 120 5.97              Y 0.66                  30.35                1,237           6              407,391$       43,049$           121,000$          1,628,341$       173,432$        ‐‐‐ ‐‐‐Within ''L'' 1,017            3,185$           30,000$          3,170$              Within ''K'' 8,786                           8,659                           107,352$                    67,992$                      0.65             0.64             516,145$                        460,120$                              
TK‐44 IFRT 120 1.69              N 1.69                  43.59                1,755           6              573,980$       60,653$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 2,436            3,753$           30,000$          3,170$              Within ''K'' 2,553                           2,426                           107,352$                    115,117$                    1.68             1.66             103,591$                        109,600$                              
TK‐45 IFRT 85 5.27              N 5.27                  22.12                1,007           8              336,614$       35,570$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 7,326            5,709$           30,000$          3,170$              Within ''K'' 1,550                           1,423                           99,780$                      277,557$                    5.22             5.16             26,857$                          62,033$                                
TK‐50 IFRT 73 0.28              N 0.28                  4.68                  1,197           9              399,314$       42,196$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 496                2,977$           30,000$          3,170$              Within ''K'' 1,815                           1,688                           107,352$                    50,677$                      0.27             0.27             565,197$                        360,379$                              
TK‐51 EFRT 42 12.22            Y 1.34                  3.28                  848               8              285,480$       30,167$           121,000$          835,483$          89,200$          ‐‐‐ ‐‐‐Within ''L'' 1,956            3,561$           30,000$          3,170$              Within ''K'' 4,901                           4,775                           107,352$                    99,199$                      1.33             1.32             176,489$                        172,300$                              
TK‐51RSR EFRT
TK‐52 EFRT 42 2.63              Y 0.29                  9.19                  898               8              301,560$       31,866$           121,000$          835,483$          89,200$          ‐‐‐ ‐‐‐Within ''L'' 513                2,984$           30,000$          3,170$              Within ''K'' 4,969                           4,843                           107,352$                    51,269$                      0.29             0.28             826,219$                        635,667$                              
TK‐53 EFRT 43 4.42              N 4.42                  7.80                  598               5              200,294$       21,165$           121,000$          839,243$          89,654$          ‐‐‐ ‐‐‐Within ''L'' 6,160            5,242$           30,000$          3,170$              Within ''K'' 4,560                           4,433                           107,352$                    238,832$                    4.37             4.33             51,671$                          83,029$                                
TK‐54 EFRT 120 15.09            Y 1.66                  56.92                1,197           9              399,314$       42,196$           121,000$          1,227,563$       134,272$        ‐‐‐ ‐‐‐Within ''L'' 2,388            3,734$           30,000$          3,170$              Within ''K'' 7,186                           7,059                           107,352$                    113,543$                    1.64             1.63             179,072$                        184,974$                              
TK‐56 IFRT 36 1.42              N 1.42                  0.20                  1,198           7              396,444$       41,893$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 2,059            3,602$           30,000$          3,170$              Within ''K'' 1,803                           1,676                           107,352$                    102,598$                    1.40             1.39             109,813$                        107,732$                              
TK‐59 IFRT 75 1.56              N 1.56                  2.59                  861               7              288,065$       30,440$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 2,253            3,679$           30,000$          3,170$              Within ''K'' 1,344                           1,218                           107,352$                    109,038$                    1.54             1.53             92,129$                          94,421$                                
TK‐62 EFRT 60 16.96            Y 1.87                  5.24                  733               5              243,710$       25,753$           121,000$          907,487$          97,796$          ‐‐‐ ‐‐‐Within ''L'' 2,671            3,847$           30,000$          3,170$              Within ''K'' 5,069                           4,942                           107,352$                    122,922$                    1.85             1.83             129,469$                        139,606$                              
TK‐65 IFRT 48 2.28              Y 2.05                  9.77                  907               8              304,454$       32,172$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 2,928            3,950$           30,000$          3,170$              Within ''K'' 1,414                           1,287                           107,352$                    131,465$                    2.03             2.01             70,878$                          83,907$                                
TK‐72 EFRT 42 17.18            Y 1.89                  7.28                  942               5              310,924$       32,856$           121,000$          835,483$          89,200$          ‐‐‐ ‐‐‐Within ''L'' 2,703            3,860$           30,000$          3,170$              Within ''K'' 5,009                           4,882                           107,352$                    124,015$                    1.87             1.85             126,992$                        137,589$                              
TK‐72RSR EFRT
TK‐75 IFRT 48 4.13              Y 3.72                  24.69                957               8              320,534$       33,871$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 5,202            4,859$           30,000$          3,170$              Within ''K'' 1,482                           1,355                           107,352$                    207,017$                    3.68             3.64             39,652$                          67,853$                                
TK‐85 VFRT 21 0.00              N 0.00                  3.42                  160               3              56,242$          5,943$             121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 365                               238                               107,352$                    38,191$                      0.00             0.00             81,535,361$                   33,343,265$                        
TK‐86 VFRT 21 0.00              N 0.00                  3.37                  185               3              64,282$          6,793$             121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 399                               272                               107,352$                    38,192$                      0.00             0.00             81,231,569$                   33,586,163$                        
TK‐87 IFRT 21 0.17              N 0.17                  7.89                  210               5              75,513$          7,980$             121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 446                               319                               107,352$                    45,837$                      0.17             0.17             708,055$                        343,115$                              
TK‐90 IFRT 55 2.83              N 2.83                  307.79              900               5              297,417$       31,428$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 3,989            4,374$           30,000$          3,170$              Within ''K'' 1,384                           1,257                           107,352$                    166,710$                    2.80             2.77             51,175$                          73,494$                                
TK‐95 IFRT 73 1.43              N 1.43                  15.87                1,197           9              399,314$       42,196$           121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 2,070            3,607$           30,000$          3,170$              Within ''K'' 1,815                           1,688                           107,352$                    102,988$                    1.41             1.40             109,376$                        107,592$                              
TK‐D2 VFRT 10 0.01              N 0.01                  0.04                  150               5              56,217$          5,940$             121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 360                2,922$           30,000$          3,170$              Within ''K'' 364                               238                               107,352$                    38,397$                      0.01             0.01             19,711,430$                   8,095,723$                          
TK‐UL VFRT 8 0.44              N 0.44                  0.02                  150               5              56,217$          5,940$             121,000$           ‐‐‐ ‐‐‐ ‐‐‐ ‐‐‐Within ''L'' 718                3,066$           30,000$          3,170$              Within ''K'' 364                               238                               107,352$                    58,072$                      0.43             0.43             268,877$                        156,509$                              
Case Two: All Tanks to Common Control Device
Cost Effectiveness Methodology:A B C D E F G H I J TOER CER
=(A+B+C+G+H+I)/
TOER
=(A+B+C+D+E+F+J)/
CER
Tank
Count of 
Tanks
RY2017 
Actual 
Emissions
(tpy)
Adjusted 
RY2017 Actual 
Emissions with 
RSR Controls 
(tpy)
Vapor Space 
Displacement 
(ACFM)
Tank Vapor 
Pipe 
Distance (ft)
Count of 
Elbows:
Tank Vapors 
Pipe Cost Ann. Pipe Cost
Common Inf. 
Costs (excl. 
Vapor Piping)
Ann. Common 
Inf. Costs (excl. 
Vapor Piping)
EFRT Roof 
Retrofit to 
Steel Fixed 
Roof Cost
Ann. EFR 
Roof Retrofit 
Cost
VRU, Utility 
Inst., and Site 
Prep Costs
Ann. VRU, 
Utility Inst., 
and Site Prep 
Costs
Ann. VRU 
Utility 
Usage
Ann. Carbon 
Usage (lb/yr)
Ann. Spent 
Carbon 
Waste Mgmt. 
Cost
Common TO, 
Utility Piping, 
Service, and 
Site Prep 
Costs
Ann. Common 
TO, Piping, 
Service, and 
Site Prep Costs
Ann. TO Utility 
Usage Ann. TO Cost Ann. VRU Cost
TO 
Emissions 
Reduction 
(tpy VOC)
VRU 
Emissions 
Reduction 
(tpy VOC)
TO Cost Effectiveness
($/ton)
VRU Cost Effectiveness
($/ton)
All 50                 116.93          53.09               1,384                19,281         143          6,428,748$    679,332$        4,807,692$       508,034$         11,702,454$    1,236,610$   26,923,077$     2,844,988$      769,231$    4,250,000     3,926,738$   4,423,077$    467,391$          1,923,077$       Within ''G'' and ''H'' Within ''D'' and ''E'' 52.56           52.03           91,605$                          191,538$                              
Table G‐4
Big West Oil LLC
North Salt Lake Refinery
Ozone RACT: Cost Evaluation for Storage Tanks
Supporting Notes ‐ Installation of Vapor Recovery Unit
Parameters:Value:Notes:
Capital Recovery Factor (CRF) = 0.1057
where:  n = Equipment Life and i= Interest Rate
Current Prime Bank Rate 8.50
Expected Equipment Life 20
Linear Piping Cost Factor $268 per foot, 10 inch diameter from RSMeans
Elbow Cost Factor $1,329
Aggregate Pipe/Fitting  Cost Safety Factor: 20%
TO Destruction Efficiency 99%
Carbon VOC capture efficiency 98%
IFRT RSR Upgrade Control Efficiency 10% Estimate based upon TankESP runs for representative tank
EFRT RSR Upgrade Control Efficiency 89% Estimate based upon TankESP runs for representative tank
Roof Retrofit Costs:
Retrofit cost: y = $308,149* exp(0.0072 * diameter in ft)
Steel roof/Geodome Cost Factor: 20%
Cleaning and degassing costs $90,000
Roof painting costs $20 /sq ft diameter of tank.
Geodesic Dome demolition cost $150,000 engineering estimate
Waste Management Costs per Tank for Carbon Canisters:
Annual Transportation Cost 1,528$                  Site‐specific records twice per year.
Annual Waste Container Cleanout 600$                     Engineering estimate, twice per year.
Annual Waste Classification 650$                     Engineering estimate, twice per year.
Annual Disposal Cost 0.40$                    /lb hazardous waste.
Waste Management Costs for Common VRU System:
Carbon required for system: 80,000                  lb carbon/ton VOC controlled.
EFRT 1,030,000            lb carbon/yr
IFRT 2,790,000            lb carbon/yr
VFRT 430,000               lb carbon/yr
All Tanks 4,250,000            lb carbon/yr
Carbon box capacity 12,500                  lb/box, site‐specific average estimate
Carbon Changeouts per year
EFRT 82                          boxes/yr
IFRT 223                       boxes/yr
VFRT 34                          boxes/yr
All Tanks 340                       boxes/yr
Costs per Carbon Box:
Rental 5,160$                  /box, 4‐month rental assumed
Transportation 764$                     /box, based on site‐specific records.
Container Cleanout 300$                     /box, based on engineering estimate
Waste Classification 325$                     /box, based on engineering estimate
Annual Hazardous Waste Disposal Costs:
Disposal Cost Rate: 0.40$                    /lb hazardous waste.
EFRT 412,000$             /yr
IFRT 1,116,000$          /yr
VFRT 172,000$             /yr
All Tanks 1,700,000$          /yr
Engineering estimate from site‐specific degassing proposal for degassing, plus safety 
factor to account for tank cleaning costs.
per elbow, 10 inch diameter.  Assumed cost of elbow represents cost of 30°/45°/60°/90° 
turns. From RSMeans
http://www.aqmd.gov/docs/default‐source/rule‐book/Proposed‐Rules/1178/par‐
1178_wgm‐6_v9.pdf?sfvrsn=14
Cost for geodesic dome installation.  Add factor of 20% for additional cost of steel fixed 
roof.
Table G‐4
Notes:
Storage tank 59 was rebuilt as an IFRT in 2023.  Potential emissions from this tank is assumed to be the same as submitted in the 7/13/2023 R307‐401‐12 submittal.
Storage tank 20 is planned to be installed in 2024 and is therefore not included in this analysis.
Carbon systems for individual tanks are based on carbon canisters, which are replaced in whole.  These are identified as "Case One" in this workbook.
Calculation for Pipe Cost includes +20% safety factor to account for changes in elevation, detailed fitting connections at tank and control device.  
Assumed combined case (Case Two) involves 50% of total pipe length required for sum of piping required for individual cases.
Tank
RY2017 Actual 
Emissions
(tpy)
Vapor Space 
Displacement 
(ACFM)
Annualized 
CCM TO Cost
Min. Annual 
Emissions for 
TO Cost 
Estimate (tpy 
VOC)
Max Annual 
Emissions for TO 
Cost Estimate 
(tpy VOC)
Annualized CCM 
Carbon Cost
Carbon 
Required (lb)
TK‐25 0.2860                          0.29                    113,283$           0.00 1.00 70,016$                     540                   
TK‐42 3.1009                          2.79                    107,352$           1.00 5.00 154,285$                   4,320               
TK‐54 12.14                             10.26                  99,780$             5.00 20.00 595,841$                   16,740             
Use Linear Regression to estimate annualized Carbon Canister cost as a function of annual VOC emissions to Carbon Can:
Y = mx+b
where:
Y= Annualized Carbon Canister Cost ($/yr) Calculated
m= Slope: 45,450           
x= Annual Emissions (tpy) Tank‐specifc
b= Intercept: 38,125.06     
Use Linear Regression to estimate annualized carbon usage as a function of annual VOC emissions to Carbon Can:
Y = mx+b
where:
Y= Annualized Carbon Cost ($/yr) Calculated
m= Slope: 1,368             
x= Annual Emissions (tpy) Tank‐specifc
b= Intercept: 117.78           
Storage tank T206 was removed from service in 2021 and replaced with a new T206 (submitted via R307‐401‐12 emissions reduction submittal).  Actual emissions have not been reported for the 
new tank. Marathon is conservatively using RY2017 emissions from the old tank, which are greater than expected for the new tank.
For tanks that meet the definition of Group 1 storage vessel in 40 CFR 63 Subpart CC (part of the Refinery Sector Rule, or RSR), the rule requires that all Group 1 storage vessels are configured 
with enhanced emissions controls the next time the vessel is completely emptied and degassed, or January 30, 2026, whichever occurs first.  All calculations for emissions reduction and cost 
effectiveness assume that emissions controls compliant with 40 CFR 63.660 are installed.  Actual emissions from RY2017 have been adjusted to show RSR‐compliant controls; the adjusted 
emissions are identified in the "Adjusted RY2017 Actual Emissions with RSR Controls (tpy)" column.
Storage tanks T244 and T245 were installed after 2017.  Tanks T244 and T245 each operated for one full year in RY2018 and RY2019, respectively, thus these years were selected for actual 
emissions from each tank.
Storage tanks T103, T241, and T248 were installed/replaced after 2017.  Actual emissions for these tanks were represented using potential emissions instead of actual emissions.
Cost Considerations for Combined Vapor Recovery Unit ‐ all costs to be prorated from 13 to number of tanks in applicable equipment as the costs estimates are from a similar facility with 13 
total tanks.
"Total" case involves evaluation of a fixed adsorber with replaceable carbon.  The carbon is replaced, while the fixed adsorber remains in place.  These are identified as "Case Two" in this 
workbook.
To evaluate annual cost of thermal oxidation, annual costs for three scenarios were evaluated.  The annual cost for a given tank is selected asssumed based on which of the three scenarios actual 
emissions most closely align with.  For carbon, the three scenarios were evaluated; annual costs are estimated from a linear regression of the three costs identified below (annual cost as a 
function of emissions rate).
Project Scope (Common for VRU or TO):
Installation of Vapor Control for control of tank head space vapors would require installation at a minimum of the following items regardless of the control technology selected:
1) Vapor piping from each tank to a main header that would direct vapors to a common point. A vapor blower to pull and direct vapors to the control devices.
2) Detonation Arrestors at specific designed locations to ensure any significant detonation event could not transverse back to a product tank.
3) Pressure sensing and control equipment at each tank to ensure pressure in the atmospheric tanks is maintained within design parameters.
4) Proper supports and foundations to hold the vapor piping, blower(s), and electrical conduit and equipment across the tank farm areas.
5) Electrical supply infrastructure including new utility feeds and distribution equipment.
6) A bladder tank to handle the surges of air flow and to condition that air flow into the Vapor Control device.
7) There is a significant potential for cost and project delays associated with the air and construction permits that will likely be required for this type of project. Permit issuance on average is 
approximately one year.
Cost considerations:
The following cost considerations are engineering estimates from similar Big West Oil projects. BWO refinery, remote tank farm, or truck loading rack sites would need an in‐depth 
engineering study to determine vapor piping sizing, number of pipe/conduit supports, survey of underground obstructions, soil surveys to determine footer designs, power utilization surveys 
to determine needed distribution up‐grades and utility impacts, tank movement schedules and fill/transfer rates to determine max vapor flows and concentrations, etc. It is estimated that 
the common infrastructure costs would likely be between $1.5 –2.5MM per site regardless of what technology is used to control the vapors.
Table G‐4
Additional Cost Considerations for Combined Vapor Recovery Unit ‐ all costs to be prorated from 13 to number of tanks in applicable equipment as the costs estimates are from a similar facility 
with 13 total tanks.
Additional Cost Considerations for Combined Thermal Oxidation System ‐ all costs to be prorated from 13 to number of tanks in applicable equipment as the costs estimates are from a similar 
facility with 13 total tanks.
In addition to the common project scope, a VRU would require the following items to be procured and installed:
1) Gasoline supply and return piping to an existing tank and a back‐up tank so that it could be operated when the primary tank is out for inspection or repair.
2) The piping may require the tanks to have hot taps performed or the tank to be taken out of service to connect the piping. This is not recommended for any gasoline tank.
3) Centrifugal pumps and motors to deliver gasoline to the VRU.
4) A large (400 Amp or larger) electrical service will need to be supplied to the location of the VRU. Electrical infrastructure in the tank farm is at capacity and service from a new substation 
would be required.
5) Significant runs of conduit and wire will be required to get the necessary power from the distribution point to the VRU skid.
6) A large concrete footer and pad will need to be created to place the VRU skid and carbon vessels on.
7) The VRU itself will need to be purchased from a 3rd party vendor.
8) Supply chain issues associated with procuring all equipment will need to be incorporated into schedule.
Cost considerations:
The following cost considerations are engineering estimates from similar Big West Oil projects. BWO refinery, remote tank farm, or truck loading rack sites would need an in‐depth study to 
determine vapor piping sizing, number of pipe/conduit supports, survey of underground obstructions, soil surveys to determine footer designs, power utilization surveys to determine 
needed distribution up‐grades and utility impacts, tank movement schedules and fill/transfer rates to determine max vapor flows and concentrations, etc.
A VRU would likely cost approximately $1.5 MM. There will be roughly $500M of costs in gasoline piping and site prep work per site. The electrical infrastructure and utility feeds could cost 
$5MM cost per site to upgrade due to limitations on the current system. The estimated increase in electrical usage per site with the VRU is expected to be on the order of $175 ‐$200M per 
year in ongoing costs.
Total Estimated costs for VRU System = $4.5MM ‐$5.5MM plus $175M‐$200M in utility cost per site
The estimates for product recovery with a VRU are very minimal. BWO does not have data to ascertain with certainty that any recovered gallons of product would be per year from a VRU 
system but based on the lean vapor / air mixture expected in the tank head spaces above the floating roof, the recovered gallons are not expected to provide a return that would 
economically justify the cost of the project to install an adequate system.
The estimated capital cost for a VRU that serves the IFRTs and VFRTs is based on the low estimate of each range. For an aggregated system that controls all IFRTs, EFRTs, and VFRTs, an 
estimate is provided for the high‐side. Furthermore, roof retrofit costs are assumed for all EFRTs to undergo conversion to utilize a VFRT in included in the latter aggregate system cost.
In addition to the common project scope, a project scope for a TO Installation would include the following additional efforts:
1) Natural gas supply would likely need to be added to the facility.
2) Work with the local utility provider would need to be done to ensure the volume required on‐site is available or if service modifications are required.
3) Piping from the natural gas supply point would need to be installed to the site of the TO skid.
4) An electrical feed will need to be provided. Electrical infrastructure in the tank farm is at capacity and service from a new substation would be required.
5) This is likely not large enough to require service upgrades from the utility but will require extra power distribution and significant runs of conduit and wire much like the VRU scope.
6) A concrete pad and footer will need to be created to place the TO skid on. 
7) The TO itself will need to be purchased from a 3rd party vendor. 
8) Supply chain issues associated with procuring all equipment will need to be incorporated into schedule.
A TO is estimated to cost approximately $750M. The natural gas piping and service upgrades are likely to cost $250M per site plus $150M additional in electrical and site prep charges. The 
natural gas usage will be significant and is estimated at $300‐500M per year ongoing, per site to maintain minimum temperatures in the TO.
Total Estimated costs for TO System = $2.15MM ‐$3.15MM plus $300M‐$500M in utility cost per site
The estimated capital cost for a TO that serves the IFRTs and VFRTs is based on the low estimate of each range. For an aggregated system that controls all IFRTs, EFRTs, and VFRTs, the 
high‐side estimate is used. Furthermore, roof retrofit costs are assumed for all EFRTs to undergo conversion to utilize a VFRT in included in the latter aggregate system cost.