DAQ-2025-001202

PM2.5 SIP Evaluation Report: Big West Oil, LLC Salt Lake City PM2.5 Serious Nonattainment Area
Utah Division of Air Quality Major New Source Review Section Originally Adopted July 1, 2018
Revised February 5, 2025

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PM2.5 SIP EVALUATION REPORT Big West Oil Refinery
1.0 Introduction The following is part of the Technical Support Documentation (TSD) for Section IX, Part H.12 of the Utah SIP; to address the Salt Lake City PM2.5 Serious Nonattainment Area. This document specifically serves as an evaluation of the Big West Oil, LLC – Big West Oil Refinery.
The revision to this TSD documents how each emission unit that existed at the refinery on January 1, 2019, met BACT/BACM. For any determination that BACT/BACM was met with existing controls (existing prior to the 2018 BACT determination, required at that time by Federal
or state regulation, or permitted prior to the 2018 determination), no new control requirements will be added to the SIP.
Economic and technical feasibility for determining BACT is based upon the 2017 BACT Analyses. Big West Oil cannot retroactively install equipment to meet the BACT deadline of January 1, 2019. 40 CFR 51.1011 establishes that control measures must be implemented no later
than the beginning of the year containing the applicable attainment date. Thus, for purposes of RFP and SIP credit, the deadline for implementation of all BACT and BACM is January 1, 2019.
Any control measures implemented beyond such date through June 9, 2021 (4 years after the date of reclassification) are instead regarded as “additional feasible measures.” Control measures that can only be implemented after June 9, 2021 are beyond the scope of this SIP. 1.1 Facility Identification
Name: Big West Oil Refinery Address: 333 W. Center Street, North Salt Lake, Utah, Davis County
Owner/Operator: Big West Oil, LLC
UTM coordinates: 4,521,000 m Northing, 422,500 m Easting, Zone 12
1.2 Facility Process Summary The Big West Oil Refinery is a petroleum refinery capable of processing 30,000 barrels per day
of crude oil. The source consists of a FCCU, catalytic reforming unit, hydro-treating units, and a sulfur recovery unit. The source also has the usual assorted heaters, boilers, cooling towers, storage tanks, flares, and fugitive emissions. The source does not operate with flare gas recovery
or cogeneration processes. 1.3 Facility Criteria Air Pollutant Emissions Sources
The following is a listing of the main emitting units from the Big West Oil Refinery (BWO): FCC Heater Alkylation Unit Deisobutanizer Reboiler Heater with Low-NOx Burners (LNB) #2 Crude Heater (LNB) Crude Pre-flash Heater (LNB) #1 Crude Heater with Ultra-Low NOx Burners (ULNB)

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Unifiner Heater (LNB) Reformer Heaters (LNB)
(MIDW) Heater (LNB) Hydrodesulfurization (HDS) Reboiler (LNB) HDS Heater (LNB)
Sulfur Removal Unit/Plant (SRU) and Tail Gas Incinerator Caustic Fuel Gas Scrubber FCC Regenerator Combustion Gas Vent
#1 Boiler with Ultra-Low NOx Burners (ULNB) #2 Boiler with Ultra-Low NOx Burners (ULNB) #6 Boiler with Ultra-Low NOx Burners (ULNB) Wabash Boiler with LNB and Flue Gas Recirculation Plant Flare #1 (South Plant Flare) Plant Flare #2 (North Plant Flare) VCU: Railcar Loading Facility and Vapor Combustor Unit Truck Load Rack and Vapor Recovery Unit
Standby (Emergency) Fire Pumps and Back-up Engine Cooling Towers Fugitives
Storage Tanks at Tank Farm This is not meant to be a complete listing of all equipment which may be involved or required
during permitting activities at the refinery; rather, it is a listing of all significant emission units or emission unit groups (such as the tank farm). See Appendix A for a more complete listing of all refinery emission units and emission unit groups. See Appendix B for supporting documentation
for all units with CEMs. Please note that the data in Appendix B are presented in raw, unprocessed form and include periods of monitor downtime, quality assurance, calibration, maintenance, out of control periods, and exempt periods, etc.
1.4 Facility 2016 Baseline Actual Emissions and Current PTE In 2016, BWO’s baseline actual emissions were determined to be the following1 (in tons per year): Table 1-1: Actual Emissions
Pollutant Actual Emissions (Tons/Year)
PM2.5 45.923
SO2 57.144 NOx 92.305 VOC 307.372
NH3 117.408
The current PTE values for BWO, as established by the most recent AO issued to the source (prior to the beginning of the year containing the applicable attainment date, i.e. January 1, 2019)
(DAQE-AN101220066-15)2 are as follows: Table 1-2: Current Potential to Emit
1 see References: #7 2 see References: #4

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Pollutant Potential to Emit (Tons/Year)
PM2.5 72.5 SO2 712.5
NOx 396.7 VOC 432.76 NH3 176.2*
* Ammonia emissions were never quantified in the AO, PTE is estimated.
2.0 Modeled Emission Values
A full explanation of how the modeling inputs are determined can be found elsewhere. However, a shortened explanation is provided here for context.
The base year for all modeling was set as 2016, as this is the most recent year in which a complete annual emissions inventory was submitted from each source. Each source’s submission was then verified, checking for condensable particulates, ammonia (NH3) emissions, and calculation methodologies. Once the quality-checked 2016 inventory had been prepared, a set of projection year inventories was generated. Individual inventories were generated for each projection year: 2017, 2019, 2020, 2023, 2024, and 2026. If necessary, the first projection year, 2017, was adjusted to account for any changes in equipment between 2016 and 2017. For new equipment not previously listed or included in the source’s inventory, actual emissions were assumed to be 90% of its individual PTE. While some facilities were adjusted by “growing” the 2016 inventory by REMI growth factors;
other facilities were held to zero growth. This decision was largely based on source type, and how each source type operates. The refineries have reported to UDAQ as a production group that they are operating at capacity and are not planning any production or major emission increases in
the time frame covered by the SIP BACT analysis. For these reasons, UDAQ used zero growth for all projection years beyond the 2016 baseline inventory.
For BWO, a summary of the modified emission totals for 2017 are shown below in Table 2-1. In addition to incorporating the emission changes from the 2015 Consent Decree AO (DAQE-AN101220066-15)3, the values in Table 2-1 also include a correction in the NH3 emissions. Prior to 2015, BWO based the reporting of “actual” emissions of NH3 on the emission factor listed in AP-42 for refinery FCC catalyst regenerators (AP-42, Table 5.1-1). Since 2015, BWO has relied on a direct stack test to calculate NH3 emissions. The most recent stack test on the FCC catalyst regenerator stack (conducted 6/28/2016) yielded an emission factor of 0.08 lb NH3/bbl of feed. Using the reported annual feed of approximately 4.3x10^6 bbl, the corrected NH3 emissions
would be just 0.171 tons for this unit. When combined with the other units, the total NH3 emissions for the plant are 4.4 tons annually.
Table 2-1: Modeled Emission Values
Pollutant Actual Emissions (Tons/Year)
PM2.5 11.2 SO2 10.6
NOx 92.3 VOC 307.4 NH3 4.4

3 see References: #4

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Since a value of zero (0) growth was applied for all projection years, the values listed above (the
2017 corrected values) would then be propagated through for each of the subsequent projection years- 2019, 2020, 2023, 2024 and 2026.
Next, the effects of BACT would be applied during the appropriate projection year. Any controls applied between 2014 and 2017 (such as any RACT or RACM required as a result of the moderate PM2.5 SIP), was already taken into account during the 2017 adjustment performed
previously. For example, in BWO’s case, those changes were included in the 2015 Consent Decree AO. Future BACT, meaning those items expected to be coming online between today and the regulatory attainment date (December 31, 2019), would be applied during the 2019 projection year. Notations in the appropriate projection year table of the emission inventory model input spreadsheet indicate the changes made and the source of those changes. Similarly, Additional Feasible Measures (AFM) or Most Stringent Measures (MSM), which might be applied in future projection years beyond 2019 are similarly marked on the spreadsheet.
The effects of those types of controls are applied on the projection year subsequent to the installation of each control – e.g. controls coming online in 2021 would be applied in the 2023 projection year, while controls installed in 2023 would be shown in 2024.
3.0 BACT Selection Methodology
The general procedure for identifying and selecting BACT is through use of a process commonly referred to as the “top-down” BACT analysis. The top-down process consists of five steps which consecutively identify control measures, and gradually eliminate less effective or infeasible
options until only the best option remains. This process is performed for each emission unit and each pollutant of concern. The five steps are as follows:
1. Identify All Existing and Potential Emission Control Technologies: UDAQ evaluated various resources to identify the various controls and emission rates. These include, but are not limited to: federal regulations, Utah regulations, regulations of other states, the RBLC, recently issued permits, and emission unit vendors. 2. Eliminate Technically Infeasible Options: Any control options determined to be technically infeasible are eliminated in this step. This includes eliminating those options with physical or technological problems that cannot be overcome, as well as eliminating those options that
cannot be installed in the projected attainment timeframe. 3. Evaluate Control Effectiveness of Remaining Control Technologies: The remaining control
options are ranked in the third step of the BACT analysis. Combinations of various controls are also included.
4. Evaluate Most Effective Controls and Document Results: The fourth step of the BACT analysis evaluates the economic feasibility of the highest ranked options. This evaluation includes energy, environmental, and economic impacts of the control option.
5. Selection of BACT: The fifth step in the BACT analysis selects the “best” option. This step also includes the necessary justification to support the UDAQ’s decision.
Should a particular step reduce the available options to zero (0), no additional analysis is required. Similarly, if the most effective control option is already installed, no further analysis is

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needed.
For the SLC-UT nonattainment area the attainment date is December 31, 2019. 40 CFR 51.1011 establishes that control measures must be implemented no later than the beginning of the year containing the applicable attainment date. Thus, for purposes of RFP and SIP credit, the deadline for implementation of all BACT and BACM is January 1, 2019. Any control measures implemented beyond such date are instead regarded as additional feasible
measures.4 4.0 BACT for the FCCU Regenerator The fluidized catalytic cracking unit, or FCCU, is a reactor where pre-heated feedstock is
combined with a very hot catalyst in order to “crack” or break the long-chain hydrocarbon molecules making up the feedstock. The long-chain molecules are broken down into shorter, lighter molecular weight hydrocarbons. These lighter materials then rise to the top of the reactor
where they are removed and sent elsewhere in the refinery for further processing. The spent catalyst is removed from the recovered material through a series of cyclones and sent to the regenerator section. The regenerator in most FCCUs is a secondary vessel located alongside (in a side-by-side configuration) the main reactor vessel. The regenerator is used to remove residual carbon buildup from the surface of the catalyst. This residual carbon, also called coke, reduces catalyst performance simply by adhering and coating the active surfaces of the catalyst. The catalyst is
quite hot when it exits the reactor, and simply introducing forced air is enough to cause the coke to combust. The additional heat from this combustion keeps the regenerator operating around 1300ºF. Catalyst coke contains a high amount of entrapped impurities depending on the chemical
nature of the feedstock. Sulfur, various nitrogen compounds, trace metals and other compounds may be present. These materials will be released during combustion of the coke and depending on the design of the regenerator may be altered during the combustion process as well. The
regenerator is the primary point of emissions from the FCCU. The BWO FCCU regenerator operates in complete combustion mode. Some regenerators are
designed to limit the amount of combustion to generate an exhaust gas that is relatively high in CO concentration – so that some of the additional heat value of the CO could be recovered in a secondary low-pressure steam boiler called a “CO boiler.” Complete combustion units aim to
burn off all of the CO in the exhaust gases to CO2 without use of a secondary boiler. BWO uses a combination of controls to limit the emissions from the FCCU regenerator. Particulates are controlled with a flue gas blowback, or Pall, filter. Sulfur emissions, in the form of SO2, are controlled using a sulfur reducing catalyst. Essentially the catalyst acts to repel sulfur
containing compounds from the cracking site, limiting the amount of sulfur that gets trapped in the residual catalyst coke. NOx emissions are limited through combustion temperature controls – in essence the design of the regenerator combustor is inherently low-NOx. Although no specific
add-on controls are currently in place to limit VOC or ammonia emissions, the complete combustion design minimizes VOC emissions, and BWO does not utilize ammonia injection for NOx control, thus limiting ammonia emissions. Only the residual ammonium salts which become
trapped in the catalyst coke are potentially released as ammonia emissions – currently stack tested

4 Utah State Implementation Plan, Control Measures for Area and Point Sources, Fine Particulate Matter, Serious Area PM2.5 SIP for the Salt Lake City, UT Nonattainment Area. Adopted by the Utah Air Quality Board January 2, 2019. Section IX, Part A.31, Section 8.3.

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at less than 1 ton per year.
Following the procedures outlined in Section 2 above, the 2017 corrected emissions from the FCCU regenerator are as follows:
PM2.5 = 0.675 tons, SO2 = 20.39 tons, NOx = 17.8 tons, VOC = 9.22 tons, NH3 = 0.171 tons. 4.1 PM2.5 4.1.1 Available Control Technology For control of particulate emissions from a FCCU regenerator, a source can choose from the usual array of options, either high efficiency electrostatic precipitation (ESP) or fabric filtration (baghouse) being the primary choices depending on the electrical resistivity of the coke burn-off at the particular refinery. Two additional, more recent choices have also emerged: wet gas scrubbing (WGS) and a “flue gas blowback filter” (FGF). The FGF is an in-stack filter that
operates in a similar fashion to a fabric filtration system, but on a smaller and faster cleaning scale. They are designed specifically for use with a FCCU, and have generally not been commercially applied in the U.S. but have seen successful application overseas. UDAQ has only
found a single application of a FGF in the U.S., namely the one installed at BWO. The other control options normally available for combustion related activities, such as fuel
switching or “good combustion controls,” are inherently limited by the nature of the process. The chemical nature of the feedstock and the type of cracking catalyst do make some difference in the resulting particulates generated during the regeneration process, but an individual refinery is
rather limited in which feedstocks it can accept based on physical configuration, geographical location, market forces (availability), and regulatory limits (on both the refinery emissions and the allowed final product). Ultimately, feedstock blending and catalyst changes have little to no
effect on particulate emissions. 4.1.2 Evaluation of Technical Feasibility of Available Controls All of the available controls are technically feasible in a general sense. BWO did provide evidence that neither an ESP nor a WGS would be able to be installed for emission control at the FCCU given constraints on physical size and location/placement of the control device. Specifically, the physical size of either device at a necessary efficiency to match the existing
control equipment would exceed the available area surrounding the FCCU. 4.1.3 Evaluation and Ranking of Technically Feasible Controls
In terms of efficiency, for control of particulate emissions, the available controls would be ranked as follows:
• Pulse jet fabric filter • FGF
• WGS • ESP
Fabric filters have the highest efficiency but are designed only to control particulate emissions. Because of their high efficiency, they suffer from a problem other control options do not have. Catalytic coke burn-off can be extremely sticky, and the fabric in these baghouses can easily

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become fouled and lead to blown bags. Higher cost bags can avoid this problem, but this application leads to higher operating costs.
The FGF option has a control efficiency nearly as high as a well-maintained pulse jet fabric filter. While the installation cost is much higher than that of a fabric filter, BWO evaluated this option
primarily through negotiations with EPA over its consent decree. The consent decree AO was issued May 18, 2015, and the FGF was installed in the early spring of 2016. Subsequent testing conducted during 2016 has shown a reduction in particulate emissions of approximately 98%.
Both the fabric filter and FGF control only the filterable fraction of particulate emissions, While the WGS system has the added benefit of removing particulates, it is primarily designed as a control device for removal of SO2 emissions. Installation and operation of a WGS is also far more expensive than any of the other options. Wet scrubbing inherently involves water treatment and disposal/discharge, which must be included in the operating cost. WGS has an additional benefit over both of the above options in that it also controls the condensable fraction of
particulate emissions – which can often be significantly larger than the filterable fraction. However, only venturi-type WGS systems can reach the same level of filterable control efficiency as fabric filters/FGF, and these have much higher energy and operating costs.
Use of a high efficiency ESP is the typical default option. BWO has retained the tertiary cyclone system to control PM emissions should the FGF go offline for some reason, but installation of an
ESP would be a considerable step backwards in control efficiency over the current technology. Retention of the old ESP system was not possible given the space constraints for the new FGF cleaning section, and power system. The use of an ESP will not be evaluated further.
4.1.4 Further Evaluation of Most Effective Controls
The top two control options, the fabric filter and the FGF are essentially identical in control efficiency. BWO has provided an analysis showing that both are capable of meeting the emission limitations required under 40 CFR 63 Subpart UUU and 40 CFR 60 Subpart Ja of 1 lb PM/1000 lb coke burn. At BWO’s annual coke burn off rate, this equates to an annual emission total of 0.675 tons of PM2.5 (PM10 = 1.23 lb annually). BWO did not directly evaluate the control cost of installing a WGS for control of particulate emissions, having eliminated this option in Step 2 as technically infeasible. However, based on
the use of such a system for control of other emissions from the equipment at the facility (which had been evaluated by BWO), the following information can be gleaned:
Use of a WGS would reduce particulate (PM2.5) emissions by approximately 35 tons (same control % as FGF and fabric filtration). Annualized cost of installation and operation $3,621,174. Final control cost = $103,462/ton of PM2.5. This is not economically feasible5.
4.1.5 Selection of BACT Controls
BWO was required to install the FGF as part of its consent decree in 2015. Resulting particulate emission reductions have been on par with any other control equipment option or technique. Estimated annual emissions of PM2.5 for the FCCU are less than 1 ton based on stack testing and the estimated throughput in 2017. These practices are required through existing permit

5 see References: #5

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requirements. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. Big West Oil will comply with any applicable emissions
limits in Section IX, Part H.11. See Appendix A for a complete listing of existing permit conditions, established emission limits, and the basis of those limits. 4.2 SO2 4.2.1 Available Control Technology
There exist several options for removing sulfur from FCCUs: • Use of low sulfur feedstocks. • Feed hydro-treating removes the sulfur prior to cracking operations. • DeSOx catalyst injection prevents the sulfur from forming in the coke so it isn’t burned off during regeneration. • WGS allows for use of normal (non-deSOx) catalyst use, and then removes the SO2 from the
exhaust gases through wet contact scrubbing These options, while not necessarily mutually exclusive, do have impacts on the control options
for other pollutants. Feed hydro-treating potentially has some positive benefit on NOx formation. Using a SOx reducing catalyst additive creates additional sulfate (condensable PM2.5). The use of WGS prevents the use of fabric filtration for particulate control, but allows the use of LoTOx, a
NOx control option. 4.2.2 Evaluation of Technical Feasibility of Available Controls
All of the listed controls are technically feasible; however, BWO has provided an analysis demonstrating physical spacing limitations on the installation of WGS for control of the FCCU
regenerator. Similarly, a catalytic feed hydro-treater system would require two additional reactor vessels occupying a total plot area of approximately 1200 ft2. The use of a hydro-treating system introduces similar physical occupancy concerns as with WGS. Although listed as technically infeasible by BWO, both WGS and feed hydro-treating will be further evaluated before elimination. 4.2.3 Evaluation and Ranking of Technically Feasible Controls
Feed hydro-treating is the least effective control option for BWO. Removal of sulfur from the feedstock can be extremely difficult and costly, depending on the type of feedstock involved. BWO is running a large percentage of highly-paraffinic waxy crude from eastern Utah which is
low in sulfur content. However, when properly designed this option is capable of reducing SO2 emissions to the limit required in 40 CFR 60.102a(b)(3) (Subpart Ja) of 50 ppmv on a 7-day average and 25 ppmv on an annual average.
The use of WGS technology can achieve a much higher level of SO2 control, easily reaching the limit required by Subpart Ja: 50/25 ppmv (7-day/annual). As noted above in the summary for
particulate control, WGS is a far more expensive option than either feed hydro-treating or deSOx catalyst. It also has the added disadvantage of water waste treatment and/or disposal. The use of SOx reducing catalyst, while not achieving quite the same level of control as WGS, is still able to meet the Subpart Ja limits. The known disadvantage of sulfate formation is covered through use of the previously selected FGF particulate control option. Since the implementation

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of the moderate PM2.5 SIP, BWO has been using SOx reducing catalyst as RACT.
4.2.4 Further Evaluation of Most Effective Controls
The space constraints greatly limit the effective use of WGS as a viable control option. While it is conceivably possible to relocate the control device to a more accommodating space, this would greatly change the exhaust gas parameters. The added flow distance would add considerable
pressure drop, and greatly lower the temperature of the exhaust and resulting plume rise. There could be condensation issues; stack gas temperatures falling below the dew point can lead to acid deposition and corrosion problems. UDAQ agrees with BWO that WGS is not a viable control option. Catalytic feed hydro-treating is less subject to physical space constraints than first considerations appeared. The source is still space restricted and would have difficulty in accommodating an additional unit of this size in the remaining available open area of the refinery. Future planned
expansions for generation of Tier 3 fuels, flare gas minimization systems and other processes also limit additional expansion. The emission reduction benefit from feed hydro-treating does not justify the additional expense, downtime, and burden of switching away from the use of SOx
reducing catalyst. 4.2.5 Selection of BACT Controls
UDAQ recommends that BWO continue to use SOx reducing catalyst as needed to meet the Subpart Ja FCCU SO2 limits. These limits have already been established in Section IX, Part
H.11.g of the SIP and are required through existing permit requirements. Monitoring, recordkeeping and reporting requirements are included as well. The existing limits account for current process variability while still limiting SO2 emissions from the FCCU. Therefore, the
existing limits are considered BACT. For a summary of the most recent CEMs data to support these conclusions, see Appendix B. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. Big West Oil will comply with any applicable emissions limits in Section IX, Part H.11. See Appendix A for a complete listing of existing permit conditions, established emission limits, and the basis of those limits. 4.3 NOx
4.3.1 Available Control Technology The available options for control of NOx from FCCUs are listed below:
• Low-NOx regeneration with low-NOx promoter catalysts • NOx reducing additive
• Selective non-catalytic reduction (SNCR) • Selective catalytic reduction (SCR) • Feed hydro-treating
• LoTOx in conjunction with WGS BWO already operates with the first option in place, so further evaluation of that option is unnecessary. The final option assumes that WGS will be used. Although the analysis for SO2 above did not result in WGS as the outcome, LoTOx will still be evaluated here.

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4.3.2 Evaluation of Technical Feasibility of BACT Controls
All control options are technically feasible, with one exception. Although LoTOx requires that a WGS system is simultaneously in use, this does not invalidate its technical feasibility. However, UDAQ does agree that the physical space limitations described by BWO do invalidate WGS as a
viable control option. Since WGS cannot be installed, the use of LoTOx is automatically disqualified as well.
BWO did provide information on the possible technical infeasibility of the use of NOx reducing additive, SCR and SNCR, but UDAQ believes this information is more appropriately discussed in Step 4. Therefore, all remaining control options will be further evaluated. 4.3.3 Evaluation and Ranking of Technically Feasible Controls The use of an SCR system was deemed to be technically infeasible by BWO, and no further evaluation was provided. During preparation of the moderate PM2.5 SIP, UDAQ’s contractor at
the time did provide additional information relating to economic feasibility and relative control value. Installation and operation of SCR would run approximately $800,000 per year when annualized. An SCR system can achieve approximately 80 to 90% control. Updating these values
to 2017 numbers and using a baseline of 17.4 tons/year of emissions, a total reduction of perhaps 14.7 tons/year is possible; yielding a relative control value of $57,400/ton.
Installation of LoTOx is expected to give a similar level of control on NOx as SCR, although the overall cost will be much higher, since it can only be installed along with a WGS system. The control value is estimated at $153,000/ton.
Feed hydro-treating was found to be economically infeasible, at $450,000/ton.
The use of SNCR presents difficulties as the ammonia injection inherent with this control option must be performed upstream of the FGF installed for particulate control. It also requires exhaust temperatures in the range of 1600ºF to 2000ºF for optimum NOx reduction. The flue gases exiting the FCCU are in excess of this optimum range, and do not re-enter the optimum range until after the particulate control filter (FGF). The ammonia compounds formed by the SNCR process (ammonium salts) would then exit the stack as uncontrolled particulates. The use of NOx reducing additives has been investigated by BWO6. To date, all tests have
proven ineffective for further reducing NOx emissions from the FCCU regenerator. Tests will likely continue, but at this time BWO has determined that the use of NOx reducing additives is not technically feasible. Without additional information, this control option will not be
investigated further. In order of effectiveness, only the existing control option of using low-NOx regeneration with
low-NOx promoter catalysts remains. However, both SNCR and SCR will be evaluated further in Step 4. 4.3.4 Further Evaluation of Most Effective Controls SCR and SNCR have an additional drawback in the form of ammonia slip. In order to control NOx, ammonia is injected to reduce the NOx to N2 and water. Ideally, a stoichiometric amount of

6 see References: #5

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ammonia would be added – just enough to fully reduce the amount of NOx present in the exhaust stream. However, some amount of ammonia will always pass through the process unreacted; and
since the process possesses some degree of variability, a small amount of additional ammonia is added to account for minor fluctuations. The ammonia which passes through the process unreacted and exits in the exhaust stream is termed “slip” (sometimes “ammonia slip”). The
amount varies from facility to facility, but ranges from almost zero to as high as 30 ppm in poorly controlled systems. In the case of SCR systems in particular, the catalyst also degrades over time, and the degree of slip will gradually increase as increasing amounts of ammonia are needed to
maintain NOx reduction performance. Please see the section on ammonia considerations for additional information. 4.3.5 Selection of BACT Controls Given the low amount of NOx reduction to be achieved, DAQ does not recommend any additional controls be installed. In 2016, BWO achieved actual emissions of 17.8 tons of NOx from the FCCU regenerator using the existing controls (Low-NOx regeneration with low-NOx promoter
catalysts). BWO’s FCCU already is subject to emissions limits from the Consent Decree and Approval Order (40 ppmvd at 0% O2 per 365-day rolling average; and 60 ppmvd at 0% O2 per seven-day rolling average) that are more stringent than those required by Subpart Ja (80 ppmvd at
0% O2 per seven-day rolling average). UDAQ recommends that Big West Oil continue to meet these emission limits as established in the existing Consent Decree and Approval Order. The existing limits account for current process variability while still limiting NOx emissions from the
FCCU. Therefore, the existing limits are considered BACT. For a summary of the most recent CEMs data to support these conclusions, see Appendix B. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. Big West Oil will
comply with any applicable emissions limits in Section IX, Part H.11. See Appendix A for a complete listing of existing permit conditions, established emission limits, and the basis of those limits.
4.4 VOC and Ammonia Considerations UDAQ was unable to locate any additional controls to reduce emissions of VOCs from the FCCU regenerator. In 2016, BWO’s VOC emissions from this unit were 9.2 tons. No viable add-on control device or technique was found to further reduce these emissions. Typical VOC reduction controls such as thermal or catalytic oxidation require relatively high VOC concentrations and often additional heat input in the form of fuel burning (negating the controls already achieved for
other pollutants). Control techniques such as fuel switching are negated by the nature of the process – the catalytic coke must be removed to continue the cracking process in the FCCU. The only remaining technique is simply good combustion practices, which is already required by the
other control systems previously mentioned. Good combustion practices are required through existing permit requirements. No additional controls are required for BACT, thus no additional limits are required to be established for the SIP. No additional consideration is required.
There are two possible mechanisms for ammonia emissions from the FCCU regenerator. Most refineries emit some amount of ammonia from the coke burn-off process itself, as trapped
ammonia salts present in the coke are released during the regeneration process. These emissions are relatively small, amounting to just 0.17 tons annually in BWO’s case. The second mechanism is the injection of ammonia for control of NOx emissions using either SCR or SNCR as a control process. The injection of ammonia is fairly common among refineries in the U.S. The standard set of emission factors for calculation of emissions (AP-42) even assumes this is the case by using a value of 54 lbs/1000 bbls (AP-42, Table 5.1-1). Beginning in 2016, BWO began testing

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ammonia emissions from the FCCU regenerator stack as no ammonia injection was taking place. Using the data from these tests, a new emission factor of 0.08 lb/1000 bbls was developed for
reporting purposes. UDAQ recommends that no additional BACT limitations be required for these two pollutants. Good combustion practices are required through existing permit requirements. No additional controls are required for BACT; thus, no additional limits are
required to be established for the SIP. 5.0 BACT for Process Heaters and Boilers The process heaters and boilers at BWO fall into two categories. For those heaters and boilers with heat input ratings less than 30 MMBtu/hr; UDAQ has completed a separate analysis of specific similar emission units which are common to many sources such as small heaters and boilers. Refer to the PM2.5 Serious SIP - BACT for Small Sources – Section 5 for details of that analysis. BWO has four (4) process heaters with heat input ratings greater than 30 MMBtu/hr – H-101, H-621, H-622, and H-624. All of the heaters are currently equipped with low-NOx (LNB) or ultra-low-NOx burners (ULNB), with the exception of H-101. In addition, BWO also operates
three (3) boilers above the heat input threshold: #1, #2 and #6. All three are currently equipped with ULNB. 5.1 PM2.5 Only a single PM2.5 BACT control was considered for process heaters or boilers. Given that these
emission units are fired on gaseous fuels, with inherently low particulate formation, few add-on controls are expected to be cost effective. Although the following controls have been identified as possible control technologies for reducing PM2.5 emissions, attempting to control emissions
post-combustion is neither technologically nor economically effective. 5.1.1 Available Control Technology
The following have been identified as possible controls for PM2.5 emissions: Good Combustion Practices, fuel choice ESP WGS Dry Gas Scrubbing (DGS) O2 Trim System
5.1.2 Evaluation of Technical Feasibility of Available Controls
GCP, combustion of only refinery fuel gas/natural gas and the use of an O2 trim system are all technically feasible. The remaining three control options – ESP, WGS and DGS – are all considered technically infeasible.
The concentration of particulate in the exhaust stream is too low for most ESP or DGS systems to be effective without significant increases in size, sorbent injection, and energy use. Non-venturi
WGS systems are ineffective at particulate removal from gaseous fuel combustion because the fine particulates have little inertia and follow the gas stream through the path of least resistance rather than being collected by impaction in the scrubbing liquid. Venturi-based systems have extremely high energy costs for the small amount of emission reduction gained and are not considered commercially available for this purpose.

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5.1.3 Evaluation and Ranking of Technically Feasible Controls
The three remaining controls: GCP, use of only refinery fuel gas/natural gas, and use of an O2 trim system can all be used in conjunction so there is no need to rank the control options in order of effectiveness.
5.1.4 Further Evaluation of Most Effective Controls
Both GCP and the type of fuel combusted are currently in use at BWO. These represent the baseline case. BWO submitted an economic analysis for installation of an O2 trim system on each of the heaters and boilers for control of PM2.5. An O2 trim system is designed to continuously measure and maintain an optimum air-to-fuel ratio in the boiler combustion zone. This limits the amount of particulate generated by maximizing complete combustion of the fuel. However, the baseline case of particulate generated (prior to the hypothetical installation of O2 trim) is that each of these three sources would generate less than 1 ton/yr of PM2.5. By installing O2 trim, each heater and boiler would be further controlled down to 0.02 (or less) tons PM2.5/yr,
but at a control cost of approximately $3 mil/ton. The use of O2 trim is not economically viable at these emission levels. 5.1.5 Selection of BACT UDAQ recommends that retention of the existing control techniques of GCP and use of only
gaseous fuel (refinery fuel gas and natural gas) be considered as BACT. As work practice standards, no limitation on emissions is required. These practices are required through existing permit requirements and standards which have been established in Section IX, Part H.11.g. No
additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. Big West Oil will comply with any applicable emission limits in Section IX, Part H.11. See Appendix A for a complete listing of existing permit conditions, established
emission limits, and the basis of those limits. 5.2 SO2 As with all combustion, SO2 emissions from the heaters and boilers is a direct function of the amount of sulfur present in the fuel. 5.2.1 Available Control Technology
By consolidating all process heaters and boilers together into a single group for BACT consideration DAQ is able to consider controls on some emissions from this group which would
ordinarily be dropped as too insignificant. However, it also limits the available options. In this particular case, only one option is available. The long-term Subpart Ja refinery fuel gas H2S limit of 60 ppmv as well as the existing short-term Subpart J limit of 162 ppmv on a 3-hour average.
The normally available options of flue gas desulfurization or fuel switching are not available in this case. Fuel switching is not possible given the requirements of eliminating the refinery fuel
gas generated during production of gasoline and other petroleum derivatives. The refinery fuel gas cannot be flared, and too much is produced to allow for reforming into heavier products (the energy losses would negate any positive benefit gained. Desulfurization systems rely on a relatively high concentration of sulfur compounds in the exhaust stream to function effectively and efficiently. By meeting the fuel gas H2S limits in Subparts J and Ja, the exhaust gas concentrations of SO2 will naturally fall below the critical concentrations necessary for optimum

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control. The combined 2016 emission values for the heaters and boilers mentioned above totaled less than 10 tons/yr. These are well below the emission levels where desulfurization is
considered commercially available. 5.2.2 Evaluation of Technical Feasibility of Available Controls
N/A These are standard limits which exist in two established federal requirements (NSPS subparts). Both limits have been met by BWO with no concerns or issues reported.
5.2.3 Evaluation and Ranking of Technically Feasible Controls The refinery is already subject to the requirements of Subpart J, and has been for some time. During the review of the various RACT evaluations made as part of the moderate PM2.5 SIP, DAQ determined that the fuel gas H2S limits from Subpart Ja would apply equally to all refineries in the nonattainment area and elected to make this a refinery general requirement. BWO has been operating under this requirement since January 1, 2015.
5.2.4 Further Evaluation of Most Effective Controls
No additional evaluation is required. BWO has been operating under both limits, and both limits are applicable to the source regardless of the status of the PM2.5 SIP. 5.2.5 Selection of BACT Controls UDAQ recommends that the Subpart Ja fuel gas H2S limits of 60 ppmv on a 365-day rolling
average and 162 ppmv on a 3-hour average be retained as BACT. These limits are currently listed as work practice requirements in Section IX, Part H.11.g of the SIP. These practices are required through existing permit requirements. The existing limits account for current process
variability while still limiting SO2 emissions from each process heater and boiler. Therefore, the existing limits are considered BACT. For a summary of the most recent CEMs data to support these conclusions, see Appendix B. For a summary of the potential emissions from each process heater and boiler with a capacity greater than 40 MMBtu/hr, see Appendix C. These calculations depend on the maximum SO2 emissions each heater and boiler could have emitted in 2017, compared to the actual emissions reported in the 2017 inventory. The actual emissions from 2017 are representative of normal operation throughout the year based on process and operation variability. Big West Oil will still comply with all existing permit and SIP requirements.
No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. Big West Oil will comply with any applicable emission limits in Section
IX, Part H.11. See Appendix A for a complete listing of existing permit conditions, established emission limits, and the basis of those limits. 5.3 NOx 5.3.1 Available Control Technology
Of the process heaters and boilers, the three reformer heaters H-621, H-622, H-624 are the ones equipped only with LNB. The boilers (#1, #2 and #6) are all equipped with ULNB. Additional control options also include sorbent injection, SCR, SNCR, flue gas recirculation (FGR), and WGS with LoTOx.

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5.3.2 Evaluation of Technical Feasibility of Available Controls
Installing and operating ULNB is technically feasible. FGR, SCR and SNCR are all technically feasible as retrofit controls, although specific space concerns, piping requirements or temperature
needs may limit the technical usefulness of these control options on any particular heater or boiler. Sorbent injection is also technically feasible, but requires additional control equipment, such as a baghouse, for capture of the reacted sorbent.
FGR is specifically not viable on those process heaters and boilers already equipped with ULNB. The control technology is redundant, as ULNB already makes use of recirculation to lower NOx emissions by reducing oxygen content in the inlet gas. Of the boilers and heaters discussed here, only the three reformer heaters could potentially benefit from FGR. The FGR system requires additional ductwork and damper controls to reroute part of the exhaust gas to the inlet side of the heater. The reformer heaters at BWO were not designed with FGR in mind when originally installed, and inclusion of this additional equipment would be difficult, if not physically
impossible, to install without great expense and a major overhaul of the surrounding equipment/infrastructure. BWO did not provide an economic analysis of this additional work, but did eliminate FGR as being technically infeasible on the size constraints alone.
After further evaluation, BWO eliminated SNCR on the basis of temperature control7. SNCR systems are sensitive to temperature fluctuations and require sufficient residence time to allow for
complete reaction between the ammonia/urea reagent and the NOx being controlled. Most of the heaters and boilers are used with variable demand loads that create variable temperature exhaust zones that are difficult to control with an unforgiving system like SNCR. Often the exhaust
temperature drops below the optimum range of SNCR effectiveness. SNCR is eliminated as a control option.
SCR is viable control option on the three boilers and the crude unit heater, but not for the three reformer heaters. For reasons similar to WGS, SCR is technically infeasible based on space considerations. The installation of the catalyst bed, ammonia/urea storage, and sufficient straight run of ductwork to ensure proper mixing, is impossible given the physical space limitations and positioning of the equipment in question. The three boilers (#1, #2 and #6) do not suffer from these same concerns and could be equipped with SCR controls. WGS is technically infeasible as has been discussed previously. Although technically feasible on
a purely technical basis, BWO has provided information demonstrating physical space constraints and other considerations which eliminate WGS as a viable control option. SCR systems occupy less space than WGS systems, and so SCR can be considered for the boilers – even though WGS
is still eliminated. WGS will not be evaluated further. 5.3.3 Evaluation and Ranking of Technically Feasible Controls
For those heaters not already equipped with ULNB, this option is still viable and would represent the next best level of control. A potential reduction of 10.1 tons of NOx could be achieved.
All three boilers could potentially be equipped with SCR, with a total reduction of 8.4 tons of NOx.

7 see References: #5

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Sorbent injection remains a viable option for all of the heaters and boilers, but achieves roughly half of the control efficiency listed above. It cannot be used in conjunction with SCR, as
injection prior to the SCR catalyst would foul the catalyst bed, and injection after the catalyst leaves insufficient residence time for effective control. It also cannot be used in conjunction with ULNB, as the inherent recirculation of the burners would cause the sorbent to be carried back
into the burner injectors potentially plugging them. 5.3.4 Further Evaluation of Most Effective Controls
BWO provided an economic evaluation of all three control options8: For installing and operating ULNB on the three reformer heaters, BWO calculated a control cost of $330,000/ton of NOx. To install and operate SCR on any of the emission units where SCR was determined viable, BWO calculated control costs between $2.0M and $3.8M/ton of NOx.
For sorbent injection, the lowest control cost value was calculated at $700,000/ton of NOx.
None of these additional controls are considered economically viable. 5.3.5 Selection of BACT Controls
UDAQ recommends the existing NOx controls remain as BACT. Big West Oil will comply with any applicable emission limits in Section IX, Part H.11. This section also contains additional
monitoring, recordkeeping and reporting requirements. These practices are required through existing permit requirements.
While no additional controls are required for BACT, UDAQ recommends additional stack testing requirements be added to bolster existing monitoring, recordkeeping, and reporting requirements. UDAQ has added additional limits for all process heaters and boilers with a capacity greater than 40 MMBtu/hr. This threshold is based on an established threshold in 40 CFR 60.102a for NOx limitations on process heaters, which was established based on the application of the best system of emission reduction while taking into consideration costs and impacts. Based on the existing NOx controls, UDAQ has established the following additional emission limits as BACT in Section IX, Part H.12:

• FCC Heater H-101: 0.1 lb/MMBtu
• Reformer Heaters H-621, 622, 624: 0.05 lb/MMBtu
• #1 Boiler: 0.035 lb/MMBtu
• #6 Boiler: 0.035 lb/MMBtu See Appendix A for a complete listing of existing permit conditions, established emission limits, and the basis of those limits. For a summary of the potential emissions from each process heater and boiler with a capacity greater than 40 MMBtu/hr, see Appendix C. These calculations depend
on the maximum NOx emissions each heater and boiler could have emitted in 2017 at the maximum of the above limits, compared to the actual emissions reported in the 2017 inventory. The actual emissions from 2017 are representative of normal operation throughout the year based

8 see References: #5

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on process and operation variability, existing stack tests, and established emission factors. Big West Oil will still comply with all existing permit and SIP requirements.
5.4 Consideration of VOC and Ammonia
UDAQ was unable to find any additional add-on controls or control techniques for further control of VOC emissions from the heaters and boilers listed in this section. While VOC controls do exist, primarily these controls are thermal or catalytic oxidation requiring relatively high VOC
concentrations and often additional heat input in the form of fuel burning (negating the controls already achieved for other pollutants). Control techniques such as fuel switching are not helpful since gaseous fuels such as refinery fuel gas and natural gas (the only fuels used by BWO in these units) are already the best available. The only control technique remaining is the use of good combustion practices. As GCP are already required or included as a part of the control techniques for the other pollutants listed previously no additional consideration is required. Good combustion practices are required through existing permit requirements. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP.
There are small amounts of ammonia emissions from the heaters and boilers naturally (some minor amounts of ammonia may be generated as part of the combustion process). Ammonia
emissions would be more of a concern if SCR or SNCR had been chosen as a viable control option. However, as no ammonia injection is being used, no ammonia slip can result. UDAQ does not recommend ammonia controls on the heaters and boilers at this time. Good combustion
practices are required through existing permit requirements. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. 6.0 BACT for Refinery Flares The refinery flares emit PM2.5, SO2, NOx and VOCs, as well as a minor amount of ammonia.
However, rather than evaluate the flares based on the individual pollutant emissions, UDAQ has historically evaluated the emissions from the flares based on the gases sent to the flares. During development of the Moderate PM2.5 SIP, UDAQ established that the refineries’ flares were to be used primarily as safety devices and not as process control devices. Therefore, each refinery was required to meet the requirements of Subpart Ja for all hydrocarbon flares, and to install and operate either a flare gas recovery system or alternative minimization process by January 1, 2019. 6.1 Flare Gas Emissions Available Control Technology
There are two parts to refinery flares, as outlined in the Refinery General RACT Evaluation9 for the moderate PM2.5 SIP. The first is setting all refinery hydrocarbon flares as subject to the
requirements of 40 CFR 60 Subpart Ja. The second is requiring all refineries to have a flare gas recovery system in place and operating by January 1, 2019 that meets the flare event limits listed in 40 CFR 60.103a(c). Since the development of the moderate SIP, BWO has conducted
additional analysis and determined that flare gas recovery remains an unavailable control option given the nature of BWO’s refinery processes. 6.2 Evaluation of Technical Feasibility of Available Controls BWO evaluated the ability of installing a flare gas compressor and determined that this option

9 see References: #3

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was technically infeasible10. BWO is “fuel gas long” – meaning that it already generates more fuel gas than it can accommodate through its existing fuel requirements at the refinery.
Attempting to capture and compress flare gases to return to the fuel gas system for recovery would simply compound this problem. BWO petitioned for option #2 in refinery general requirement IX.H.11.g.v.B – to limit flaring during normal operations to 500,000 scfd or less for
each affected flare. This value is derived from the identical value in NSPS Subpart Ja, and was originally determined for use in the Subpart from studies conducted at BWO and similarly sized and operated refineries (those operating “fuel gas long”).
6.3 Evaluation and Ranking of Technically Feasible Controls The refinery general requirement of subjecting all hydrocarbon flares to the requirements of Subpart Ja has already been accepted by all listed refineries. As well, BWO has begun evaluations of flaring events beginning in November of 2015. This evaluation requires that the refinery perform a “root cause analysis” on flaring events, and the evaluation of technical and economic feasibility of flare gas recovery to determine whether a flare gas recovery program is
viable regardless of any imposing of such requirement by DAQ. 6.4 Further Evaluation of Most Effective Controls
No additional analysis is required. The general requirements on refinery flares found at Section IX Part H.11.g of the moderate PM2.5 SIP are the only viable techniques for the control of
emissions from the refinery’s flares. No additional analysis is required. 6.5 Selection of BACT Controls
DAQ recommends that BWO implement the general refinery SIP requirements found in Section IX Part H.11.g. These practices are required through existing permit requirements. The existing
limits account for current process variability while still limiting SO2 emissions from the refinery flares. Therefore, the existing limits are considered BACT. For a summary of the most recent CEMs data to support these conclusions, see Appendix B. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. BWO will comply with any applicable emission limits in Section IX, Part H.11. See Appendix A for a complete listing of existing permit conditions, established emission limits, and the basis of those limits. 7.0 BACT for the SRU
BWO operates a well-controlled sulfur recovery plant meeting the established 95% sulfur recovery required under the PM10 SIP (SIP Section IX, Part H.1). Generically, the sulfur
recovery systems at the various refineries located in the PM2.5 non-attainment areas are referred to as sulfur recovery units or SRUs. For purposes of this review a “well-controlled SRU” is one that is already operating with a tail gas treatment system followed by tail gas incineration. BWO has
also added a redundant caustic scrubber system to treat the refinery fuel gas during outages of the SRU.
There are only two pollutants of concern from a well-controlled SRU: SO2 and NOx. The system is designed to remove sulfur (primarily in the form of H2S) from the refinery fuel gas through a combination of catalytic treatment and combustion. A portion of the total H2S is burned to form SO2. Then, the H2S and SO2 react, at an optimal 2:1 ratio, to form elemental sulfur. After each

10 see References: #5

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catalytic stage, the liquid sulfur is recovered from condensers. Any remaining unreacted sulfur compounds are then hydro-treated in the tail gas treatment unit to form H2S exclusively. The
remaining H2S is combusted in the tail gas incinerator yielding SO2. Through the heat of combustion, some NOx is formed (thermal NOx), but particulate and VOC emissions are very low.
7.1 Available Control Technology
Three control systems were identified to further control emissions from a well-controlled SRU. For purposes of this review a “well-controlled SRU” is one that is already operating with a tail gas treatment system followed by tail gas incineration. • LoCat • WGS • Caustic Scrubbing • Additional Tail Gas Treatment
LoCat is unusual in that it can serve as both a final treatment following the SRU (both in addition to, or in-lieu of a tail gas unit) or as a fuel gas sulfur removal unit (in case the SRU itself goes
down). WGS is a final control option, where the exhaust from the SRU is sent to the WGS in-lieu of tail
gas treatment. Caustic scrubbing is typically used as a replacement for a SRU, such as a redundant back-up
device, but can be used as a final scrubbing process. 7.2 Evaluation of Technical Feasibility of Available Controls
All controls are technically feasible. 7.3 Evaluation and Ranking of Technically Feasible Controls BWO has previously reviewed the installation of LoCat technology and determined that the emission control possible was less effective than the existing system. Caustic scrubbing was determined to be a viable backup control option, but did not serve as a primary control or as an
additional add-on control to operate in series with the existing SRU and tail gas system. Both WGS and the installation of an additional tail gas unit would achieve greater emission
reductions than the current base case. Emission reductions of approximately 3.5 tons of SO2 are possible for both controls, while WGS can also reduce NOx emissions by 0.25 tons. 7.4 Further Evaluation of Most Effective Controls BWO conducted an economic analysis of installing either the WGS system or an additional tail
gas unit for further treatment of the SRU emissions. Based on the expected reductions in emissions, a WGS’s control cost is estimated at $700,000/ton. A second tail gas unit’s control cost is estimated at $4.5M/ton removed11. Neither option is economically viable.

11 see References: #5

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7.5 Selection of BACT Controls
UDAQ recommends that BWO continue to operate the existing SRU system and redundant SO2 caustic scrubber. BWO is subject to the PM10 SIP and PM2.5 SIP refinery requirements found at Section IX Parts H.1.g and H.11.g. These practices are required through existing permit
requirements. The existing emission limitation was established based on NSPS Subpart Ja, using the equations found in 40 CFR 60.102a(f). These emission limitations were established based on the application of the best system of emission reduction while taking into consideration costs and
impacts. The existing limits account for current process variability while still limiting SO2 emissions from the SRU. Therefore, the existing limits are considered BACT. For a summary of the most recent CEMs data to support these conclusions, see Appendix B. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. BWO will comply with any applicable emission limits in Section IX, Part H.11. See Appendix A for a complete listing of existing permit conditions, established emission limits, and the basis of those limits.
8.0 BACT for Standby Fire Pumps BWO provided a BACT analysis for the standby fire pump which ultimately resulted in retaining
the use of the existing equipment with no additional controls. At the time of this document preparation, BWO had submitted an application to replace the fire pump with five (5) new, tier 3, standby, fire pumps, as part of upgrading the entire fire control system for the refinery. The
engines were identified as subject to 40 CFR 60 Subpart IIII and 40 CFR 63 Subpart ZZZZ as applicable for stationary sources that operate emergency engines. The BACT analysis12 concluded that use of engines subject to Subparts IIII and ZZZZ, Tier 3 certified engines, use of
ultra-low sulfur diesel fuel (15 ppm), use of good combustion practices, and adherence to the manufacturer’s operation and maintenance manuals would constitute BACT. UDAQ agreed with the analysis and ultimately issued an Approval Order DAQE-AN101220074-19, which
documented agreement with the analysis. Separately, UDAQ prepared guidance for BACT for Diesel-Fired Emergency Generators rated between 200-600 hp in its “PM2.5 Serious SIP BACT for Small Sources”13. The evaluation concluded that for replacement of old engines with new engines subject to Subpart IIII would potentially be cost feasible for NOx and VOC. BACT for SO2 included used of ULSD, and BACT for PM2.5 included conducting proper maintenance and operation of the engines. These requirements align with the BACT assessment completed by BWO.
Therefore, use of engines subject to Subparts IIII and ZZZZ, Tier 3 certified engines, use of ultra-low sulfur diesel fuel (15 ppm), use of good combustion practices, and adherence to the
manufacturer’s operation and maintenance manuals would constitute BACT. These practices are required through existing permit requirements. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. BWO will comply with any
applicable emission limits in Section IX, Part H.11. 9.0 BACT for Cooling Towers

12 Notice of Intent submitted by Big West Oil to UDAQ, dated April 30, 2018, 13 DAQ-2018-007161, “Appendix A – PM2.5 Serious SIP BACT for Small Sources,” Section 8B. Available at: https://documents.deq.utah.gov/air-quality/pm25-serious-sip/DAQ-2018-007161.pdf.

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There are two main pollutants of concern from cooling towers used in refinery settings. Like all industrial cooling towers, some particulate emissions will result during the evaporation of the
cooling water. For further details on BACT controls for particulate emissions from cooling towers please refer to the PM2.5 Serious SIP - BACT for Small Sources – Section 6 for the analysis.
Cooling towers found in refineries have a secondary concern. It is possible for the cooling water to pick up volatile compounds during the heat transfer process, and for these compounds to be
released as VOCs. As the levels of VOCs in refinery cooling water can be large enough to deserve their own controls, a separate BACT analysis is provided. 9.1 VOCs 9.1.1 Available Control Technology UDAQ employed the services of a contractor during review of the RACT evaluations for the
moderate PM2.5 SIP. Only a single control technique was determined to be “available.” During that review, it became apparent that DAQ’s contractor was making the same recommendation to all of the refineries located in the PM2.5 non-attainment area. Specifically, that each refinery apply
the 40 CFR 63 Subpart CC requirements to all cooling towers servicing heat exchangers with high VOC content streams. These requirements are basically leak detection and repair programs that apply specifically to cooling towers by checking for the presence of VOCs in the cooling
water on a periodic basis. If detected, then service or repair of the relevant heat exchanger is warranted. 9.1.2 Evaluation of Technical Feasibility of Available Controls All the refineries located in the PM2.5 non-attainment area agreed to an application of the MACT
CC language which was included in the moderate PM2.5 SIP in Section IX, Part H.11.g. 9.1.3 Evaluation and Ranking of Technically Feasible Controls N/A This has become a refinery general SIP requirement. 9.1.4 Further Evaluation of Most Effective Controls
N/A This has become a refinery general SIP requirement. 9.1.5 Selection of BACT Controls
UDAQ recommends that BWO continue to follow the general refinery SIP requirements found in Section IX, Part H.11.g. These practices are required through existing permit requirements. No
additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. BWO will comply with any applicable emission limits in Section IX, Part H.11.
10.0 BACT for Fugitives
In this context, fugitives are referring to fugitive VOC emissions. While BWO does have fugitive dust emissions from items such as roads, spill containment berms, and similar earthworks – particulate emissions from these items have been evaluated separately. Please refer to the PM2.5

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Serious SIP - BACT for Small Sources – Section 12 for the evaluation.
Fugitive VOC emissions are those emissions that result from the various pipe connections; feedstock, intermediary, and product transfer activities; loading and unloading operations; and any and all equipment leaks. They do not typically include the VOC emissions from storage
vessels (storage tanks), cooling towers, or wastewater treatment. 10.1 VOCs
10.1.1 Available Control Technology The only available control option is the low-leak LDAR program as outlined in 40 CFR 60 Subpart VVa and incorporated by reference (with some source category modifications) in 40 CFR 60 Subpart GGGa. Each refinery (including BWO) became subject to the requirements of low-leak LDAR (Subpart GGGa) as part of the requirements of the moderate PM2.5 SIP.
10.1.2 Evaluation of Technical Feasibility of Available Controls N/A Low-leak LDAR is technically feasible, and BWO became subject to its requirements on
January 1, 2017. 10.1.3 Evaluation and Ranking of Technically Feasible Controls
N/A BWO is already implementing the requirements of 40 CFR 60 Subpart GGGa. 10.1.4 Further Evaluation of Most Effective Controls N/A BWO is already implementing the requirements of 40 CFR 60 Subpart GGGa.
10.1.5 Selection of RACT Controls UDAQ recommends that BWO continue to implement the general refinery SIP requirements regarding Leak Detection and Repair as outlined in Section IX, Part H.11.g. These practices are required through existing permit requirements. No additional controls are required for BACT; thus, no additional limits other than those established in H.11.g are required to be established for the SIP. BWO will comply with any applicable emission limits in Section IX, Part H.11.
11.0 BACT for Tanks
Although most of UDAQ’s analysis of storage vessels, more commonly referred to as storage tanks (or just “tanks”), can be found in the PM2.5 Serious SIP - BACT for Small Sources – Section 13, the refineries as a group were evaluated for two additional BACT controls beyond the
small source controls. First, the refineries have some tanks that are larger than the 30,000 gallon cut-off used in the small source analysis. Second, during development of the moderate 2.5 SIP, the refineries were required to implement a tank degassing work practice standard14 at Section IX,
Part H.11.g.vi. 11.1 VOC

14 see References: #3

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11.1.1 Available Control Technology
Although tanks as a group were evaluated for tank degassing, individual tanks were not evaluated for working or breathing losses. While some VOCs are emitted during these periods, these can only be controlled on a tank by tank basis. Larger tanks are already subject to floating roof and
specific seal requirements such as those found in 40 CFR 60 Subpart Kb. Some additional VOC reductions could be gained by including slotted guide poles and geodesic
domes, but these gains are relatively minor. In the case of slotted guide poles, such requirements are more easily handled through individual permitting requirements. Individual tanks can also be controlled by vapor recovery, vapor scrubbers, or vapor combustors. Geodesic domes have not been found to be economically or technically feasible. 11.1.2 Evaluation of Technical Feasibility of Available Controls The use of slotted guide poles and vapor controls are technically both technically feasible. Tank
degassing as a group control is also technically feasible, and was included as a requirement of the moderate PM2.5 SIP. 11.1.3 Evaluation and Ranking of Technically Feasible Controls Tank degassing during tank shutdowns was required as of the moderate PM2.5 SIP. The
remaining controls can be employed in conjunction with tank degassing. The various methods of vapor control (recovery, scrubbing, and combustion) are all similar in effectiveness and are employed primarily on a tank by tank basis. While some economy of scale could conceivably be
achieved by combining the emissions from several tanks, tank vapors are primarily released during filling or unloading, and nearby tanks are rarely loaded or unloaded at the same time. 11.1.4 Further Evaluation of Most Effective Controls BWO is already required to follow the tank degassing requirements of Section IX, Part H.11.g. The remaining vapor controls were all evaluated by BWO and were found not be economically feasible, with cost effectiveness values in excess of $200,000/ton of VOC control15. 11.1.5 Selection of BACT Controls
UDAQ recommends that BWO continue to implement the SIP general refinery requirements on tank degassing as outlined in Section IX, Part H.11.g. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. BWO will comply
with any applicable emission limits in Section IX, Part H.11. 12.0 BACT for Wastewater System
12.1 VOC
The wastewater treatment system consists primarily of a system of drains that route runoff water and storm water to the API separator, which separates entrained oils and volatiles from the wastewater. BWO currently operates the API separator with a fixed cover to limit VOC emissions.

15 see References: #5

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12.1.1 Available Control Technology
Only two control options were identified to reduce VOC emissions from the wastewater system. The collected vapors from the API separator can be routed to a control device for capture or
destruction. Carbon canisters reduce emissions by capturing the VOCs using activated carbon filtration. Oxidation, using either thermal treatment or catalytic oxidation systems, is also a viable option for elimination of VOC emissions.
12.1.2 Evaluation of Technical Feasibility of Available Controls Both options are technically feasible. 12.1.3 Evaluation and Ranking of Technically Feasible Controls BWO installed the fixed API cover as part of the RACT controls for the moderate PM2.5 SIP.
Following installation of the fixed cover, BWO’s baseline actual emissions dropped to approximately 16.5 tons in 201616. Both control options achieve similar levels of additional reductions: 15.4 tons of VOCs removed using the carbon canisters, 15.9 tons of VOCs removed
with oxidation. 12.1.4 Further Evaluation of Most Effective Controls
BWO conducted an economic analysis of both control options. Based on the estimated possible emission reductions, the control cost of installing and using the carbon canister options is
approximately $8,000/ton of VOC removed. Both thermal and catalytic oxidation have control costs of over $75,000/ton of VOC removed17.
Based on these values, the use of the carbon canisters is economically feasible, while neither oxidation system is economically viable. 12.1.5 Selection of BACT Controls UDAQ recommends that BWO continue to operate the existing wastewater treatment system with fixed API cover, plus install and operate a set of carbon canisters for VOC control. The carbon canisters shall achieve 90% or better removal. Operation of the carbon canisters is required in
Part H.12.b.v. No additional controls are required for BACT, thus no additional limits other than those established in H.12.b.v are required to be established for the SIP. 13.0 Additional Feasible Measures and Most Stringent Measures 13.1 Extension of SIP Analysis Timeframe
As outlined in 40 CFR 51.1003(b)(2)(iii):
If the state(s) submits to the EPA a request for a Serious area attainment date extension simultaneous with the Serious area attainment plan due under paragraph (b)(1) of this section, such a plan shall meet the most stringent measure (MSM) requirements set forth at § 51.1010(b)
16 see References: #7 17 see References: #5

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in addition to the BACM and BACT and additional feasible measure requirements set forth at § 51.1010(a).
Thus, with the potential for an extension of the SIP regulatory attainment date from December 31, 2019 to December 31, 2024, the SIP must consider the application of both Additional Feasible
Measures (AFM) and Most Stringent Measures (MSM). 13.2 Additional Feasible Measures at BWO
As defined in Subpart Z, AFM is any control measure that otherwise meets the definition of “best available control measure” (BACM) but can only be implemented in whole or in part beginning 4 years after the date of reclassification of an area as Serious and no later than the statutory attainment date for the area. The Salt Lake City Nonattainment Area was reclassified as Serious on June 9, 2017. Therefore, any viable control measures that could only be implemented in whole or in part beginning 6/9/2021 (4 years after the date of reclassification) are classified as AFM.
After a review of the available control measures described throughout this evaluation report, UDAQ was unable to identify any additional control measures that were eliminated from BACT
consideration due to extended construction or implementation periods. 13.3 Most Stringent Measures at BWO
As defined in Subpart Z, MSM is defined as:
… any permanent and enforceable control measure that achieves the most stringent emissions reductions in direct PM2.5 emissions and/or emissions of PM2.5 plan precursors from among those control measures which are either included in the SIP for any other NAAQS, or have been
achieved in practice in any state, and that can feasibly be implemented in the relevant PM2.5 NAAQS nonattainment area. This is further refined and clarified in 40 CFR 51.1010(b), to include the following Steps: Step 1) The state shall identify the most stringent measures for reducing direct PM2.5 and PM2.5 plan precursors adopted into any SIP or used in practice to control emissions in any state. Step 2) The state shall reconsider and reassess any measures previously rejected by the state
during the development of any previous Moderate area or Serious area attainment plan control strategy for the area. Step 3) The state may make a demonstration that a measure identified is not technologically or
economically feasible to implement in whole or in part by 5 years after the applicable attainment date for the area, and may eliminate such whole or partial measure from further consideration.
Step 4) Except as provided in Step 3), the state shall adopt and implement all control measures identified under Steps 1) and 2) that collectively shall achieve attainment as expeditiously as practicable, but no later than 5 years after the applicable attainment date for the area.
13.3.1 Step 1 – Identification of MSM For purposes of this evaluation report UDAQ has identified for consideration the most stringent methods of control for each emission unit and pollutant of concern (PM2.5 or PM2.5 precursor). A summary is provided in the following table:

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Table 13-1: Most Stringent Controls by Emission Unit
Emission Unit Pollutant Most Stringent Control Method FCCU Regenerator PM2.5 GCP, fuel type, flue gas filter (FGF) / wet gas scrubber (WGS) SO2 DeSOx catalyst, WGS
NOx GCP, de-NOx catalyst, feed hydro-treating, deNOx additive (?), use of Lo-TOx. Heaters/Boilers NOx ULNB, SCR
Ammonia only if SCR is used, feedback controls
Flares Flare Gas flare minimization program
SRU SO2 second tail gas treatment unit (TGTU), WGS
NOx WGS
Cooling Towers VOC MACT CC requirements Fugitives VOC NSPS GGGa LDAR requirements Tanks VOC tank degassing requirements
Wastewater Treatment VOC API separator cover with carbon canister control / oxidation
The above listed controls represent the most stringent level of control identified from all other state SIPs or permitting actions, but do not necessarily represent the final choice of MSM. That is
determined in Step 4. 13.3.2 Step 2 – Reconsideration of Previous SIP Measures
Utah has previously issued a SIP to address the moderate PM2.5 nonattainment areas of Logan, Salt Lake City, and Provo. The SIP was issued in parts: with the section devoted to the Logan
nonattainment area being found at SIP Section IX.A.23, Salt Lake City at Section IX.A.21, and Provo/Orem at Section IX.A.22. Finally, the Emission Limits and Operating Practices for Large Stationary Sources, which includes the application of RACT at those sources, can be found in the SIP at Section IX Part H. Limits and practices specific to PM2.5 may be found in subsections 11, 12, and 13 of Part H. Accompanying Section IX Part H was a TSD that included multiple evaluation reports similar to this document for each large stationary source identified and listed in each nonattainment area. UDAQ conducted a review of those measures included in each previous evaluation report which contained emitting units which were at all similar to those installed and operating at BWO.
There were several technologies that had been eliminated from further consideration at some point during many of the previous reviews. Some emitting units were considered too small, or emissions too insignificant to merit further consideration at that time. The cost effectiveness
considerations may have been set at too low a threshold (a question of cost in RACT versus BACT). And many cases of technology being technically infeasible for application – such as applying catalyst controls to infrequently used emitting units which may never reach an operating
temperature where use of the catalyst becomes viable and effective. In one particular case, these previously rejected control technologies were already brought
forward and re-evaluated using updated information (more recent permits, emission rates and cost information) by BWO in its BACT analysis report. This was the deferment of VOC controls for the wastewater treatment systems at four Salt Lake City area refineries. BWO did include an
analysis of the wastewater treatment system, and took into account previous steps (such as the fixed cover installed at the API separator) previously undertaken to reduce emissions. This

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updated analysis has been reviewed as part of the UDAQ BACT review in Section 12 above. 13.3.3 Step 3 – Demonstration of Feasibility A control technology or control strategy can be eliminated as MSM if the state demonstrates that
it is either technically or economically infeasible. This demonstration of infeasibility must adhere to the criteria outlined under §51.1010(b)(3), in
summary: 1) When evaluating technological feasibility, the state may consider factors including but not limited to a source's processes and operating procedures, raw materials, plant layout, and potential environmental or energy impacts 2) When evaluating the economic feasibility of a potential control measure, the state may consider capital costs, operating and maintenance costs, and cost effectiveness of the measure.
3) The SIP shall include a detailed written justification for the elimination of any potential control measure on the basis of technological or economic infeasibility.
This evaluation report serves as written justification of technological or economic feasibility/infeasibility for each control measure outlined herein. Where applicable, the most effective control option was selected, unless specifically eliminated for technological or
economical infeasibility. Expanding on the previous table, the following additional information is provided: Table 13-2: Feasibility Determination
Emission Unit Pollutant MSM Previously Identified Is Method Feasible?
FCCU Regenerator PM2.5 GCP, fuel type, FGF/WGS See below
SO2 deSOx catalyst, WGS See below
NOx GCP, deNOx catalyst, feed hydro-treating, deNOx additive, LoTOx
See below
Heaters/Boilers NOx ULNB, SCR See below
Ammonia NH3 feedback See below
Flares Flare Gas flare minimization program Yes
SRU SO2 TGTU or WGS No, high cost
NOx WGS No, high cost Cooling Towers VOC MACT CC Yes Fugitives VOC LDAR Yes
Tanks VOC tank degassing Yes
WW Treatment VOC carbon canister / oxidation Yes, see below

Most of the entries in the above table were determined to be feasible on a technological basis. However, in several cases two distinct paths exist that are mutually exclusive. Two control techniques could serve equally as BACT/BACM or MSM, but they are not simply
interchangeable. Once a source has elected to follow a particular path for emission control, needing to change over to the alternative control path would involve considerable expense as well as complete removal of the existing system(s). In many cases this would also involve shutting
down operation of the source for an extended period of time – posing additional economic burden on the source.

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One particular example of this is the application (or lack) of WGS. Wet gas scrubbing has the
capability of removing both particulates and acid gases (SO2 and derivatives) and, if the LoTOx option has been pursued, NOx as well. However, this control system is not compatible with other control systems such as fabric filtration (baghouses or FGF), catalytic controls (SCR), or tail gas
treatment (as these are also catalytic controls). If the WGS is installed secondary to the existing controls, these would render the use of WGS redundant and extremely cost ineffective (the inlet concentrations would simply be too low to be viable). Alternatively, the WGS would be installed
as the primary control, creating a similar situation for the “existing” controls, but with an additional problem of a now water saturated exhaust stream and a greatly lowered exhaust temperature. Removing the existing controls to swap to the new control option is often millions of dollars above and beyond the millions already spent on the primary BACT level control. In BWO’s case, the FGF used for particulate control on the FCCU catalyst regenerator is required by consent decree and could not simply be “swapped out” without agreement of all parties involved in that agreement.
The costs for WGS and a second TGTU on the SRU do not currently justify including either of these controls as MSM. With total expected reductions in SO2 of just 3.5 tons, UDAQ cannot recommend either control option as MSM. 14.0 New PM2.5 SIP – General Requirements
The general requirements for all listed sources are found in SIP Subsection IX.H.11. These serve as a means of consolidating all commonly used and often repeated requirements into a central location for consistency and ease of reference. As specifically stated in subsection IX.H.11.a
below, these general requirements apply to all sources subsequently listed in either IX.H.12 (Salt Lake City) or IX.H.13 (Provo/Orem), and are in addition to (and in most cases supplemental to) any source-specific requirements found within those two subsections.
IX.H.11.a. This paragraph states that the terms and conditions of Subsection IX.H.11 apply to all sources subsequently addressed in the following subsections IX.H.12 and IX.H.13. It also clarifies that should any inconsistency exist between the general requirements and the source specific requirements, then the source specific requirements take precedence. IX.H.11.b Paragraph i: States that the definitions found in State Rule 307-101-2, Definitions, apply to SIP Section IX.H. Since this is stated for the Section (IX.H), it applies equally to
IX.H.11, IX.H.12 and IX.H.13. A second paragraph (ii), includes a new definition for natural gas curtailment for those sources in IX.H.12 and IX.H.13 that reference it.
IX.H.11.c This is a recordkeeping provision. Information used to determine compliance shall be recorded for all periods the source is in operation, maintained for a minimum period of five (5) years, and made available to the Director upon request. As the general recordkeeping
requirement of Section IX.H, it will often be referred to and/or discussed as part of the compliance demonstration provisions for other general or source specific conditions. It also includes provisions referring to the reporting of emission inventories and reporting deviations
(paragraph ii). IX.H.11.d Statement that emission limitations apply at all times that the source or emitting
unit is in operation, unless otherwise specified in the source specific conditions listed in IX.H.12 or IX.H.13. It also clarifies that particulate emissions consist of both the filterable and condensable fractions unless otherwise specified in IX.H.12 or IX.H.13.

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This is the definitive statement that emission limits apply at all times – including periods of
startup or shutdown. It may be that specific sources have separate defined limits that apply during alternate operating periods (such as during startup or shutdown), and these limits will be defined in the source specific conditions of either IX.H.12 or IX.H.13.
Conditions 1.a, 1.b and 1.d are declaratory statements, and have little in the way of compliance provisions. Rather, they define the framework of the other SIP conditions. As condition 1.c is
the primary recordkeeping requirement, it shall be further discussed under item 4.2 below. IX.H.11.e This is the main stack testing condition, and outlines the specific requirements for demonstrating compliance through stack testing. Several subsections detailing Sample Location, Volumetric Flow Rate, Calculation Methodologies and Stack Test Protocols are all included – as well as those which list the specific accepted test methods for each emitted pollutant species (PM10, NOx, or SO2). Finally, this subsection also discusses the need to test at an acceptable production rate, and that production is limited to a set ratio of the tested rate.
IX.H.11.f This condition covers the use of CEMs and opacity monitoring. While it specifically details the rules governing the use of continuous monitors (both emission monitors
and opacity monitors), it also covers visible opacity observations through the use of EPA reference method 9.
Both conditions 11.e and 11.f serve as the mechanism through which sources conduct monitoring for the verification of compliance with a particular emission limitation. 14.1 Monitoring, Recordkeeping and Reporting As stated above, the general requirements IX.H.11.a through IX.H.11.f primarily serve as
declaratory or clarifying conditions, and do not impose compliance provisions themselves. Rather, they outline the scope of the conditions which follow in the source specific requirements of IX.H.12 and IX.H.13. For example, most of the conditions in those subsections include some form of short-term emission limit. This limitation also includes a compliance demonstration methodology – stack test, CEM, visible opacity reading, etc. In order to ensure consistency in compliance demonstrations and avoid unnecessary repetition, all common monitoring language has been
consolidated under IX.H.11.e and IX.H.11.f. Similarly, all common recordkeeping and reporting provisions have been consolidated under IX.H.11.c.
15.0 Revised PM2.5 SIP – General Refinery Requirements The revised PM2.5 SIP incorporates several new requirements that apply specifically to those
petroleum refineries listed in Section IX.H.12 of the SIP. Some subsections of IX.H.11.g also apply more broadly and could affect additional petroleum refineries in addition to those listed in IX.H.12. Where this greater applicability exists for a particular condition or limitation, such will
be noted in the discussion for that requirement. IX.H.11.g.i.A This condition covers SO2 emissions from fluidized catalytic cracking units (FCCUs). The limit is 50 ppmvd @ 0% excess air on a 7-day rolling average basis, as well as 25 ppmvd @ 0% excess air on a 365-day rolling average basis.

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The condition is based on 40 CFR 60 Subpart Ja, and includes the same limitation found in that subpart. Compliance is demonstrated by CEM, as outlined in 40 CFR 60.105a(g) – also from
Subpart Ja. IX.H.11.g.i.B This condition addresses PM emissions from FCCUs. The limit is 1.0 lb PM per
1000 lb coke burned. The emission limit applies on a 3-hour average basis. The emission limit is derived from 40 CFR 60 Subpart Ja, although Subpart Ja does not
specifically state that the limit applies on a 3-hour average. Instead it states that compliance will be demonstrated via a performance test using Method 5, 5b or 5f, using an average of three 60-minute (minimum) test runs. Compliance is demonstrated by stack test as outlined in 40 CFR 60.106(b). This stack testing procedure is from Subpart J, rather than Subpart Ja. The equations utilized and reference methods involved are identical between the two subparts; however, the protocol to follow for testing is much more direct and straightforward in §60.106(b).
The condition also requires the installation of a continuous parameter monitoring system (CPMS) to monitor and record operating parameters for determination of source-wide PM10 emissions.
IX.H.11.g.ii This condition limits the H2S content of gases burned within any refinery located within (or affecting) an area of PM2.5 or PM10 nonattainment. The limit is 60
ppm H2S or less as described in 40 CFR 60.102a on a rolling average of 365 days.
Compliance is demonstrated through continuous H2S monitoring, as outlined in 40 CFR 60.107a. Both the limitation and the compliance methodology are based on 40 CFR 60 Subpart Ja.
IX.H.11.g.iii This condition places limits on heat exchangers in VOC service. The condition requires that all heat exchangers in VOC service meet the requirements of 40 CFR 63.654, which requires use of the “Modified El Paso Method” for calculation of VOC emissions. Sources are allowed an option to use another EPA-approved method if allowed by the Director. An exemption is also given for heat exchangers that meet specific criteria that are outlined within the condition language.
IX.H.11.g.iv Leak Detection and Repair Requirements. This condition subjects each source to the requirements of 40 CFR 60 Subpart GGGa – also
known as Enhanced LDAR. The Sustainable Skip Period provisions of that subpart have also been retained.
IX.H.11.g.v This condition establishes new requirements on hydrocarbon flares. First, it states that all hydrocarbon flares are subject to Subpart Ja (40 CFR
60.100a-109a) if not previously subject. Second it requires that each major source refinery either: 1) install a flare gas recovery system designed to limit hydrocarbon flaring from each affected flare during normal operations below the values listed in Subpart Ja (specifically 40 CFR 60.103a(c)), or 2) limit flaring during normal operations to 500,000 scfd or

31
less for each affected flare.
This requirement is based on Subpart Ja, and is designed to incorporate the flare gas recovery requirements of that subpart ahead of the normal implementation schedule. The refineries located in, or impacting, the nonattainment areas are relatively small. As a consequence, the possibility
that they would trigger the flare gas recovery provisions of Subpart Ja in the near term (5-10 years) was very small. Although one of the refineries had elected to install a flare gas recovery system voluntarily, the system only addressed a part of the refinery’s total flaring capacity, and
was not originally designed to Subpart Ja specifications. The first paragraph is already applicable to all refineries, while the second paragraph is applicable as of January 1, 2019 (with a single exception – see BWO’s source specific requirements below). IX.H.11.g.vi This condition requires that vapor control devices be employed during tank degassing operations. Some provisions are made for connecting and disconnecting degassing equipment. Notification must also be made to the Director prior to performing such an operation – unless an emergency situation is
at play. This condition applies to sources beyond just refineries – any owner/operator of any stationary
tank meeting the outlined criteria must fulfill the requirements of this condition. IX.H.11.g.vii No Burning of Liquid Fuel Oil in Stationary Sources – Establishes that no
petroleum refineries in or affecting any PM nonattainment or maintenance area shall be allowed to burn liquid fuel oil in stationary sources except during natural gas curtailments or as specified in the individual subsections of Section IX, Part
H. The use of diesel fuel meeting the specifications of 40 CFR 80.510 in standby or emergency equipment is exempt from this requirement.
This requirement addresses a provision of the original PM10 SIP, which prevented the refineries from burning liquid fuel oil in any capacity – including in emergency or standby equipment. This brings forward the original intent, maintains consistency with the PM10 maintenance plan provisions of IX.H.1.g, and addresses the problem of emergency and standby equipment. IX.H.11.i This condition requires that good combustion practices will be followed. This condition applies to all combustion units and sets a general work practice that good
combustion practices and maintenance will be in line with manufacturer’s recommendations, to ensure equipment stays in good working order.
IX.H.11.j This condition requires additional recordkeeping and reporting requirements specific to the refineries.
This condition applies to the refineries until such time that a Title V operating permit is issued. This condition ensures all applicable recordkeeping and reporting requirements are being followed.
15.1 Monitoring, Recordkeeping and Reporting The new petroleum refinery requirements establish several specific emission limitations. Primarily these limits are monitored continuously – such as the SO2 CEM on the FCCU or the H2S monitor on fuel gas. Where continuous monitoring is used, the requirements of IX.H.11.f

32
apply, which incorporates by reference R307-170, 40 CFR 60.13 and 40 CFR 60, Appendix B – Performance Specifications.
Under R307-170, paragraph 170-8 addresses Recordkeeping, while 170-9 addresses Reporting.
The FCCU PM limit is demonstrated by stack test. This stack test requirement is subject to the requirements of IX.H.11.e. In addition, any source with a direct stack emission limitation is subject to the requirements of R307-165.
These conditions are also subject to the general recordkeeping and reporting requirements of IX.H.11.c. 16.0 New PM2.5 SIP – Big West Oil Specific Requirements The Big West Oil specific conditions in Section IX.H.12 address those limitations and requirements that apply only to the Big West Oil Refinery in particular. The following controls
were determined as necessary for the PM2.5 SIP to satisfy BACT. IX.H.12.b.i This condition establishes NOx emission limits for six combustion units at Big
West Oil. These emission limitations were determined as necessary for BACT. This condition requires
initial and ongoing stack testing to ensure emission limitations and existing control requirements are being met.
IX.H.12.b.iv Alternate Startup and Shutdown Requirements This condition provides alternate limits which apply during periods of startup or shutdown of the
FCCU. This shall be discussed in greater detail in the Startup / Shutdown section below. 16.1 Monitoring, Recordkeeping and Reporting Monitoring for all conditions is addressed through a variety of methods, depending on the emission point in question. Stack testing, CEMs, parameter monitoring – all are viable options, and have been included in the language of IX.H.12.b.i through IX.H.12.b.iii. As appropriate,
these monitoring requirements are complemented by the general provisions of IX.H – specifically 11.e for stack testing, 11.f for CEMs and other continuous monitors, and 11.c for recordkeeping and reporting.
Where necessary, additional monitoring, recordkeeping and/or reporting requirements have been directly included in the language of IX.H.12.b to address specific concerns.
Monitoring recordkeeping and reporting for IX.H.2.b.iv is discussed in under Startup / Shutdown below.
17.0 Startup / Shutdown
As with the other refineries, BWO elected not to deviate from the general refinery requirements with respect to startup and shutdown considerations. However, as a part of the SIP RACT evaluation, BWO did elect to install and operate a redundant caustic scrubber system to work in

33
conjunction with the SRU. This caustic scrubber will work as a backup unit for those periods when the SRU is out of service, effectively serving as startup and shutdown controls for the SRU.
With the addition of this unit, BWO is able to most effectively meet the SRU SO2 emission limit at all times – without additional startup or shutdown requirements on that unit. 18.0 References 1. BWO, PM2.5 SIP Major Point Source RACT Documentation - BWO Refinery
2. BWO - response to information request, dated May 20, 2014 3. UDSHW Contract No. 12601, Work Assignment No. 7, Utah PM2.5 SIP RACT Support - TechLaw Inc. 4. DAQE-AN101220066-15 5. Big West Oil, Flying J Refinery – Submittal of Best Available Control Technology Evaluation, dated April 27, 2017 6. Big West Oil, Flying J Refinery – RE: Big West Oil PM2.5 Amended BACT Evaluation, dated January 31, 2018
7. Utah Division of Air Quality – Final Big West Oil - Flying J Refinery 10122 PM2.5 SIP BACT.xlsx, May 22, 2018
Additional references reviewed during UDAQ BACT research: 3-2-1-2.pdf. (n.d.). Retrieved from
https://www.netl.doe.gov/File%20Library/Research/Coal/energy%20systems/turbines/handbook/3-2-1-2.pdf
5ce1d8028599a7954783ca08d5489afbb8b8.pdf. (n.d.). Retrieved from https://pdfs.semanticscholar.org/9722/5ce1d8028599a7954783ca08d5489afbb8b8.pdf
7FA Gas Turbine DLN 2.6 Gas Fuel Control System.pdf | Servomechanism | Valve.
(n.d.). Retrieved August 30, 2017, from https://www.scribd.com/doc/308100183/7FA-Gas-Turbine-DLN-2-6-Gas-Fuel-Control-System-pdf
2017-Jan6-001.pdf. (n.d.). Retrieved from http://www.aqmd.gov/docs/default-source/Agendas/Governing-Board/2017/2017-Jan6-001.pdf
30464f.pdf. (n.d.). Retrieved from http://permits.air.idem.in.gov/30464f.pdf
Annealing (metallurgy). (2017, December 4). In Wikipedia. Retrieved from https://en.wikipedia.org/w/index.php?title=Annealing_(metallurgy)&oldid=813625590
ASME99-Presentation.pdf. (n.d.). Retrieved from http://www.nsittech.com/images/ASME99-Presentation.pdf
BACT / TBACT Workbook. (n.d.-b). Retrieved from
http://www.baaqmd.gov/permits/permitting-manuals/bact-tbact-workbook
BACT Clearinghouse (Searchable). (n.d.). Retrieved from http://www.valleyair.org/busind/pto/bact/bactLoader.htm
bact_boilheatfurn.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bac
t/bact_boilheatfurn.pdf
bact_bulkgasterm.pdf. (n.d.). Retrieved from

34
https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_bulkgasterm.pdf
bact_cooltow.pdf. (n.d.). Retrieved from
https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_cooltow.pdf
bact_engine.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_engine.pdf
bact_fccu.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_fccu.pdf
bact_flares.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bac
t/bact_flares.pdf
bact_fugitives.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_fugitives.pdf
bact_loading.pdf. (n.d.-a). Retrieved from
https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_loading.pdf
bact_loading.pdf. (n.d.-b). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_loading.pdf
bact_processfurn.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_processfurn.pdf
bact_sru.pdf. (n.d.). Retrieved from
https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bac
t/bact_sru.pdf
bact_turbines.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_turbines.pdf
C302-4-(BMK750-1000-Alt-Derate).pdf. (n.d.). Retrieved from
http://aerco.com/sites/default/files/document/document/C302-4-%28BMK750-1000-Alt-Derate%29.pdf
chapter7.pdf. (n.d.). Retrieved from http://www.valleyair.org/busind/pto/bact/chapter7.pdf
Current Rules. (n.d.). Retrieved from http://www.baaqmd.gov/rules-and-
compliance/current-rules
Development, O. of R. &. (n.d.). ENVIRONMENTAL TECHNOLOGY

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VERIFICATION REPORT, NOX CONTROL TECHNOLOGIES, CATALYTICA COMBUSTION SYSTEMS, INC., XONON FLAMELESS COMBUSTION SYSTEM. Retrieved October 17, 2017, from
https://cfpub.epa.gov/si/si_public_record_Report.cfm?dirEntryID=86205
DPFs and DOCs: The new components at the heart of your Tier 4 engine | Equipment World | Construction Equipment, News and Information | Heavy Construction Equipment. (n.d.). Retrieved December 6, 2017, from https://www.equipmentworld.com/maintenance-24/
Electric Power Monthly - U.S. Energy Information Administration. (n.d.). Retrieved March 7, 2018, from https://www.eia.gov/electricity/monthly/
epm.pdf. (n.d.). Retrieved from https://www.eia.gov/electricity/monthly/current_month/epm.pdf
ffdg.pdf. (n.d.). Retrieved from https://www3.epa.gov/ttncatc1/dir1/ffdg.pdf
fnoxdoc.pdf. (n.d.). Retrieved from https://www3.epa.gov/ttncatc1/dir1/fnoxdoc.pdf
iron. (n.d.). Retrieved from https://www.chemguide.co.uk/inorganic/transition/iron.html
LEC_Appendix 5.1C_BACT Analysis.pdf. (n.d.). Retrieved from http://www.energy.ca.gov/sitingcases/lodi/documents/applicant/afc/Volume_II/LEC_Appendix%205.1C_BACT%20Analysis.pdf
May 2008 BACT cost effectiveness threshold update staff report.pdf. (n.d.). Retrieved from http://www.valleyair.org/busind/pto/bact/May%202008%20BACT%20cost%20effectiveness%20threshold%20update%20staff%20report.pdf
m-g-util-tceq-non-ghg-updated052014.pdf. (n.d.). Retrieved from
https://archive.epa.gov/region6/6pd/air/pd-r/ghg/web/pdf/m-g-util-tceq-non-ghg-updated052014.pdf
nitrogen-oxides | netl.doe.gov. (n.d.). Retrieved from https://www.netl.doe.gov/research/Coal/energy-systems/gasification/gasifipedia/nitrogen-
oxides
NSR Guidance for Boilers. (n.d.). Retrieved from https://www.tceq.texas.gov/permitting/air/guidance/newsourcereview/boilers/nsr_fac_boilheat.html
NSR Guidance for Cooling Towers. (n.d.). Retrieved from
https://www.tceq.texas.gov/permitting/air/guidance/newsourcereview/cooling/nsr_fac_co
oltow.html
NSR Guidance for Equipment Leak Fugitives. (n.d.). Retrieved from https://www.tceq.texas.gov/permitting/air/guidance/newsourcereview/fugitives/nsr_fac_eqfug.html
NSR Guidance for Flares and Vapor Combustors. (n.d.). Retrieved from
https://www.tceq.texas.gov/permitting/air/guidance/newsourcereview/flares/nsr_fac_flares.html

36
NSR Guidance for Fluid Catalytic Cracking Units (FCCU). (n.d.). Retrieved from https://www.tceq.texas.gov/permitting/air/guidance/newsourcereview/cracking/nsr_fac_fccu.html
NSR Guidance for Internal Combustion Engines. (n.d.). Retrieved from https://www.tceq.texas.gov/permitting/air/guidance/newsourcereview/engine/nsr_fac_engine.html
NSR Guidance for Loading Operations. (n.d.). Retrieved from https://www.tceq.texas.gov/permitting/air/guidance/newsourcereview/loading/nsr_fac_lo
ading.html
NSR Guidance for Storage Tanks. (n.d.). Retrieved from https://www.tceq.texas.gov/permitting/air/guidance/newsourcereview/tanks/nsr_fac_tanks.html
NSR Guidance for Sulfur Recovery Units (SRU). (n.d.). Retrieved from
https://www.tceq.texas.gov/permitting/air/guidance/newsourcereview/sulfur/nsr_fac_sru.html
NSR Guidance for Turbines. (n.d.). Retrieved from https://www.tceq.texas.gov/permitting/air/guidance/newsourcereview/turbines/nsr_fac_turb.html
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reactions of aqua ions with ammonia solution. (n.d.). Retrieved December 13, 2017, from https://www.chemguide.co.uk/inorganic/complexions/aquanh3.html#top
sec6.pdf. (n.d.). Retrieved from https://epd.georgia.gov/air/sites/epd.georgia.gov.air/files/related_files/document/sec6.pdf
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pollution-regulations/cost-reports-and-guidance-air-pollution
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37
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PM2.5 SIP Evaluation Report: Big West Oil, LLC Salt Lake City PM2.5 Serious Nonattainment Area Utah Division of Air Quality Major New Source Review Section Appendix A
Big West Oil Refinery Emission Unit Monitoring
Emission Unit Capacity Controls
AO
Conditions[1]SIP Conditions Monitoring Established Emission Limit Basis of Limit
FCC Heater H-101 53.8 MMBtu/hr -- -- NOx Limit (new) Stack Test (new) 0.1 lb/MMBtu Based on SLEIS-reported NOx emission factor (originating from AP-42)
Alkylation Unit Deisobutanizer Reboiler Heater H-301 16.9 MMBtu/hr LNB -- -- -- --
No limit in new requirements - BACT included in small source BACT
document
#2 Crude Heater H-402 30.0 MMBtu/hr LNB -- -- -- --
No limit in new requirements - BACT included in small source BACT
document
Crude Pre-Flash Heater H-403 16.2 MMBtu/hr LNB -- -- -- --
No limit in new requirements - BACT included in small source BACT
document
#1 Crude Heater H-404 27.9 MMBtu/hr ULNB -- -- -- --
No limit in new requirements - BACT included in small source BACT
document
Unifiner Heater H-601 22.6 MMBtu/hr LNB -- -- -- --
No limit in new requirements - BACT included in small source BACT
document
Reformer Heaters H-621, 622, 624 (Common Stack) 50.4 MM Btu/hr LNB -- NOx Limit (new) Stack Test (new) 0.05 lb/MMBtu
Based on SLEIS-reported NOx post control emission factor (originating from
AP-42)
MIDW Heater H-1001 3.8 MMBtu/hr LNB -- -- -- --
No limit in new requirements - BACT included in small source BACT
document
Hydrodesulfurization (HDS) Reboiler H-1002 2.2 MMBtu/hr LNB -- -- -- --
No limit in new requirements - BACT included in small source BACT
document
HDS Heater H-1003 6.6 MMBtu/hr LNB -- -- -- --
No limit in new requirements - BACT included in small source BACT
document
SRU H-1102 3.0 MMBtu/hr Tail Gas Incinerator II.B.2 No CEMs 0.5323 ton/day (24-hour average) NSPS Subpart Ja
Caustic Fuel Gas Scrubber -- -- II.B.5.d & e No CEMs -- Only used during periods of outage of amine unit or SRU
FCC (MSCC) Regenerator Combustion Gas Vent -- Flue Gas Blowback Filter II.B.3 Yes CEMs/Stack Test
40 ppm NOx (365-day rolling average)
60 ppm NOx (7-day rolling average)
25 ppm SO2 (365-day rolling average)
50 ppm SO2 (7-day rolling average)
0.5 lb/1000 lb coke burned PM
NSPS Subpart Ja
#1 Boiler 83.0 MMBtu/hr ULNB -- NOx Limit (new) Stack Test (new) 0.035 lb/MMBtu 2014 Consent Decree
#2 Boiler (removed) ULNB -- -- -- --
#6 Boiler 42.0 MMBtu/hr ULNB -- NOx Limit (new) Stack Test (new) 0.035 lb/MMBtu 2014 Consent Decree
Wabash Boiler 92.3 MMBtu/hr LNB; FGR -- -- --
Non-permanent in place of Boiler #2; NOx emissions monitored monthly via
portable analyzer. Will be removed by 12/31/2026.
Plant Flare #1 (South) -- Flare Gas Minimization II.B.7.c; d SO2 Limit CEMs 162 ppm H2S (3-hour rolling average) NSPS Subpart Ja
Plant Flare #2 (North) (Removed) -- Flare Gas Minimization II.B.7.c; d CEMs 162 ppm H2S (3-hour rolling average) Replaced by the West Flare in September 2020
Plant Flare #3 (West) -- Flare Gas Minimization II.B.4 & II.B.7.c; d SO2 Limit CEMs 162 ppm H2S (3-hour rolling average) NSPS Subpart Ja
Railcar Loading Facility -- VCU -- -- -- --
North Truck Load Rack (NVRU) -- VRU -- No CEMs 10 mg/l gas VOCs
Facility monitors %TOC and compares again 1.1%VOC limit (established
during historical performance testing)
South Truck Load Rack (SVRU) -- VRU -- No CEMs 10 mg/l gas VOCs
Facility monitors %TOC and compares again 1.1%VOC limit (established
during historical performance testing)
Emergency Equipment Varies Varies II.B[3]-- -- -- Equipment subject to various federal and general regulations
Cooling Towers -- Drift Eliminators II.B.7.a -- -- -- --
Fugitives N/A Federal Regulations -- -- -- Federal Regulations Follow federal regulations and LDAR
Tank Farm Storage Tanks Varies Varies II.B[2]-- -- Varies Various requirements based on federal regulation applicability
Amine Unit -- -- II.B.5 Yes CEMs
162 ppm H2S (3-hr rolling average)
60 ppm H2S (365-day rolling average)NSPS Subpart Ja
[1] AO DAQE-AN101220077-22
[2] AO DAQE-AN101220072-19
[3] AO DAQE-AN101220074-19
[4] Applicable federal regulations:
NSPS Subpart A: General Provisions
NSPS Subpart J: Petroleum Refineries
NSPS Subpart Ja: Petroleum Refineries after 5/14/07
NSPS Subpart K: Storage Vessels 6/11/73-5/19/78
NSPS Subpart Ka: Storage Vessels for Petroleum Liquids 5/18/78-7/23/84
NSPS Subpart Kb: Storage Vessels for Petroleum Liquids after 7/23/84
NSPS Subpart GGG: VOC Equipment Leaks in Petroleum Refineries 1/4/83 - 11/7/06
NSPS Subpart GGGa: VOC Equipment Leaks in Petroleum Refineries after 11/7/06
NSPS Subpart QQQ: VOC Emissions from Petroleum Refinery WWTP
NSPS Subpart IIII: Stationary CI Internal Combustion Engines
NESHAP Subpart A: General Provisions
NESHAP Subpart FF: Benzene Waste Operations
MACT Subpart A: General Provisions
MACT Subpart CC: Petroleum Refineries
MACT Subpart ZZZZ: Stationary RICE
MACT Subpart DDDDD: Industrial, Commercial, Institutional Boilers and Heaters
PM2.5 SIP Evaluation Report: Big West Oil, LLC Salt Lake City PM2.5 Serious Nonattainment Area Utah Division of Air Quality Major New Source Review Section Appendix B
Note: All data in this document is in raw, unprocessed form and includes periods of monitor downtime,
quality assurance, calibration, maintenance, out of control periods, potential malfunctioning CEMs data,
and exempt periods
UDAQ 2023 Data Request - UDAQ Analysis and Summary
Amine H2S - Rolling 3-Hour Average & Rolling 365-Day Average
Big West Oil Refinery
Total Data Entries 76,678 Min (ppm) -3 Min (ppm) 1 Min (ppm) -3 Min (ppm) 1
Total Invalid Hour Entries 1,045 Max (ppm) 376 Max (ppm) 376 Max (ppm) 162 Max (ppm) 162
% Total Invalid Hour Entries 1.36% Average (ppm) 15.68 Average (ppm) 17.71 Average (ppm) 15.25 Average (ppm) 17.22
% Un-Matched Data 0.26% Standard Deviation 24.47 Standard Deviation 25.31 Standard Deviation 21.74 Standard Deviation 22.35
%Un-Matched Bad Data 0.00%
Limit (ppm H2S) 162 10th 0 10th 2 10th 0 10th 2
Total Data Entries <= 0 8,642 20th 2 20th 3 20th 2 20th 3
% Total Data Entries <= 0 11.43% 30th 3 30th 5 30th 3 30th 5
Total Data Entries > Limit 125 40th 5 40th 7 40th 5 40th 7
% Total Data Entries > Limit 0.17% 50th 8 50th 9 50th 8 50th 9
60th 11 60th 12 60th 11 60th 12
70th 14 70th 16 70th 14 70th 16
Total Data Entries 2,830 80th 22 80th 25 80th 21 80th 24
Total Invalid Hour Entries 0 90th 41 90th 44 90th 41 90th 44
% Total Invalid Hour Entries 0.00% 97th 80 97th 84 97th 78 97th 82
% Un-Matched Data 2.69% 99th 113.66 99th 116 99th 109 99th 112
%Un-Matched Bad Data 0.00%Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data
Limit (ppm H2S) 60 <10% of Limit 16 56,188 74.29% <10% of Limit 16 47,546 70.97% <10% of Limit 16 56,188 74.41% <10% of Limit 16 47,546 71.11%
Total Data Entries = 0 0 <20% of Limit 32 65,591 86.72% <20% of Limit 32 56,949 85.01% <20% of Limit 32 65,591 86.87% <20% of Limit 32 56,949 85.17%
% Total Data Entries = 0 0.00% <30% of Limit 49 69,945 92.48% <30% of Limit 49 61,303 91.51% <30% of Limit 49 69,945 92.63% <30% of Limit 49 61,303 91.68%
Total Data Entries > Limit 0 <40% of Limit 65 72,140 95.38% <40% of Limit 65 63,498 94.79% <40% of Limit 65 72,140 95.54% <40% of Limit 65 63,498 94.96%
% Total Data Entries > Limit 0.00% <50% of Limit 81 73,462 97.13% <50% of Limit 81 64,820 96.76% <50% of Limit 81 73,462 97.29% <50% of Limit 81 64,820 96.94%
<60% of Limit 97 74,317 98.26% <60% of Limit 97 65,675 98.04% <60% of Limit 97 74,317 98.42% <60% of Limit 97 65,675 98.22%
<70% of Limit 113 74,877 99.00% <70% of Limit 113 66,235 98.87% <70% of Limit 113 74,877 99.16% <70% of Limit 113 66,235 99.06%
<80% of Limit 130 75,258 99.50% <80% of Limit 130 66,616 99.44% <80% of Limit 130 75,258 99.67% <80% of Limit 130 66,616 99.63%
<90% of Limit 146 75,437 99.74% <90% of Limit 146 66,795 99.71% <90% of Limit 146 75,437 99.91% <90% of Limit 146 66,795 99.89%
<=100% of Limit 162 75,508 99.83% <=100% of Limit 162 66,866 99.81% <=100% of Limit 162 75,508 100.00% <=100% of Limit 162 66,866 100.00%
Min (ppm) 5
Max (ppm) 29
Average (ppm) 14.69
Standard Deviation 4.77
10th 9
20th 11
30th 12
40th 13
50th 14
60th 15
70th 16
80th 17
90th 22
97th 26
99th 29
Percentage of Limit Value (ppm) Total Data Points % of Total Data
<10% of Limit 6 39 1.38%
<20% of Limit 12 937 33.11%
<30% of Limit 18 2,351 83.07%
<40% of Limit 24 2,694 95.19%
<50% of Limit 30 2,830 100.00%
<60% of Limit 36 2,830 100.00%
<70% of Limit 42 2,830 100.00%
<80% of Limit 48 2,830 100.00%
<90% of Limit 54 2,830 100.00%
<=100% of Limit 60 2,830 100.00%
Data Verification - Hourly/3-Hr Average
Data Verification - Daily/365-Day Average
Data Analysis - All Data Included (3-Hr Average) Data Analysis - Excluding All Data <= 0 (3-Hr Average)
Data Analysis - All Data Included (365-Day Averages)
Percentiles (ppm):
Data Analysis - Excluding All Data > 162 (3-Hr Average) Data Analysis - Excluding All Data = 0 and > 162 (3-Hr Average)
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
UDAQ 2023 Data Request - UDAQ Analysis and Summary
MSCC SO2 & NOx - Rolling 7-Day Averages
Big West Oil Refinery
Total Data Entries 3,189 Min (ppm) -452 Min (ppm) 1 Min (ppm) -452 Min (ppm) 1
Total Invalid Day Entries 192 Max (ppm) 191 Max (ppm) 191 Max (ppm) 40 Max (ppm) 40
% Total Invalid Day Entries 6.02% Average (ppm) 19.64 Average (ppm) 20.15 Average (ppm) 19.18 Average (ppm) 19.69
% Un-Matched Data 12.76% Standard Deviation 13.37 Standard Deviation 9.48 Standard Deviation 11.12 Standard Deviation 5.84
%Un-Matched Bad Data 0.00%
Limit (ppm SO2) 50 10th 13 10th 13 10th 13 10th 13
Total Data Entries <= 0 29 20th 15 20th 15 20th 15 20th 15
% Total Data Entries <= 0 0.97% 30th 16 30th 16 30th 16 30th 16
Total Data Entries > Limit 15 40th 18 40th 18 40th 18 40th 18
% Total Data Entries > Limit 0.50% 50th 19 50th 19 50th 19 50th 19
60th 20.8 60th 21 60th 20 60th 21
70th 22 70th 22 70th 22 70th 22
Total Data Entries 3,189 80th 24 80th 24 80th 24 80th 24
Total Invalid Day Entries 192 90th 28 90th 28 90th 28 90th 28
% Total Invalid Day Entries 6.02% 97th 34 97th 34 97th 33 97th 33
% Un-Matched Data 12.73% 99th 37 99th 37 99th 35 99th 35
%Un-Matched Bad Data 0.00%Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data
Limit (ppm NOx) 60 <10% of Limit 5 39 1.30% <10% of Limit 5 10 0.34% <10% of Limit 5 39 1.31% <10% of Limit 5 10 0.34%
Total Data Entries <= 0 25 <20% of Limit 10 154 5.14% <20% of Limit 10 125 4.21% <20% of Limit 10 154 5.16% <20% of Limit 10 125 4.23%
% Total Data Entries <= 0 0.83% <30% of Limit 15 716 23.89% <30% of Limit 15 687 23.15% <30% of Limit 15 716 24.01% <30% of Limit 15 687 23.26%
Total Data Entries > Limit 40 <40% of Limit 20 1,798 59.99% <40% of Limit 20 1,769 59.60% <40% of Limit 20 1,798 60.30% <40% of Limit 20 1,769 59.91%
% Total Data Entries > Limit 1.33% <50% of Limit 25 2,510 83.75% <50% of Limit 25 2,481 83.59% <50% of Limit 25 2,510 84.17% <50% of Limit 25 2,481 84.02%
<60% of Limit 30 2,854 95.23% <60% of Limit 30 2,825 95.18% <60% of Limit 30 2,854 95.71% <60% of Limit 30 2,825 95.67%
<70% of Limit 35 2,958 98.70% <70% of Limit 35 2,929 98.69% <70% of Limit 35 2,958 99.20% <70% of Limit 35 2,929 99.19%
<80% of Limit 40 2,982 99.50% <80% of Limit 40 2,953 99.49% <80% of Limit 40 2,982 100.00% <80% of Limit 40 2,953 100.00%
<90% of Limit 45 2,982 99.50% <90% of Limit 45 2,953 99.49% <90% of Limit 45 2,982 100.00% <90% of Limit 45 2,953 100.00%
<=100% of Limit 50 2,982 99.50% <=100% of Limit 50 2,953 99.49% <=100% of Limit 50 2,982 100.00% <=100% of Limit 50 2,953 100.00%
Min (ppm) -229 Min (ppm) 15 Min (ppm) -229 Min (ppm) 15
Max (ppm) 139 Max (ppm) 139 Max (ppm) 60 Max (ppm) 60
Average (ppm) 32.27 Average (ppm) 33.17 Average (ppm) 31.57 Average (ppm) 32.47
Standard Deviation 14.32 Standard Deviation 7.64 Standard Deviation 12.88 Standard Deviation 4.26
10th 28 10th 28 10th 28 10th 28
20th 29 20th 29 20th 29 20th 29
30th 30 30th 30 30th 30 30th 30
40th 31 40th 31 40th 31 40th 31
50th 32 50th 32 50th 32 50th 32
60th 33 60th 33 60th 33 60th 33
70th 34 70th 34 70th 34 70th 34
80th 35 80th 35 80th 35 80th 35
90th 37 90th 37 90th 37 90th 37
97th 43.06 97th 43.81 97th 40 97th 40
99th 73.02 99th 73.27 99th 49 99th 49
Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data
<10% of Limit 6 25 0.83% <10% of Limit 6 0 0.00% <10% of Limit 6 25 0.85% <10% of Limit 6 0 0.00%
<20% of Limit 12 25 0.83% <20% of Limit 12 0 0.00% <20% of Limit 12 25 0.85% <20% of Limit 12 0 0.00%
<30% of Limit 18 29 0.97% <30% of Limit 18 4 0.13% <30% of Limit 18 29 0.98% <30% of Limit 18 4 0.14%
<40% of Limit 24 53 1.77% <40% of Limit 24 28 0.94% <40% of Limit 24 53 1.79% <40% of Limit 24 28 0.95%
<50% of Limit 30 929 31.00% <50% of Limit 30 904 30.42% <50% of Limit 30 929 31.42% <50% of Limit 30 904 30.83%
<60% of Limit 36 2,613 87.19% <60% of Limit 36 2,588 87.08% <60% of Limit 36 2,613 88.37% <60% of Limit 36 2,588 88.27%
<70% of Limit 42 2,897 96.66% <70% of Limit 42 2,872 96.64% <70% of Limit 42 2,897 97.97% <70% of Limit 42 2,872 97.95%
<80% of Limit 48 2,927 97.66% <80% of Limit 48 2,902 97.64% <80% of Limit 48 2,927 98.99% <80% of Limit 48 2,902 98.98%
<90% of Limit 54 2,940 98.10% <90% of Limit 54 2,915 98.08% <90% of Limit 54 2,940 99.43% <90% of Limit 54 2,915 99.42%
<=100% of Limit 60 2,957 98.67% <=100% of Limit 60 2,932 98.65% <=100% of Limit 60 2,957 100.00% <=100% of Limit 60 2,932 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification - SO2 Data Analysis - All Data Included (SO2) Data Analysis - Excluding All Data <= 0 (SO2) Data Analysis - Excluding All Data > 50 (SO2) Data Analysis - Excluding All Data <= 0 and > 50 (SO2)
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification - NOx
Data Analysis - All Data Included (NOx) Data Analysis - Excluding All Data <= 0 (NOx) Data Analysis - Excluding All Data > 60 (NOx) Data Analysis - Excluding All Data <= 0 and > 60 (NOx)
UDAQ 2023 Data Request - UDAQ Analysis and Summary
North Flare H2S - Rolling 3-Hour Average
Big West Oil Refinery
Total Data Entries 42,412 Min (ppm) 0 Min (ppm) 1 Min (ppm) 0 Min (ppm) 1
Total Invalid Hour Entries 1,155 Max (ppm) 9,925 Max (ppm) 9,925 Max (ppm) 162 Max (ppm) 162
% Total Invalid Hour Entries 2.72% Average (ppm) 37.85 Average (ppm) 40.47 Average (ppm) 30.52 Average (ppm) 32.66
% Un-Matched Data 11.61% Standard Deviation 162.44 Standard Deviation 167.67 Standard Deviation 25.73 Standard Deviation 25.27
%Un-Matched Bad Data 0.00%
Limit (ppm H2S) 162 10th 2 10th 7 10th 2 10th 7
Total Data Entries = 0 2,676 20th 10 20th 13 20th 10 20th 13
% Total Data Entries = 0 6.49% 30th 15 30th 16 30th 15 30th 16
Total Data Entries > Limit 416 40th 19 40th 20 40th 19 40th 20
% Total Data Entries > Limit 1.01% 50th 23 50th 25 50th 23 50th 25
60th 30 60th 32 60th 29 60th 31
70th 39 70th 42 70th 39 70th 41
80th 52 80th 54 80th 51 80th 53
90th 69 90th 70 90th 67 90th 68
97th 98 97th 100 97th 91 97th 92
99th 164 99th 171 99th 112 99th 113
Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data
<10% of Limit 16 14,334 34.74% <10% of Limit 16 11,658 30.22% <10% of Limit 16 14,334 35.10% <10% of Limit 16 11,658 30.55%
<20% of Limit 32 26,098 63.26% <20% of Limit 32 23,422 60.71% <20% of Limit 32 26,098 63.90% <20% of Limit 32 23,422 61.37%
<30% of Limit 49 32,201 78.05% <30% of Limit 49 29,525 76.53% <30% of Limit 49 32,201 78.84% <30% of Limit 49 29,525 77.36%
<40% of Limit 65 36,506 88.48% <40% of Limit 65 33,830 87.69% <40% of Limit 65 36,506 89.39% <40% of Limit 65 33,830 88.64%
<50% of Limit 81 38,882 94.24% <50% of Limit 81 36,206 93.84% <50% of Limit 81 38,882 95.20% <50% of Limit 81 36,206 94.87%
<60% of Limit 97 39,979 96.90% <60% of Limit 97 37,303 96.69% <60% of Limit 97 39,979 97.89% <60% of Limit 97 37,303 97.74%
<70% of Limit 113 40,464 98.08% <70% of Limit 113 37,788 97.94% <70% of Limit 113 40,464 99.08% <70% of Limit 113 37,788 99.01%
<80% of Limit 130 40,689 98.62% <80% of Limit 130 38,013 98.53% <80% of Limit 130 40,689 99.63% <80% of Limit 130 38,013 99.60%
<90% of Limit 146 40,778 98.84% <90% of Limit 146 38,102 98.76% <90% of Limit 146 40,778 99.85% <90% of Limit 146 38,102 99.83%
<=100% of Limit 162 40,841 98.99% <=100% of Limit 162 38,165 98.92% <=100% of Limit 162 40,841 100.00% <=100% of Limit 162 38,165 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data = 0 Data Analysis - Excluding All Data > 162 Data Analysis - Excluding All Data = 0 and > 162
UDAQ 2023 Data Request - UDAQ Analysis and Summary
West Flare H2S - Rolling 3-Hour Average
Big West Oil Refinery
Total Data Entries 26,293 Min (ppm) 0 Min (ppm) 1 Min (ppm) 0 Min (ppm) 1
Total Invalid Hour Entries 1,793 Max (ppm) 5,965 Max (ppm) 5,965 Max (ppm) 162 Max (ppm) 162
% Total Invalid Hour Entries 6.82% Average (ppm) 33.13 Average (ppm) 33.24 Average (ppm) 25.84 Average (ppm) 25.93
% Un-Matched Data 11.43% Standard Deviation 102.68 Standard Deviation 102.84 Standard Deviation 29.83 Standard Deviation 29.84
%Un-Matched Bad Data 0.00%
Limit (ppm H2S) 162 10th 4 10th 4 10th 4 10th 4
Total Data Entries = 0 82 20th 6 20th 6 20th 6 20th 6
% Total Data Entries = 0 0.33% 30th 8 30th 8 30th 8 30th 8
Total Data Entries > Limit 362 40th 12 40th 12 40th 11 40th 12
% Total Data Entries > Limit 1.48% 50th 16 50th 16 50th 16 50th 16
60th 21 60th 21 60th 20 60th 20
70th 27 70th 27 70th 26 70th 26
80th 37 80th 37 80th 35 80th 36
90th 77 90th 77 90th 67 90th 67
97th 128 97th 128 97th 114 97th 114
99th 196 99th 196 99th 135 99th 135
Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data
<10% of Limit 16 12,553 51.24% <10% of Limit 16 12,471 51.07% <10% of Limit 16 12,553 52.01% <10% of Limit 16 12,471 51.84%
<20% of Limit 32 18,675 76.22% <20% of Limit 32 18,593 76.14% <20% of Limit 32 18,675 77.37% <20% of Limit 32 18,593 77.29%
<30% of Limit 49 20,852 85.11% <30% of Limit 49 20,770 85.06% <30% of Limit 49 20,852 86.39% <30% of Limit 49 20,770 86.34%
<40% of Limit 65 21,676 88.47% <40% of Limit 65 21,594 88.43% <40% of Limit 65 21,676 89.80% <40% of Limit 65 21,594 89.77%
<50% of Limit 81 22,202 90.62% <50% of Limit 81 22,120 90.59% <50% of Limit 81 22,202 91.98% <50% of Limit 81 22,120 91.95%
<60% of Limit 97 22,809 93.10% <60% of Limit 97 22,727 93.07% <60% of Limit 97 22,809 94.49% <60% of Limit 97 22,727 94.48%
<70% of Limit 113 23,402 95.52% <70% of Limit 113 23,320 95.50% <70% of Limit 113 23,402 96.95% <70% of Limit 113 23,320 96.94%
<80% of Limit 130 23,823 97.24% <80% of Limit 130 23,741 97.23% <80% of Limit 130 23,823 98.70% <80% of Limit 130 23,741 98.69%
<90% of Limit 146 24,022 98.05% <90% of Limit 146 23,940 98.04% <90% of Limit 146 24,022 99.52% <90% of Limit 146 23,940 99.52%
<=100% of Limit 162 24,138 98.52% <=100% of Limit 162 24,056 98.52% <=100% of Limit 162 24,138 100.00% <=100% of Limit 162 24,056 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data = 0 Data Analysis - Excluding All Data > 162 Data Analysis - Excluding All Data = 0 and > 162
UDAQ 2023 Data Request - UDAQ Analysis and Summary
South Flare H2S - Rolling 3-Hour Average
Big West Oil Refinery
Total Data Entries 69,382 Min (ppm) 0 Min (ppm) 1 Min (ppm) 0 Min (ppm) 1
Total Invalid Hour Entries 2,327 Max (ppm) 6,994 Max (ppm) 6,994 Max (ppm) 162 Max (ppm) 162
% Total Invalid Hour Entries 3.35% Average (ppm) 33.34 Average (ppm) 33.79 Average (ppm) 19.22 Average (ppm) 19.49
% Un-Matched Data 12.06% Standard Deviation 164.55 Standard Deviation 165.60 Standard Deviation 19.70 Standard Deviation 19.70
%Un-Matched Bad Data 0.00%
Limit (ppm H2S) 162 10th 3 10th 4 10th 3 10th 4
Total Data Entries = 0 883 20th 6 20th 6 20th 6 20th 6
% Total Data Entries = 0 1.32% 30th 8 30th 8 30th 8 30th 8
Total Data Entries > Limit 1,196 40th 10 40th 11 40th 10 40th 11
% Total Data Entries > Limit 1.78% 50th 14 50th 14 50th 13 50th 14
60th 17 60th 18 60th 17 60th 17
70th 22 70th 23 70th 22 70th 22
80th 30 80th 30 80th 29 80th 29
90th 45 90th 45 90th 42 90th 42
97th 94 97th 95 97th 69 97th 69
99th 378 99th 389.54 99th 101 99th 101
Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data
<10% of Limit 16 38,842 57.93% <10% of Limit 16 37,959 57.36% <10% of Limit 16 38,842 58.98% <10% of Limit 16 37,959 58.42%
<20% of Limit 32 55,130 82.22% <20% of Limit 32 54,247 81.98% <20% of Limit 32 55,130 83.71% <20% of Limit 32 54,247 83.49%
<30% of Limit 49 61,379 91.54% <30% of Limit 49 60,496 91.42% <30% of Limit 49 61,379 93.20% <30% of Limit 49 60,496 93.11%
<40% of Limit 65 63,568 94.80% <40% of Limit 65 62,685 94.73% <40% of Limit 65 63,568 96.52% <40% of Limit 65 62,685 96.47%
<50% of Limit 81 64,588 96.32% <50% of Limit 81 63,705 96.27% <50% of Limit 81 64,588 98.07% <50% of Limit 81 63,705 98.04%
<60% of Limit 97 65,132 97.13% <60% of Limit 97 64,249 97.09% <60% of Limit 97 65,132 98.90% <60% of Limit 97 64,249 98.88%
<70% of Limit 113 65,420 97.56% <70% of Limit 113 64,537 97.53% <70% of Limit 113 65,420 99.33% <70% of Limit 113 64,537 99.32%
<80% of Limit 130 65,632 97.88% <80% of Limit 130 64,749 97.85% <80% of Limit 130 65,632 99.66% <80% of Limit 130 64,749 99.65%
<90% of Limit 146 65,760 98.07% <90% of Limit 146 64,877 98.04% <90% of Limit 146 65,760 99.85% <90% of Limit 146 64,877 99.85%
<=100% of Limit 162 65,859 98.22% <=100% of Limit 162 64,976 98.19% <=100% of Limit 162 65,859 100.00% <=100% of Limit 162 64,976 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data = 0 Data Analysis - Excluding All Data > 162 Data Analysis - Excluding All Data = 0 and > 162
UDAQ 2023 Data Request - UDAQ Analysis and Summary
NVRU VOC - Rolling 6-Hour Average
Big West Oil Refinery
Total Data Entries 43,825 Min (ppm) 0 Min (ppm) 0.1 Min (ppm) 0 Min (ppm) 0.1
Total Invalid Hour Entries 745 Max (ppm) 1 Max (ppm) 1 Max (ppm) 1.4 Max (ppm) 1.4
% Total Invalid Hour Entries 1.70% Average (ppm) 0.10 Average (ppm) 0.11 Average (ppm) 0.10 Average (ppm) 0.11
% Un-Matched Data 8.94% Standard Deviation 0.05 Standard Deviation 0.04 Standard Deviation 0.05 Standard Deviation 0.04
%Un-Matched Bad Data 0.00%
Limit (ppm VOC) 10 10th 0.0 10th 0.1 10th 0.0 10th 0.1
Total Data Entries = 0 5,677 20th 0.1 20th 0.1 20th 0.1 20th 0.1
% Total Data Entries = 0 13.18% 30th 0.1 30th 0.1 30th 0.1 30th 0.1
Total Data Entries > Limit 0 40th 0.1 40th 0.1 40th 0.1 40th 0.1
% Total Data Entries > Limit 0.00% 50th 0.1 50th 0.1 50th 0.1 50th 0.1
60th 0.1 60th 0.1 60th 0.1 60th 0.1
70th 0.1 70th 0.1 70th 0.1 70th 0.1
80th 0.1 80th 0.1 80th 0.1 80th 0.1
90th 0.1 90th 0.2 90th 0.1 90th 0.2
97th 0.2 97th 0.2 97th 0.2 97th 0.2
99th 0.2 99th 0.2 99th 0.2 99th 0.2
Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data
<10% of Limit 1 43,075 99.99% <10% of Limit 1 37,398 99.99% <10% of Limit 1 43,075 99.99% <10% of Limit 1 37,398 99.99%
<20% of Limit 2 43,080 100.00% <20% of Limit 2 37,403 100.00% <20% of Limit 2 43,080 100.00% <20% of Limit 2 37,403 100.00%
<30% of Limit 3 43,080 100.00% <30% of Limit 3 37,403 100.00% <30% of Limit 3 43,080 100.00% <30% of Limit 3 37,403 100.00%
<40% of Limit 4 43,080 100.00% <40% of Limit 4 37,403 100.00% <40% of Limit 4 43,080 100.00% <40% of Limit 4 37,403 100.00%
<50% of Limit 5 43,080 100.00% <50% of Limit 5 37,403 100.00% <50% of Limit 5 43,080 100.00% <50% of Limit 5 37,403 100.00%
<60% of Limit 6 43,080 100.00% <60% of Limit 6 37,403 100.00% <60% of Limit 6 43,080 100.00% <60% of Limit 6 37,403 100.00%
<70% of Limit 7 43,080 100.00% <70% of Limit 7 37,403 100.00% <70% of Limit 7 43,080 100.00% <70% of Limit 7 37,403 100.00%
<80% of Limit 8 43,080 100.00% <80% of Limit 8 37,403 100.00% <80% of Limit 8 43,080 100.00% <80% of Limit 8 37,403 100.00%
<90% of Limit 9 43,080 100.00% <90% of Limit 9 37,403 100.00% <90% of Limit 9 43,080 100.00% <90% of Limit 9 37,403 100.00%
<=100% of Limit 10 43,080 100.00% <=100% of Limit 10 37,403 100.00% <=100% of Limit 10 43,080 100.00% <=100% of Limit 10 37,403 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data = 0 Data Analysis - Excluding All Data > 10 Data Analysis - Excluding All Data = 0 and > 10
UDAQ 2023 Data Request - UDAQ Analysis and Summary
SVRU VOC - Rolling 6-Hour Average
Big West Oil Refinery
Total Data Entries 43,819 Min (ppm) 0 Min (ppm) 0.1 Min (ppm) 0 Min (ppm) 0.1
Total Invalid Hour Entries 34,301 Max (ppm) 1.1 Max (ppm) 1 Max (ppm) 1.1 Max (ppm) 1.1
% Total Invalid Hour Entries 78.28% Average (ppm) 0.04 Average (ppm) 0.27 Average (ppm) 0.04 Average (ppm) 0.27
% Un-Matched Data 0.46% Standard Deviation 0.13 Standard Deviation 0.23 Standard Deviation 0.13 Standard Deviation 0.23
%Un-Matched Bad Data 0.00%
Limit (ppm VOC) 10 10th 0.0 10th 0.1 10th 0.0 10th 0.1
Total Data Entries = 0 8,082 20th 0.0 20th 0.1 20th 0.0 20th 0.1
% Total Data Entries = 0 84.91% 30th 0.0 30th 0.1 30th 0.0 30th 0.1
Total Data Entries > Limit 0 40th 0.0 40th 0.1 40th 0.0 40th 0.1
% Total Data Entries > Limit 0.00% 50th 0.0 50th 0.2 50th 0.0 50th 0.2
60th 0.0 60th 0.2 60th 0.0 60th 0.2
70th 0.0 70th 0.3 70th 0.0 70th 0.3
80th 0.0 80th 0.4 80th 0.0 80th 0.4
90th 0.1 90th 0.6 90th 0.1 90th 0.6
97th 0.4 97th 0.9 97th 0.4 97th 0.9
99th 0.7 99th 1.0 99th 0.7 99th 1.0
Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data Percentage of Limit Value (ppm) Total Data Points % of Total Data
<10% of Limit 1 9,507 99.88% <10% of Limit 1 1,425 99.23% <10% of Limit 1 9,507 99.88% <10% of Limit 1 1,425 99.23%
<20% of Limit 2 9,518 100.00% <20% of Limit 2 1,436 100.00% <20% of Limit 2 9,518 100.00% <20% of Limit 2 1,436 100.00%
<30% of Limit 3 9,518 100.00% <30% of Limit 3 1,436 100.00% <30% of Limit 3 9,518 100.00% <30% of Limit 3 1,436 100.00%
<40% of Limit 4 9,518 100.00% <40% of Limit 4 1,436 100.00% <40% of Limit 4 9,518 100.00% <40% of Limit 4 1,436 100.00%
<50% of Limit 5 9,518 100.00% <50% of Limit 5 1,436 100.00% <50% of Limit 5 9,518 100.00% <50% of Limit 5 1,436 100.00%
<60% of Limit 6 9,518 100.00% <60% of Limit 6 1,436 100.00% <60% of Limit 6 9,518 100.00% <60% of Limit 6 1,436 100.00%
<70% of Limit 7 9,518 100.00% <70% of Limit 7 1,436 100.00% <70% of Limit 7 9,518 100.00% <70% of Limit 7 1,436 100.00%
<80% of Limit 8 9,518 100.00% <80% of Limit 8 1,436 100.00% <80% of Limit 8 9,518 100.00% <80% of Limit 8 1,436 100.00%
<90% of Limit 9 9,518 100.00% <90% of Limit 9 1,436 100.00% <90% of Limit 9 9,518 100.00% <90% of Limit 9 1,436 100.00%
<=100% of Limit 10 9,518 100.00% <=100% of Limit 10 1,436 100.00% <=100% of Limit 10 9,518 100.00% <=100% of Limit 10 1,436 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data = 0 Data Analysis - Excluding All Data > 10 Data Analysis - Excluding All Data = 0 and > 10
UDAQ 2023 Data Request - UDAQ Analysis and Summary
SRU Incinerator SO2 Emissions Daily Rate
Big West Oil Refinery
Total Data Entries 3,195 Min (lbs) 0 Min (lbs) 1 Min (lbs) 0 Min (lbs) 1
Total Invalid Hour Entries 23 Max (lbs) 654.0 Max (lbs) 654 Max (lbs) 654.0 Max (lbs) 654
% Total Invalid Hour Entries 0.72% Average (lbs) 176.86 Average (lbs) 178.04 Average (lbs) 176.86 Average (lbs) 178.04
% Un-Matched Data 11.08% Standard Deviation 60.70 Standard Deviation 59.16 Standard Deviation 60.70 Standard Deviation 59.16
%Un-Matched Bad Data 4.38%
Limit (lbs SO2/day) 1,065 10th 104.3 10th 108.0 10th 104.3 10th 108.0
Total Data Entries = 0 20 20th 133.0 20th 134.0 20th 133.0 20th 134.0
% Total Data Entries = 0 0.63% 30th 150.0 30th 151 30th 150.0 30th 151
Total Data Entries > Limit 0 40th 163.0 40th 164 40th 163.0 40th 164
% Total Data Entries > Limit 0.00% 50th 175.5 50th 176 50th 175.5 50th 176
60th 190.0 60th 191 60th 190.0 60th 191
70th 207.0 70th 207 70th 207.0 70th 207
80th 223.0 80th 223 80th 223.0 80th 223
90th 244.0 90th 244 90th 244.0 90th 244
97th 288.0 97th 288 97th 288.0 97th 288
99th 338.0 99th 338.6 99th 338.0 99th 338.6
Percentage of Limit Value (lbs) Total Data Points % of Total Data Percentage of Limit Value (lbs) Total Data Points % of Total Data Percentage of Limit Value (lbs) Total Data Points % of Total Data Percentage of Limit Value (lbs) Total Data Points % of Total Data
<10% of Limit 107 319 10.52% <10% of Limit 107 299 9.93% <10% of Limit 107 319 10.52% <10% of Limit 107 299 9.93%
<20% of Limit 213 2,263 74.64% <20% of Limit 213 2,243 74.47% <20% of Limit 213 2,263 74.64% <20% of Limit 213 2,243 74.47%
<30% of Limit 320 2,993 98.71% <30% of Limit 320 2,973 98.71% <30% of Limit 320 2,993 98.71% <30% of Limit 320 2,973 98.71%
<40% of Limit 426 3,027 99.84% <40% of Limit 426 3,007 99.83% <40% of Limit 426 3,027 99.84% <40% of Limit 426 3,007 99.83%
<50% of Limit 533 3,029 99.90% <50% of Limit 533 3,009 99.90% <50% of Limit 533 3,029 99.90% <50% of Limit 533 3,009 99.90%
<60% of Limit 639 3,031 99.97% <60% of Limit 639 3,011 99.97% <60% of Limit 639 3,031 99.97% <60% of Limit 639 3,011 99.97%
<70% of Limit 746 3,032 100.00% <70% of Limit 746 3,012 100.00% <70% of Limit 746 3,032 100.00% <70% of Limit 746 3,012 100.00%
<80% of Limit 852 3,032 100.00% <80% of Limit 852 3,012 100.00% <80% of Limit 852 3,032 100.00% <80% of Limit 852 3,012 100.00%
<90% of Limit 959 3,032 100.00% <90% of Limit 959 3,012 100.00% <90% of Limit 959 3,032 100.00% <90% of Limit 959 3,012 100.00%
<=100% of Limit 1065 3,032 100.00% <=100% of Limit 1065 3,012 100.00% <=100% of Limit 1065 3,032 100.00% <=100% of Limit 1065 3,012 100.00%
Data Analysis - Excluding All Data = 0 and >1,065 lbs
Percentiles (lbs):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data = 0
Percentiles (lbs): Percentiles (lbs):
Data Analysis - Excluding All Date > 1,065 lbs
Percentiles (lbs):
PM2.5 SIP Evaluation Report: Big West Oil, LLC Salt Lake City PM2.5 Serious Nonattainment Area Utah Division of Air Quality Major New Source Review Section Appendix C
Big West Oil Emission Calculations - Check
Gas-Fired Combustion Units with proposed limits
1,020
8,760
7.60
0.01
Emission Unit
Heat Input
Capacity
(MMBtu/hr)
Proposed
NOx Limit
(lb/MMBtu)
2017
Hours of Operation
(hrs/yr)
NOx
Emissions
(tons/yr)
2017 NOx
Inventory
(tons/yr)
PM2.5
Emissions
(tons/yr)
2017 PM2.5
Inventory
(tons/yr)
SO2
Emissions
(tons/yr)
2017 SO2
Inventory
(tons/yr)
FCC Heater H-101 53.8 0.10 8,184 23.56 3.60 1.76 0.27 2.36 0.07
Reformer Heaters H-621, 622, 624 50.4 0.05 8,784 33.11 24.83 1.64 3.77 2.21 0.92
#1 Boiler 83.0 0.035 4,992 12.72 5.34 2.71 1.45 3.64 0.36
#6 Boiler 42.0 0.035 8,784 6.44 2.88 1.37 0.78 1.84 0.21
75.84 36.65 7.48 6.27 10.04 1.56
[1] AP-42 Section 1.4.1
[2] AP-42 Section 1.4
[3] Based on H2S limit from NSPS Subpart Ja 365-day average at 0% O2: 60 ppm H2S, assuming full conversion to SO2
Source-wide PM2.5 limit adopted by AQB July 1, 2018: 72.5 tons/yr
Source-wide NOx Limit adopted by AQB July 1, 2018: 195.0 tons/yr
Source-wide SO2 Limit adopted by AQB July 1, 2018: 140.0 tons/yr
Total Emissions
Assumed: Refinery gas is equivalent to natural gas
Heating Value of Refinery Gas (Btu/scf)[1]
Maximum Hour of Operation (hrs/yr)
PM2.5 Emission Factor (lb/MMscf)[2]
SO2 Emission Factor (lb/MMBtu)[3]