DAQ-2025-001204

PM2.5 SIP Evaluation Report: HF Sinclair Woods Cross Refinery (Previously Holly Refining & Marketing Company – Woods Cross, LLC – Holly Refinery) 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 HF Sinclair Woods Cross Refining LLC – Woods Cross 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 Nonattainment Area. This document specifically serves as an evaluation of the HF Sinclair Woods Cross 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. HF Sinclair 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: HF Sinclair Woods Cross Refinery Address: 393 South 800 West, Woods Cross, Utah, Davis County Owner/Operator: HF Sinclair Woods Cross Refining LLC
UTM coordinates: 4,526,227 m Northing, 424,000 m Easting, Zone 12
1.2 Facility Process Summary The HF Sinclair Refinery (HF Sinclair) is a petroleum refinery capable of processing 60,000
barrels per day of crude oil, primarily heavier black wax and yellow wax crudes from eastern Utah. The source consists of two FCCUs, both controlled with wet gas scrubbers. A single sulfur recovery unit controls the sulfur content of the fuel gas. The source also has the usual assorted
heaters, boilers, cooling towers, storage tanks, flares, and related fugitive emissions – primarily VOCs.
The two FCCUs are both complete burn units without cokers. There are no cogeneration units present. The refinery currently operates without flare gas recovery. 1.3 Facility Criteria Air Pollutant Emissions Sources The following is a listing of the main emitting units from the HF Sinclair Refinery:
• Fluid Catalytic Cracking Unit (FCCU) #1, controlled with WGS
• FCC Feed Heater, 68.4 MMBtu/hr process furnace, fired on plant gas, restricted to 39.9

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MMBtu/hr, equipped with low NOx burners (LNB)
• Reformer charge and reheater furnace/waste heat boiler, 54.7 MMBtu/hr process furnace, fired on plant gas
• Prefractionator Reboiler Heater, 12.0 MMBtu/hr process furnace, fired on plant gas
• Reformer Reheat Furnace, 37.7 MMBtu/hr process furnace, fired on plant gas
• HF Alkylation Regeneration Furnace, 4.4 MMBtu/hr process furnace, fired on plant gas
• HF Alkylation Depropanizer Reboiler, 33.3 MMBtu/hr process furnace, fired on plant gas
• Crude Furnace #1, 99.0 MMBtu/hr process furnace, fired on plant gas, equipped with next generation ultra-low NOx burner (NGULNB)
• Distillate Hydrosulfurization (DHDS) Unit Reactor Charge Heater, 8.1 MMBtu/hr process furnace, fired on plant gas
• DHDS Stripper Reboiler, 4.1 MMBtu/hr process furnace, fired on plant gas
• Asphalt Mix Heater, 13.2 MMBtu/hr process furnace, fired on plant gas
• Straight Run Gas Plant (SRGP) Depentanizer Reboiler, 24.2 MMBtu/hr process furnace, fired on plant gas
• Naphtha Hydrodesulphurization (NHDS) Unit Reactor Charge Furnace, 50.2 MMBtu/hr process furnace, fired on plant gas, equipped with NGULNB
• Isomerization Reactor Feed Furnace 6.5 MMBtu/hr process furnace, fired on plant gas
• Sulfur Recovery (SRU) with Tailgas Incinerator
• Distillate Hydrodesulfurization Treatment (DHT) Reactor Charge Heater, 23.0 MMBtu/hr process furnace, fired on plant gas, equipped with LNB
• Fractionator Charge Heater, 47.0 MMBtu/hr process furnace, fired on plant gas, equipped with ULNB
• Fractionator Charge Heater, 39.7 MMBtu/hr furnace, fired on plant gas, equipped with
ULNB
• Crude Unit Furnace, 32.5 MMBtu/hr process furnace, fired on plant gas, equipped with
ULNB
• FCCU #2, controlled with WGS and LoTOx
• FCC Feed Heater 17.7 MMBtu/hr process furnace, fired on plant gas, equipped with ULNB
• Boiler #4, 35.6 MMBtu/hr boiler, fired on plant gas
• Boiler #5, 70.0 MMBtu/hr boiler, fired on plant gas, equipped with SCR
• Boiler #8, 92.7 MMBtu/hr boiler, fired on plant gas, equipped with LNB and SCR
• Boiler #9, 89.3 MMBtu/hr boiler, fired on plant gas, equipped with SCR
• Boiler #10, 89.3 MMBtu/hr boiler, fired on plant gas, equipped with SCR
• Boiler #11, 89.3 MMBtu/hr steam boiler, fired on plant gas, equipped with LNB and SCR
• Cooling Towers
• Flares
• Tank Farm
• Loading/Unloading
• Emergency Equipment (Diesel)
• Emergency Equipment (Natural Gas) 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). Emission units such as a fluidized catalytic cracking unit (FCCU) which may have multiple individual component parts, but which can be
treated as a single unit for purposes of RACT analysis and discussion, will be treated in such a manner. 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

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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, HF Sinclair’s baseline actual emissions were determined to be the following (in tons per year)1:
Table 1-1: Actual Emissions
Pollutant Actual Emissions (Tons/Year)
PM2.5 13.27 SO2 109.96 NOx 181.71
VOC 157.86 NH3 17.82
The current PTE values for HF Sinclair, 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-AN101230041-13)2 are as follows:
Table 1-2: Current Potential to Emit
Pollutant Potential to Emit (Tons/Year)
PM2.5 47.6 SO2 110.3
NOx 341.1 VOC 252.2 NH3 18.2*
* NH3 emissions not 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;
most facilities were held to zero growth. This decision was largely based on source type, and
1 see References: Item #9 2 see References: Item #6

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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 HF Sinclair, between the years of 2016 and 2017, there were no NSR permitting actions that took place – the last AO issued to the HF Sinclair refinery was in 2013. Thus, the only required changes to the emission inventory would be to apply the effects of growth, which in HF Sinclair’s
case was no effect (as explained above). Therefore, the modified emission totals for 2017 are shown below in Table 2-1, and look exactly the same as the original 2016 actual emissions. Table 2-1: Modeled Emission Values
Pollutant Potential to Emit (Tons/Year)
PM2.5 13.27
SO2 109.96 NOx 181.71 VOC 157.86
NH3 17.82
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 2016 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. 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.

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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 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.3
4.0 BACT for Refinery Process Heaters and Boilers
UDAQ has separated the analysis of process heaters and boilers into two groups. For those heaters and boilers with heat input ratings less than 30 MMBtu/hr; UDAQ has included its analysis in a separate document which addresses similar emission units which are common to
many sources – such as small heaters and boilers. Please refer to the PM2.5 Serious SIP - BACT for Small Sources – Section 5 for details of the analysis for these smaller units. The remaining larger items are covered below. Of the 21 existing or proposed process heaters, approximately
half meet the size criteria discussed above. HF Sinclair also has 6 boilers which will be covered in this analysis. These items are: 4H1 FCC Feed Heater 6H1 Reformer Reheat Furnace 6H3 Reformer Reheat Furnace 7H3 HF Alkylation Depropanizer Reboiler 8H2 Crude Furnace #1 10H2 Hot Oil Furnace
12H1 NHDS Reactor Charge Furnace 19H2 DHT Charge Heater 20H2 Fractionator Charge Heater
20H3 Fractionator Charge Heater

3 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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24H1 Crude Unit Furnace 33H1 Vacuum Furnace Heater
Boiler #4 Boiler #5 Boiler #8
Boiler #9 Boiler #10 Boiler #11
These units range in size from 33 MMBtu/hr to as large as 150 MMBtu/hr. All are or would be fired on a combination of refinery fuel gas and natural gas. 4.1 PM2.5 No add-on controls for particulates were considered by UDAQ for these boilers. Given that these emission units are fired on gaseous fuels, with inherently low particulate formation, no controls
are expected to be cost effective. HF Sinclair did consider the usual particulate control options of good combustion practices, use of low sulfur fuels, wet gas scrubbers, electrostatic precipitators (ESPs), cyclones, and baghouse/fabric filtration; and determined that only good combustion
practices and use of low sulfur gaseous fuels were technically feasible. Both refinery fuel gas4 and natural gas are low sulfur fuels. HF Sinclair conducted an economic analysis5 of switching to using exclusively natural gas as fuel and found such a switch to not be economically feasible,
with a control cost in excess of $2.2 million/ton of particulate removed. 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. HF Sinclair 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. 4.2 SO2 Generally, SO2 is formed from the combustion of sulfur present in the fuel. By limiting the sulfur
content of the fuel, less SO2 will be generated. Emissions of SO2 can also be controlled by post combustion control devices or processes. 4.2.1 Available Control Technology By consolidating all process heaters and boilers together into a single group for BACT

4 Refinery fuel gas is higher in sulfur content than natural gas. Pipeline quality natural gas has a very low sulfur content of approximately 4 ppm – typically in the form of mercaptans used as odorants. The sulfur content of refinery fuel gas varies depending on the performance/removal efficiency of the amine scrubbing units (SRUs) at the refinery. At the HF Sinclair refinery, the SRU is designed to produce fuel gas with an average H2S content of 60 ppm on an annual average. However, short term spikes as high as 162 ppmv sulfur on a 3-hr average basis are allowed under the current rules of the SIP. By way of comparison, ultra-low sulfur diesel fuel (ULSD) is 15 ppm sulfur. 5 see References: Item #7

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consideration DAQ is able to consider controls on some emissions from this group which would ordinarily be dropped as being 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 (FGD) 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 control. Two other add-on controls wet gas scrubbing (WGS) and Emerachem EMx™ can be considered
available technologies. A typical WGS system consists of either a packed bed tower or venturi-type scrubber. The flue gas to be cleaned passes through the absorber where misting nozzles form a dense curtain of liquid. The liquid reagent helps to cool the flue gas, neutralize the SO2 in
the flue gas, as well as trap any particulate matter in the gas. Liquid collects in the bottom of the scrubber where caustic soda (NaOH) is added to prevent the formation of sulfuric acid (H2SO4). The scrubbed gas continues upward through the vessel passing through filters prior to release into
the atmosphere. Waste collected at the bottom of the scrubber is pumped off for additional treatment. This waste contains sulfites such as NaHSO3 and Na2SO3 along with residual catalyst fines and precipitated solids. Solids removal is done through a clarifier using flocculation to settle
out the solids. The EMx™ system uses a coated oxidation catalyst installed in the flue gas to remove both NOx
and CO without a reagent such as ammonia. The NO emissions are oxidized to NO2 and then absorbed onto the catalyst. A dilute hydrogen gas is passed through the catalyst periodically to de-absorb the NO2 from the catalyst and reduce it to N2 prior to exit from the stack. EMx™ prefers an operating temperature range between 500°F and 700°F. The catalyst uses a potassium carbonate coating that reacts to form potassium nitrates and nitrites on the surface of the catalyst. When all of the carbonate absorber coating on the surface of the catalyst has reacted to form nitrogen compounds, NO2 is no longer absorbed, and the catalyst must be regenerated. Dampers are used to isolate a portion of the catalyst for regeneration. The regeneration gas consists of
steam, carbon dioxide, and a dilute concentration of hydrogen. The regeneration gas is passed through the isolated portion of the catalyst while the remaining catalyst stays in contact with the flue gas. After the isolated portion has been regenerated, the next set of dampers close to isolate
and regenerate the next portion of the catalyst. This cycle repeats continuously. At any one time, four oxidation/absorption cycles are occurring and one regeneration cycle is occurring. 4.2.2 Evaluation of Technical Feasibility of Available Controls WGS is available for control of emissions from sources with higher concentrations of SO2 or acid
gases in the exhaust stream, but for these types of sources they are just not commercially available. To some degree this can also be viewed as a technical concern, but in either case the end result is the same. As WGS is not commercially available for emission sources of this concentration, WGS will not be considered further. The EMx system is complex enough that the technology has not been proven to run longer than

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one year without a turnaround. HF Sinclair requires that the refinery heaters are able to operate at least three years between turnarounds. This type of control imposes a technical limitation on the
operation of the refinery and is considered technically infeasible by the refinery for control of SO2 emissions. EMx will not be considered further.
This leaves only the use of low sulfur fuels and good combustion practices as technically feasible and available controls. 4.2.3 Evaluation and Ranking of Technically Feasible Controls Both controls can be used in conjunction, so no ranking of control techniques is required. 4.2.4 Further Evaluation of Most Effective Controls As mentioned previously, HF Sinclair conducted an analysis of switching to running exclusively on pipeline quality natural gas as fuel versus using refinery fuel gas or a combination of refinery
fuel gas and natural gas6. While HF Sinclair’s analysis was conducted on particulate emissions and not SO2, the difference in emission totals between particulate and SO2 is approximately 3 tons (total particulate emissions from heaters and boilers ~ 10 tons/year, total emissions of SO
from heaters and boilers ~ 13 tons/year), the economic analysis result is similar. Using exclusively natural gas as fuel is not economically feasible, with a control cost in excess of $1.69 million/ton of particulate removed.
4.2.5 Selection of BACT Controls
UDAQ recommends that HF Sinclair continue to use good combustion controls and refinery fuel gas or natural gas as fuel for control of SO2 emissions from the refinery process heaters and boilers. In addition, UDAQ recommends that the Subpart Ja fuel gas H2S limit 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. HF Sinclair 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. HF Sinclair 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.
4.3 NOx NOx, or oxides of nitrogen, are formed from the combustion of fuel. There are three mechanisms

6 see References: Item #7

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for the formation of NOx: fuel NOx, which is the oxidation of the nitrogen bound in the fuel; thermal NOx, or the oxidation of the nitrogen (N2) present in the combustion air itself; and prompt
NOx, which is formed from the combination of combustion air nitrogen (N2) with various partially-combusted intermediary products derived from the fuel. For combustion within the process heaters and boilers, fuel NOx and thermal NOx are the major contributors, with prompt
NOx contributing slightly only in the initial stages of combustion. All three processes are temperature dependent – combustion temperatures below 2700ºF greatly inhibit NOx formation. 4.3.1 Available Control Technology The following technologies were identified as potential control methodologies for control of NOx emissions by HF Sinclair7: good combustion practices; low emission combustion (LEC); selective non-catalytic reduction (SNCR), the injection of ammonia or urea directly into the late stages of the combustion zone; selective catalytic reduction (SCR); flue gas recirculation (FGR); and EMx™ (previously known as SCONOx™).
Low Emission Combustion (or LEC) is a summary term given to a host of different combustor designs and pre-combustion controls such as water or steam injection. These can be combined with a similar type of combustion control known as staged air/fuel combustion or overfire air
injection. All serve the same general purpose – to reduce NOx formation by lowering the overall flame temperature. The various combustor (burner) designs, ranging from low-NOx, through ultra-low-NOx and up to “next generation” ultra-low-NOx reduce flame temperature through a
combination of flame diffusion, internal flue gas recirculation and some degree of staged combustion design. Water injection uses the inherent high specific heat of the injected water to absorb some of the combustion energy without increasing the ambient gas temperature. Staged
air/fuel combustion limits the total amount of combustion air so that reducing and oxidizing sections are created in the combustion chamber. Combustion happens in stages, with intermediary products needing to physically move between sections before continuing
combustion. Combustion is slowed down, limiting the “flux” (energy output/time) which lowers the total temperature. Low-NOx Burners (LNB): Typically thought of as an advanced version of a standard burner, the LNB reduces NOx formation through the restriction of oxygen, flame temperature, and/or residence time. There are two main types of LNB: staged fuel and staged air burners. Staged fuel burners divide the combustion zone into two regions, limiting the amount of fuel supplied in the first zone with the standard amount of combustion air, and then supplying the remainder of the
fuel in the second zone to combust with the un-combusted oxygen from the first zone. Staged air burners reverse this, limiting the combustion air in the first zone then supplying the remainder of the combustion air in the second zone to combust the remaining fuel. Staged fuel LNBs are more
suited to natural gas-fired boilers as they are designed to restrict flame temperature. Ultra-Low-NOx Burners (ULNB): Most commonly a combination of LNB technology with some
internal flue gas recirculation. The burner recirculates some of the hot flue gases from the flame or firebox back into the combustion zone. Since these high temperature flue gases are oxygen depleted, the burner lowers the speed at which fuel can be combusted without reducing the flame
temperature below the level needed for optimum combustion efficiency. Reducing oxygen concentrations in the firebox most directly impacts fuel NOx generation. Flue Gas Recirculation (FGR): External FGR involves recycling of flue gas back into the firebox

7 see References: Item #7

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as part of the fuel-air mixture at the burner. Although similar to the concept of ULNB, rather than using burner design features to recirculate gases from within the firebox, FGR uses external
ductwork to route a portion of the exhaust stream back to the inlet side of the boiler and return it into the boiler windbox.
In the SCR process, a reducing agent, such as aqueous ammonia, is introduced into the exhaust, upstream of a metal or ceramic catalyst. As the exhaust gas mixture passes through the catalyst bed, the reducing agent selectively reduces the nitrogen oxide compounds present in the exhaust
to produce elemental nitrogen (N2) and water (H2O). Ammonia is the most commonly used reducing agent. Adequate mixing of ammonia in the exhaust gas and control of the amount of ammonia injected (based on the inlet NOx concentration) are critical to obtaining the required reduction. For the SCR system to operate properly, the exhaust gas must maintain minimum O2 concentrations and remain within a specified temperature range (typically between 480ºF and 800ºF with the most effective range being between 580°F and 650°F), with the range dictated by the type of catalyst. Exhaust gas temperatures greater than the upper limit (850°F) will pass the NOx and unreacted ammonia through the catalyst. The most widely used catalysts are vanadium,
platinum, titanium, or zeolite compounds impregnated on metallic or ceramic substrates in a plate of honeycomb configuration. The catalyst life expectancy is typically 3 to 6 years, at which time the vendor can recycle the catalyst to minimize waste.
One final technology is CETEX, which is a process of descaling firebox steam tubes and the recoating these tubes – improving heat transfer and lowering total fuel consumption for a given
amount of steam output. 4.3.2 Evaluation of Technical Feasibility of Available Controls
Most of the listed controls are technically feasible, although certain control techniques cannot be used in conjunction. For example, ULNB and FGR both use some degree of flue gas
recirculation, making the use of both technologies redundant and counter-productive. FGR can only be applied on mechanical draft heaters/boilers with burners that can accommodate increased gas flows. All but one heater at the HF Sinclair refinery is naturally drafted, and this heater has a separate physical limitation. In order to physically connect FGR, a separation of at least three feet must exist between the windbox and the burner to prevent the accumulation of potentially explosive gas mixtures if a heater tube should fail. The burner on the mechanical draft heater is located closer than three feet to the windbox and cannot be moved farther away and still receive proper heater transfer. FGR is eliminated from further consideration. Next generation ULNB
have proven less reliable than “normal” ULNB. They have been prone to plugging from impurities present in the fuel source. They also have not been shown to have any better emissions control than normal ULNB.
SCR and SNCR are opposed technologies as well, as SNCR is the use of ammonia injection without the added benefit of a catalyst bed to aid in pollutant reduction. Strictly speaking, SCR is
simply the most commonly used catalytic reduction technique. More generally, NSCR (or non-selective catalytic reduction) represents those catalytic reduction techniques using alternative catalysts also capable of reducing NOx. Often these catalysts reduce NOx in addition to many
other compounds and are not specifically designed or optimized for NOx reduction. Efficient operation of these catalysts typically requires that the exhaust gases contain low oxygen concentrations – perhaps as low as 0.5% and no more than 4%. Since this requires the use of lean burn engines, furnaces and boilers, NSCR was eliminated by HF Sinclair as a valid control technique.

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SNCR was eliminated based on a lack of load responsiveness. The control technique is somewhat crude by current standards, using only ammonia injection to reduce NOx emissions and
relying on turbulence, temperature and residence time to allow the reaction to come to completion. The technical limitation of this technique is that as load changes NOx emissions can vary and change fairly rapidly, yet the only control mechanism is to change the amount of
ammonia being injected into the flue gas. Periods of too little ammonia will be followed by periods of too much ammonia, both scenarios leading directly to an increase in PM2.5 emissions.
The EMx process is highly sensitive to poisoning from sulfur compounds present in the exhaust gas. EMx has never been demonstrated in practice on refinery fuel gas-fired heaters or boilers and is not deemed commercially available for this fuel type. EMx is therefore eliminated from consideration. Water/steam injection is of limited effectiveness on process heaters and boilers. While some NOx reduction is possible, the benefit gained is minimal on units already equipped with low-NOx burners or better. Water/steam injection is typically employed on turbines where the increased
mass of the steam-laden exhaust gas increases the efficiency of the turbine by improving the momentum transfer to the power generator. It is not typically employed on process heaters or boilers.
Low excess air firing (overfire/staged air combustion) was also eliminated based on flame lengthening problems. Reducing the oxygen concentration causes the combustion flame to
lengthen, potentially causing flame impingement – where the flame comes into physical contact with one or more surfaces of the unit. This can cause severe damage to the unit and hazardous safety situations for refinery workers. This technique has also been eliminated from further
consideration. 4.3.3 Evaluation and Ranking of Technically Feasible Controls
The remaining control techniques and their control effectiveness are listed below: Table 4-1 NOx Control Effectiveness Technology Range of Control (%)
ULNB + SCR 85-99
LNB + SCR 80-99
SCR 80-90
ULNB 65-75 LNB 50-60 CETEX NA* * Not applicable, see below Based on these control efficiencies, the use of SCR in combination with some form of NOx
controlling burner (either LNB or ULNB) is the top ranked control option. The use of SCR without a burner upgrade can also be applied, but is rarely found in practice. The second ranked option is the use of ULNB alone, followed by LNB. HF Sinclair already performs chemical
descaling operations on the refinery boilers which are very similar in form and function to CETEX.

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4.3.4 Further Evaluation of Most Effective Controls
HF Sinclair provided additional analysis for the technically feasible controls8. Installing SCR can have adverse energy and environmental impacts. One potential source of concern with operation of SCR is the generation of ammonia slip. Unreacted ammonia, meaning any ammonia which
does not react with the NOx present in the exhaust stream, may react with SO3 to form ammonium sulfate/sulfite. This can occur either in the exhaust stream or in the ambient air. The unreacted ammonia is referred to as “ammonia slip.” Ammonia slip itself often requires permit limitations
as a precursor pollutant. Another source of concern is handling and disposal of the spent catalyst, which becomes a solid waste product. Operation of the SCR system reduces air flow, requiring additional energy in the form of fan power upgrades. In addition, in order to install SCR, HF Sinclair would need to replace all of the existing natural draft heaters with mechanical draft heaters in order to accommodate the additional airflow requirements.
Installation of LNB or ULNB can change the heating pattern of the furnace or boiler by extending and cooling the flame.
HF Sinclair conducted an analysis for installing SCR on those heaters/boilers not already equipped with this control, and for installing LNB/ULNB. HF Sinclair concluded that the installation of SCR on naturally drafted heaters would require replacing or rebuilding those
heaters as mechanical draft heaters. Such a change would not be economically feasible. Similarly, installation of LNB or ULNB often requires the use of more physical burners than originally installed, as each burner can have a lower heating duty. While larger duty burners can
be installed, the selection is limited and the change in burner size can force physical changes in the process heater or boiler to prevent damage from the increased flame size. 4.3.5 Selection of BACT Controls UDAQ recommends the existing NOx controls remain as BACT. HF Sinclair 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:
• Reformer Reheat Furnace 6H1: 0.15 lb/MMBtu
• Crude Furnace #1 8H2: 0.04 lb/MMBtu
• NHDS Reactor Charge Furnace 12H1: 0.10 lb/MMBtu
• Fractionator Charge Heater 20H2: 0.04 lb/MMBtu

8 see References: Item #7

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• Boiler #5: 0.02 lb/MMBtu
• Boiler #8: 0.02 lb/MMBtu
• Boiler #9: 0.02 lb/MMBtu
• Boiler #10: 0.02 lb/MMBtu
• Boiler #11: 0.02 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 on process and operation variability, existing stack tests, and established emission factors. HF
Sinclair will still comply with all existing permit and SIP requirements. 4.4 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 HF Sinclair 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 few emissions of ammonia from the heaters and boilers naturally (some minor amounts of ammonia may be generated as part of the combustion process). At the HF Sinclair Refinery, two large process heaters (10H2 Hot Oil Furnace, and 33H1 Vacuum Furnace Heater) and all of the large boilers except Boiler #4 are equipped with SCR as NOx control and thus subject to some
degree of ammonia slip. For existing systems, an ammonia slip of 10 ppm is considered BACT for process heaters and boilers. This is discussed in greater detail in the PM2.5 Serious SIP - BACT for Small Sources – Section 2 - Ammonia Emissions from SCRs. No additional controls
are required for BACT; thus, no additional limits are required to be established for the SIP.are 5.0 BACT for Flares
5.1 Flare Gas Emissions
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 2.5 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 J and Ja for all hydrocarbon flares, and to install and operate a flare gas recovery or minimization process by January 1, 2019.

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5.1.1 Available Control Technology
There are two parts to refinery flares, as outlined in the Refinery General RACT Evaluation. 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). 5.1.2 Evaluation of Technical Feasibility of Available Controls
Neither part is technically infeasible. 5.1.3 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 discussed in the Refinery General RACT Evaluation, most refineries began economic evaluations of flaring events beginning in
November of 2015 to determine whether a flare gas recovery program is viable regardless of any imposing of such requirement by DAQ.
For its part, HF Sinclair has implemented a program to evaluate flare events which exceed the thresholds listed in Subpart Ja. The refinery has initiated procedures to install and operate a flare gas recovery program by the implementation date of January 1, 2019 as outlined in
IX.H.11.g.v.B. 5.1.4 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. 5.1.5 Selection of BACT Controls DAQ recommends that HF Sinclair continue to implement the general refinery SIP requirement “Requirements on Hydrocarbon Flares” as outlined in Section IX.H.11.g.v.B. There are no expected emission reductions versus the 2016 “true-up” emission inventory as the flare gas recovery system was already included in that inventory. 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. HF Sinclair 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. 6.0 BACT for Cooling Towers
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.

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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.
6.1 VOCs 6.1.1 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 UDAQ’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.
6.1.2 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. 6.1.3 Evaluation and Ranking of Technically Feasible Controls N/A This has become a refinery general SIP requirement.
6.1.4 Further Evaluation of Most Effective Controls N/A This has become a refinery general SIP requirement. 6.1.5 Selection of BACT Controls UDAQ recommends that HF Sinclair 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. HF Sinclair will comply with any applicable emission
limits in Section IX, Part H.11. 7.0 BACT for the SRUs
HF Sinclair identified several different types of SRU systems9: the traditional Claus unit with or without a tail gas treatment unit (TGTU),
the Superclaus process, the Euroclaus process, the Mobil Oil Direct Oxidation process, the COPE, Oxyclaus, and SURE processes,

9 see References: Item #7

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the Selectox process, the Sulfreen process,
the Maxisulf, CBA, Clinsulf, and MCRC processes, the Wellman-Lord, CANSOLV, and CLINTOX processes, the Stretford, Z-SORB, LO-CAT, and CrystaSulf liquid-phase oxidation reduction technologies,
and, the SCOT process.
However, primarily these processes are merely refinements on existing SRU technology and do little to treat or remove the SO2 emissions being released to the ambient air. Rather, they attempt either 1) to reduce the load on the SRU by removing some amount of H2S prior to the oxidation step of the SRU, or 2) attempt to improve the efficiency of the SRU by aiding in the oxidation/reduction process. There are a few notable exceptions, namely the last three types of processes, which will be discussed further below. 7.1 SO2
HF Sinclair operates a single SRU meeting the established 95% sulfur recovery required under the PM10 SIP (SIP Section IX, Part H.1). The existing system consists of an amine treatment unit
followed by a conventional Claus SRU and tail gas incinerator. The SRU does not utilize a TGTU as HF Sinclair has opted to control emissions from the SRU with a wet gas scrubber (WGS) – either unit 4 or unit 25. The SRU does not operate if neither WGS is operational and
able to receive the emissions. UDAQ considers this system to be a “well-controlled SRU”, even though in most cases a “well -controlled SRU” is one that is operating with a TGTU followed by tail gas incineration.
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 catalytically to form SO2. Then, the H2S and SO2 react, at an optimal 2:1 ratio, to form elemental sulfur. After each catalytic stage, the liquid sulfur is recovered from condensers. The effluent gas from this process is sent to the TGTU, where the SO2 is converted back to H2S and captured by amine scrubbing. Any unreacted 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.
In HF Sinclair’s case, the process is reversed, using amine treatment first, then the Claus unit form elemental sulfur. The effluent gas from the Claus unit is then sent to the tail gas incinerator to convert any remaining H2S into SO2. The exhaust gas from the incinerator is then sent through
the WGS which scrubs out the SO2 and NOx, through use of a LoTOx system. 7.1.1 Available Control Technology
As mentioned in the opening paragraph, HF Sinclair identified three other processes/control systems to further reduce emissions from a well-controlled SRU.
• the Wellman-Lord, CANSOLV, and CLINTOX processes • the Stretford, Z-SORB, LO-CAT, and CrystaSulf liquid-phase oxidation reduction technologies • the SCOT process

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The Wellman-Lord, CANSOLV, and CLINTOX processes are essentially wet scrubbers that use proprietary solvents for SO2 removal. The processes can be used in conjunction with traditional
SRUs, but the use of a SRU is not required. A combustion process to convert the H2S in the inlet stream to SO2 is required however. When they are used in conjunction with a traditional SRU, the stripped SO2 can be returned to the front of the processing stream so that more elemental
sulfur can be recovered. This type of technology serves as the basis of Big West Oil’s backup caustic scrubbing system.
The Stretford, Z-SORB, LO-CAT, and CrystaSulf liquid-phase oxidation reduction technologies use indirect oxidation of H2S to form elemental sulfur and water. These systems replace the traditional SRU. They all operate similarly, differing primarily only in the choice of chelating agent used. The SCOT process is essentially the basis of the TGTU and, while an available control technology, has been specifically skipped by HF Sinclair in using WGS technology as a final form of treatment.
WGS is a final control option, where the exhaust from the SRU is sent to the WGS in-lieu of tail gas treatment.
7.1.2 Evaluation of Technical Feasibility of Available Controls
All controls are technically feasible and have been demonstrated in practice. The Stretford, Z-SORB, LO-CAT, and CrystaSulf processes replace the traditional SRU and have been eliminated for use as the sole control technique for this reason. The original PM10 SIP and the current
maintenance plan requirements of IX.H.1.g.iii.A.I require all refineries located in or affecting a PM10 or PM2.5 nonattainment area to install, operate and maintain a SRU that is at least 95% efficient in SO2 removal. As these processes do not meet the definition of a SRU, they cannot
meet this requirement without a change in this particular requirement. They can serve as redundant backup processes or as add-on controls to the existing SRU. 7.1.3 Evaluation and Ranking of Technically Feasible Controls Well-controlled SRUs can achieve 99.9% or better sulfur recovery efficiency rates. HF Sinclair’s current SRU+WGS system meets this level of sulfur recovery, with estimated SO2 emissions of just 12.5 tons following installation of the WGS10. Operation of the other control/processing
systems are not expected to yield higher levels of SO2 control than operation of a WGS. 7.1.4 Further Evaluation of Most Effective Controls
None of the control options will effectively reduce emissions below the levels already achieved. Although any of the control options could be applied in lieu of the existing controls, the costs of
these alternative add-on measures would be well above any arbitrary $/ton value considered

10 HF Sinclair received authorization to install the both WGS systems in the AO DAQE-AN101230041-13 which was issued on November 18, 2013. HF Sinclair’s baseline actual emissions for 2016 are based on the 2014 triannual emission inventory as submitted by HF Sinclair. At that time (on or about April 15, 2015) HF Sinclair had not yet completed installation of the 2nd WGS which was primarily designed to control emissions from the SRU and the second FCCU (the 1st WGS primarily controlled FCCU #1). At the time of preparation of this technical support documentation, HF Sinclair’s estimated emissions from the SRU as controlled by WGS are approximately 12.5 tons for emission year 2017.

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viable. Either the system would require a redesign of the SRU process, or it would require removal of the existing WGS infrastructure as this system would no longer be economically or
process viable. 7.1.5 Selection of BACT Controls
UDAQ recommends that HF Sinclair continue to control its SRU and TGI via WGS as BACT. The emissions from the WGS systems are monitored by CEM. Because the SRU and TGI are
routed through one of HF Sinclair’s existing FCCU WGS, HF Sinclair will continue to meet BACT by meeting the FCCU WGS limits established in Section IX, Part H.11.g of the SIP. These controls and limits are required through existing permit requirements. The existing emission limitations were established based on NSPS Subpart Ja. 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. HF Sinclair 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 the FCCU Regenerators 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 two- or three-stage 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 “catalyst coke” or just 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. HF Sinclair’s refinery has two FCCUs. The older FCCU receives hydrotreated feedstocks from
the gas-oil hydrocracker (GHC). The GHC uses a hydrotreating catalyst to begin removal of sulfur and nitrogen from the feed by replacing these elements with hydrogen. Once hydrotreated, the modified and now heated feedstock is sent to the FCCU where catalyst additives are used to
control both SO2 and NOx emissions. The new FCCU, which was added as part of the Heavy Crude Processing Project in DAQE-AN101230041-13 processes lower sulfur waxy crudes. This unit is not hydrotreated, but the difference in crude sulfur content is great enough that no hydrotreating is required (HF Sinclair’s “standard” crude – Western Canadian Select – is approximately 34,000 ppm sulfur, black and yellow wax crudes are approximately 900 ppm sulfur).

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Both FCCUs operate in complete combustion mode. Neither unit is equipped with a CO boiler.
Cyclones are used to remove catalyst particles from the combustion gases exiting the regenerators, and a WGS is used for final control of particulate emissions. 8.1 PM2.5 8.1.1 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. 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. 8.1.2 Evaluation of Technical Feasibility of Available Controls
All of the available controls are technically feasible; however the controls are mutually exclusive – they cannot (in most cases) be used together. 8.1.3 Evaluation and Ranking of Technically Feasible Controls In terms of efficiency for control of particulate emissions, the available controls are all approximately equal.
• 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
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, with a higher installation cost than that of a fabric filter.

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Both the fabric filter and FGF control only the filterable fraction of particulate emissions,
While the WGS system has the added benefit of removing condensable 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. Use of a high efficiency ESP is the typical default option. HF Sinclair used an ESP prior to the installation of the WGS system, and the nearby Chevron refinery still employs an ESP as the final particulate control system. 8.1.4 Further Evaluation of Most Effective Controls
Should HF Sinclair have chosen to use a FGF or fabric filter control, emissions of 0.2 lb/1000 lb of coke burned are possible, although these values are filterable particulate only. WGS is slightly less efficient, with reported values of 0.3-0.5 lb/1000 lb coke burned. The default ESP option is
typically limited to 0.5-0.7 lb/1000 lb coke burned, although this meets the various requirements of both the moderate PM2.5 SIP as well as the emission limitations of 40 CFR 63 Subpart UUU and 40 CFR 60 Subpart Ja (limits are 1.0 lb/1000 lb coke burned). HF Sinclair did not provide an
economic analysis of the various controls, as it has already elected to install WGS as a control system on both FCCUs.
Switching away from WGS to utilize FGF or fabric filtration would not provide better emission control (although some decrease in filterable emissions would be possible, condensable emissions would increase and the added benefit provided by WGS in control of additional pollutants would
be lost. In addition, switching control technology would automatically be economically infeasible. 8.1.5 Selection of BACT Controls UDAQ recommends that HF Sinclair continue to use the WGS system to control emissions of particulate from the FCCU catalyst regenerator. 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. HF Sinclair 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.
8.2 SO2 8.2.1 Available Control Technology There exist several options for removing sulfur from FCCUs:
• Feed hydrotreating removes the sulfur from FCCU feedstocks prior to cracking operations. • SOx removing (deSOx) catalyst injection prevents the sulfur from forming in the coke so it isn’t burned off during regeneration forming SO2. • WGS allows for normal catalyst use, and then removes the SO2 from the exhaust gases through wet contact scrubbing.

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These options, while not necessarily mutually exclusive, do have impacts on the control options
for other pollutants. Feed hydrotreating has some positive benefit on NOx formation (see section 6.3 below). 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 for the use
of LoTOx, a NOx control option. 8.2.2 Evaluation of Technical Feasibility of Available Controls
All of the listed controls are technically feasible. Currently HF Sinclair uses a combination of feed hydrotreating and WGS for SO2 control, which represents the baseline case for this refinery (see section 8.0 above for details). 8.2.3 Evaluation and Ranking of Technically Feasible Controls Some combining of control options is possible. Feed hydrotreating and deSOx catalysts can be
used in combination. WGS systems do not gain any additional benefit when combined with either of the other two control methods.
The use of WGS technology can achieve the limits 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 hydrotreating or deSOx catalyst. It also has the added
disadvantage of water waste treatment and/or disposal. The use of SOx reducing catalyst, can also meet the Subpart Ja limits. The known disadvantage of
sulfate formation can be treated with effective particulate control systems. Feed hydrotreating has also been demonstrated to meet the Subpart Ja limits. While HF Sinclair
uses feed hydrotreating, this is done for refinery processing purposes rather than its effects on emission control. As all three control options are viable, and have been deemed equally effective at reaching the required limits under Subpart Ja – further evaluation is required. 8.2.4 Further Evaluation of Most Effective Controls
HF Sinclair did not submit an economic analysis for any of these control options. However, since all three control options have similar control efficiencies and HF Sinclair has already chosen to install a WGS, no additional analysis is required.
8.2.5 Selection of BACT Controls
UDAQ recommends that HF Sinclair continue to use feed hydrotreating and WGS 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. HF Sinclair will comply with any applicable emissions limits in Section IX, Part H.11. See Appendix A for a complete listing of

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existing permit conditions, established emission limits, and the basis of those limits. 8.3 NOx 8.3.1 Available Control Technology
The available options for control of NOx from FCCUs are listed below:
• Low-NOx promoter catalysts • Selective non-catalytic reduction (SNCR) • Selective catalytic reduction (SCR) • Feed hydrotreating • LoTOx in conjunction with WGS Low-NOx promoter catalysts and NOx reducing additives (as found in another BACT analysis) can be considered the same technology for purposes of this review. Both are catalytic additives
(meaning they are not consumed in the process) although they serve slightly different purposes. The promoter catalysts specifically serve as FCC catalysts – providing sites for the cracking of long chain hydrocarbon molecules into shorter ones, but helping prevent the formation of NOx
during the regeneration phase. The additives are supposed to prevent nitrogen from being trapped in the coke in the first place so that there is less “fuel-bound” nitrogen to form NOx during the regeneration process.
8.3.2 Evaluation of Technical Feasibility of BACT Controls
All control options are technically feasible. Although LoTOx requires that a WGS system is simultaneously in use, this does not invalidate its
technical feasibility. HF Sinclair, and to some degree the other refineries as well, has extensively investigated the use of NOx reducing additives and determined that they had no effect on NOx emissions. Low-NOx promoter catalysts are useful, and so only the promoter catalysts will be evaluated further. The use of SNCR or direct ammonia injection into the FCCU regenerator exhaust cannot be used in conjunction with the WGS/LoTOx system because of the rapid cooling provided by the WGS.
The use of SCR would also be severely hampered by a WGS/LoTOx system for much the same reason, although the injection of the ammonia would likely not harm the functionality of the WGS or LoTOx systems.
8.3.3 Evaluation and Ranking of Technically Feasible Controls
None of the refineries provided detailed analysis for the evaluation of SNCR beyond stating that no ammonia injection into the FCCU was occurring. Expected control efficiencies would be rather low, based on residence time, exhaust temperatures, and overall emission reductions of
SNCR-based systems. The remaining options of feed hydrotreating, SCR, and WGS with LoTOx are all approximately equal in terms of overall control effectiveness. 8.3.4 Further Evaluation of Most Effective Controls

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SCR has 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 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, 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. WGS systems, with or without LoTOx, generate wastewater which must be treated before discharge or stored before disposal. Systems with LoTOx either have an acidic wastewater (nitric acid generated by N2O5 in the aqueous phase), or one with soluble solids from neutralization of
that acid. 8.3.5 Selection of BACT Controls
UDAQ does not recommend any additional controls be installed. HF Sinclair should continue to meet the rolling 365-day and rolling seven-day limits on NOx emissions from the FCCU as
required by NSPS Subpart Ja using WGS with LoTOx. The existing limits account for current process variability while still limiting NOx emissions from the FCCUs. 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. HF Sinclair 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. 8.4 VOC and Ammonia Considerations UDAQ was unable to locate any additional controls to reduce emissions of VOCs from the FCCU regenerators. In 2016, HF Sinclair’s listed VOC emissions from these units were 0 tons. HF Sinclair has not tested the emissions from this emitting unit, and thus UDAQ is unable to comment. However, in a review of other refineries, no viable add-on control device or technique
was found to further reduce the emissions of VOCs from FCC catalyst regenerators. 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 already in place. No additional consideration or controls are 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 typically relatively small. 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., but does not occur among the refineries in Utah.

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None of the refineries located in the Salt Lake City PM2.5 NAA uses ammonia injection for NOx control.
Therefore, 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. 9.0 BACT for Fugitives In this context, fugitives are referring to fugitive VOC emissions. While HF Sinclair 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 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.
9.1 VOCs 9.1.1 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 HF Sinclair) became subject to the requirements of low-leak LDAR (Subpart GGGa) as part of the requirements of the moderate PM2.5 SIP.
9.1.2 Evaluation of Technical Feasibility of Available Controls N/A Low-leak LDAR is technically feasible, and HF Sinclair became subject to its requirements on January 1, 2017. 9.1.3 Evaluation and Ranking of Technically Feasible Controls
N/A HF Sinclair is already implementing the requirements of 40 CFR 60 Subpart GGGa. 9.1.4 Further Evaluation of Most Effective Controls
N/A HF Sinclair is already implementing the requirements of 40 CFR 60 Subpart GGGa. 9.1.5 Selection of RACT Controls UDAQ recommends that HF Sinclair 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 exiting permit and SIP 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. HF Sinclair will comply with any applicable emission limits in Section IX, Part H.11.

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10.0 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 PM2.5 SIP, the refineries were required to implement a tank degassing work practice standard.
10.1 VOC 10.1.1 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. 10.1.2 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. 10.1.3 Evaluation and Ranking of Technically Feasible Controls Tank degassing 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. 10.1.4 Further Evaluation of Most Effective Controls HF Sinclair is already required to follow the tank degassing requirements of Section IX, Part
H.11.g. The remaining vapor controls were all evaluated by HF Sinclair and were found not be economically feasible, with cost effectiveness values in excess of $200,000/ton of VOC control. 10.1.5 Selection of BACT Controls UDAQ recommends that HF Sinclair 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. HF Sinclair will comply with any applicable emission limits in Section IX, Part H.11.

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11.0 BACT for Wastewater System
11.1 VOC
The wastewater treatment system at HF Sinclair consists primarily of a system of drains that route runoff water and stormwater to an American Petroleum Institute (API) Separator unit, which separates entrained oils and volatiles from the wastewater. From there the effluent wastewater is
further treated with dissolved gas floatation and moving bed bio-film reactors. HF Sinclair also further treats the exhaust air from the system with carbon absorption. 11.1.1 Available Control Technology Because of HF Sinclair’s existing control system at the wastewater treatment plant, there are few available control options other than the baseline case. Essentially, the other control options are all alternatives to the existing controls. HF Sinclair currently uses carbon absorption as the
primary control option. Alternatively, the use of regenerative thermal oxidation (RTO), non-regenerative thermal oxidation (flaring), or vapor recovery (refrigeration or alternative method), are all potentially available methods of controlling the recovered vapors.
11.1.2 Evaluation of Technical Feasibility of Available Controls
For destruction/control of the collected vapors, only the use of a RTO, carbon canisters, or flaring have been shown to be technically feasible control methods based on the volume of expected VOC emissions (approximately 10 tons VOC/year).
11.1.3 Evaluation and Ranking of Technically Feasible Controls
The various control options are all approximately equal in terms of overall capture and control efficiency – although the use of thermal destruction (either RTO or flaring) is slightly better than carbon canisters in terms of overall efficiency. The carbon canisters eventually become saturated, allowing for some VOC bleed through until the canister is replaced. 11.1.4 Further Evaluation of Most Effective Controls HF Sinclair did not conduct an economic analysis of the available control options. Instead HF
Sinclair focused primarily on the regulatory requirements that apply to wastewater systems at refineries. 40 CFR 60 Subpart QQQ, 40 CFR 61 Subpart FF and 40 CFR 63 Subpart CC are all applicable to refinery wastewater treatment plants. These three regulations are all similar and
require closed drain systems and a control device for the main collection system. 11.1.5 Selection of BACT Controls
UDAQ recommends that HF Sinclair continue to operate the existing wastewater control system of API and carbon absorption as BACT for the wastewater treatment plant. Operation of API and
carbon absorption are required in Part H.12.d.v. No additional controls are required for BACT, thus no additional limits other than those established in H.12.d.v are required to be established for the SIP.

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12.0 BACT for Loading/Unloading
HF Sinclair submitted an analysis for product loading and unloading operations11. UDAQ has covered the analysis of loading and unloading operations in two different locations. For fugitive VOC emissions please refer to Section 9.0 of this document for further details. For more direct
VOC emissions from loading/unloading operations please refer to the PM2.5 Serious SIP - BACT for Small Sources – Section 13B for additional details. 12.1 VOC Loading and unloading operations are a source of VOC emissions. Although Stage I and II vapor recovery have already been covered in UDAQ’s PM2.5 Serious SIP - BACT for Small Sources analysis, one additional VOC control option in common use at refinery loading racks is a vapor combustion unit or carbon capture system to treat the recovered VOC vapors. 12.1.1 Available Control Technology
Once vapors have been recovered from loading/unloading operations, the recovered vapors need to be treated. While some vapor recovery units (VRUs) can return the recovered vapors back into
the system being controlled (depending on the system), some units require external treatment for final control. The use of regenerative thermal oxidation (RTO), non-regenerative thermal oxidation (flaring), or carbon capture via carbon canisters are all potentially available methods of
controlling the recovered vapors. 12.1.2 Evaluation of Technical Feasibility of Available Controls
For destruction/control of the collected vapors, only the use of a RTO, carbon canisters, or flaring have been shown to be technically feasible control methods based on the volume of expected
VOC emissions (typically less than 5 tons VOC/year). 12.1.3 Evaluation and Ranking of Technically Feasible Controls The various control options are all approximately equal in terms of overall capture and control efficiency – although the use of thermal destruction (either RTO or flaring) is slightly better than carbon canisters in terms of overall efficiency. The carbon canisters eventually become saturated, allowing for some VOC bleed through until the canister is replaced.
12.1.4 Further Evaluation of Most Effective Controls
HF Sinclair conducted an economic analysis of installing and operating a RTO for loading/unloading operations12. Based on expected annual emissions of 3.5 tons of VOC (based on HF Sinclair’s 2016 baseline emissions) and an annualized cost of $175,000 for this system, HF
Sinclair concluded that use of an RTO was not economically viable. HF Sinclair also determined that flaring of the VOC emissions would be viewed as installation of a new hydrocarbon flare and therefore subject to the flaring provisions of IX.H.11.g. UDAQ confirmed this assessment and
agreed that flaring was not a viable solution. The use of carbon canisters is potentially viable, but HF Sinclair has opted to continue to operate with vapor balancing, and submerged or bottom filling for control of VOCs from product loading.
11 see References: Item #7 12 see References: Item #7

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12.1.5 Selection of BACT Controls
UDAQ recommends that HF Sinclair continue to control product loading and unloading operations using existing work practice standards (submerged/bottom filling and vapor balancing)
as BACT. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. HF Sinclair will comply with any applicable emission limits in Section IX, Part H.11.
13.0 BACT for Diesel- and Natural Gas-fired Emergency Engines HF Sinclair submitted an analysis for both diesel and natural gas-fired emergency engines13. The largest of these engines are a 540 hp diesel-fired standby generator and a pair of 142 kW natural gas-fired emergency engines. UDAQ has covered the analysis of both diesel-fired and natural gas fired emergency engines in a separate document. Please refer to the PM2.5 Serious SIP - BACT for Small Sources – Section 8 for additional details.
14.0 Additional Ammonia Considerations
HF Sinclair has direct ammonia emissions beyond the ammonia slip from SCR control systems. Sour water containing ammonia is drained from process vessels throughout the refinery into an enclosed drain system which is then piped into Storage Tank 166. The sour water is then pumped
to the sour water stripper where steam is used to strip the ammonia from the sour water. The ammonia vapors are then sent to the ammonia stripping unit. 14.1 Ammonia (NH3) 14.1.1 Available Control Technology
The only add-on control system found to reduce ammonia emissions is the use of a WGS – specifically the packed tower style of wet scrubber. Venturi style scrubbers have not been shown effective. Condensers can convert ammonia vapors into a liquid which can then be removed through liquid disposal. 14.1.2 Evaluation of Technical Feasibility of Available Controls
The ammonia vapors from the sour water stripper are mixed with water in the ammonia stripping unit forming ammonia liquid. No add-on controls are considered technically feasible for further control, as this liquid is not primarily in the vapor phase. The ammonia liquid is stored in
horizontal, high-pressure, storage vessels (Tanks 124 and 125) with no anticipated emissions. 14.1.3 Evaluation and Ranking of Technically Feasible Controls
Some ammonia emissions from the sour water stripper and ammonia stripper are inevitable and cannot be captured or collected. Efficiency concerns make the use of additional condensers or
WGS non-viable from both a technical and economic basis. Only best management practices and good general maintenance are effective controls for these emissions. 14.1.4 Further Evaluation of Most Effective Controls

13 see References: Item #7

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As no additional controls have been shown to feasible, no additional analysis is required.
14.1.5 Selection of BACT Controls
UDAQ recommends that HF Sinclair continue to use the existing sour water stripper and ammonia stripper units to reduce ammonia emissions from the refinery. Best management practices and proper maintenance shall be considered BACT for these units. No additional
limitations or requirements are necessary. 15.0 Additional Feasible Measures and Most Stringent Measures 15.1 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)
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).
15.2 Additional Feasible Measures at HF Sinclair
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.
15.3 Most Stringent Measures at HF Sinclair
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:

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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. 15.3.1 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:
Table 15-1: 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, WGS-LoTOx
Heaters/Boilers NOx ULNB, SCR
Ammonia only if SCR is used, feedback controls Flares Flare Gas flare minimization program SRU SO2 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 IAF/API separator; 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. 15.3.2 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 Technical Support Document (TSD) that included

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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 HF Sinclair.
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 HF Sinclair in its BACT analysis report. This was the deferment of VOC
controls for the wastewater treatment systems at four Salt Lake City area refineries. HF Sinclair did include an analysis of the wastewater treatment system, and took into account previous steps (such as the API and carbon absorption) previously undertaken to reduce emissions. This
updated analysis has been reviewed as part of the UDAQ BACT review in Section 11 above. 15.3.3 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 15-2: 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, WGS-LoTOx See below
Heaters/Boilers NOx ULNB, SCR See below

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Ammonia NH3 feedback See below
Flares Flare Gas flare minimization program Yes
SRU SO2 TGTU or WGS See below NOx WGS-LoTOx See below 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. One particular example of this is the application 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). HF Sinclair has chosen the WGS solution for primary control of both the SRU and FCCUs at the refinery. This control choice has effectively eliminated the option of installing a TGTU on the SRU, or installing an alternate form of particulate control on the FCCUs.
16.0 New 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.
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.

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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 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 (defined as all non-dedicated SRU flare and header systems and all non-HF flare and header systems) are subject to Subpart Ja as of January 1, 2018 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 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. IX.H.11.g.vi This condition requires that vapor control devices be employed during tank

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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. 16.1 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 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. 16.2 Discussion of Attainment Demonstration

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PM Discussion: While the new PM limit on the FCCU might not appear to directly affect PM2.5
emissions, this would be incorrect. The limit is derived from the current NSPS (Subpart Ja). Under the NSPS, the assumption was that all particulate captured in the reference test method (Method 5, 5b or 5f) would be considered as PM2.5. This is still the case, as compliance with the
PM limit at the FCCU shall be demonstrated by stack test. Using a method 5 variant stack test allows the test to be overly conservative, as some particulate captured may fall outside the PM2.5 size range, and still be useful for SIP planning purposes. At the same time, it lowers the
regulatory burden on the sources, by allowing each source to only have to comply with the requirements of the individual NSPS. The limit is expressed on a 3-hour block average, well below the 24-hour basis of the PM2.5 standard. Stack tests are required every three (3) years, which meets the minimum stack test frequency set by DAQ. Compliance is demonstrated via monitoring and use of emission factors. Stack testing serves to periodically adjust emission factors to account for significant changes in feedstocks, refinery turnarounds, or other large-scale changes that would affect the emission factor. As allowed under R307-165-2, the Director may require stack testing at any time to demonstrate compliance.
SO2 Discussion: This is a new limitation that did not previously appear in any form in the original PM10 SIP. Although the limit is expressed on a 7-day rolling average basis, and therefore
longer than the 24-hour PM2.5 standard, SO2 emissions are eventually converted into sulfates – the particulate form. As this process takes some time to occur, and is not directly dependent on hourly or daily SO2 emissions – but rather on area average SO2 concentrations and relative
chemistry – a 7-day rolling average is quite adequate to demonstrate attainment with the standard. This is especially true, given the overall daily SIP Cap – which still controls total SO2 emissions from the entire refinery. The secondary limit, expressed on a 365-day basis simply serves to keep
SO2 emissions down over the long run, as well as maintaining consistency with the PM2.5 SIP requirements.
H2S Discussion: Although the limit appears to be on a much longer averaging period than the 24-hour PM2.5 standard, the rolling 365-day calculation prevents the overall H2S content from increasing. This in turn keeps the amount of sulfur being sent to each fuel burning device consistently low. This is also a fallback limit, like the SO2 emissions from the FCCU discussed in the previous paragraph. Total SO2 emissions are still controlled by the daily SIP Cap, regardless of the averaging period on fuel gas H2S content. 17.0 New PM2.5 SIP – HF Sinclair Specific Requirements
The HF Sinclair specific conditions in Section IX.H.12 address those limitations and requirements that apply only to the HF Sinclair Refinery in particular. The following controls
were determined as necessary for the PM2.5 SIP to satisfy BACT. IX.H.12.g.i This condition establishes NOx emission limits for nine combustion units at HF
Sinclair. 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.g.v Listing of required emission controls. Shown in table format, all emission controls which were determined to be BACT are listed in this condition.

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17.1 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.g.i through IX.H.12.g.iv. 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.g to address specific concerns. 18.0 References 1. Holly, PM2.5 SIP Major Point Source RACT Documentation – Holly Refinery 2. Holly Frontier – response to information request, dated April 25, 2014
3. Holly Frontier – additional information, dated May 5, 2014 4. UDSHW Contract No. 12601, Work Assignment No. 7, Utah PM2.5 SIP RACT Support – TechLaw Inc.
5. Holly NOI dated April 22, 2013 6. DAQE-AN101230041-13 7. Holly Frontier – Best Available Control Measure Analysis for Holly Frontier’s Woods Cross
Refinery, dated April 28, 2017 8. Holly Frontier – Response to Request DAQE-066-17, dated October 24, 2017 9. Final Holly Corp - Woods Cross Operation 10123 PM2.5 SIP BACT.xlsx
Additional references reviewed during UDAQ BACT research:
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Presentation.pdf
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BACT Clearinghouse (Searchable). (n.d.). Retrieved from http://www.valleyair.org/busind/pto/bact/bactLoader.htm

37
bact_boilheatfurn.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_b
oilheatfurn.pdf
bact_bulkgasterm.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_b
ulkgasterm.pdf
bact_cooltow.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_c
ooltow.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
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bact_fugitives.pdf. (n.d.). Retrieved from
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bact_loading.pdf. (n.d.-a). Retrieved from
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bact_loading.pdf. (n.d.-b). Retrieved from
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bact_processfurn.pdf. (n.d.). Retrieved from
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bact_sru.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/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 VERIFICATION
REPORT, NOX CONTROL TECHNOLOGIES, CATALYTICA COMBUSTION SYSTEMS, INC., XONON FLAMELESS COMBUSTION SYSTEM. Retrieved October 17, 2017, from

38
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 |
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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
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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_cooltow.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
NSR Guidance for Fluid Catalytic Cracking Units (FCCU). (n.d.). Retrieved from
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NSR Guidance for Internal Combustion Engines. (n.d.). Retrieved from https://www.tceq.texas.gov/permitting/air/guidance/newsourcereview/engine/nsr_fac_engine.html
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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

39
https://www.tceq.texas.gov/permitting/air/guidance/newsourcereview/sulfur/nsr_fac_sru.html
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PM2.5 SIP Evaluation Report: HF Sinclair Woods Cross Refinery Salt Lake City PM2.5 Serious Nonattainment Area Utah Division of Air Quality Major New Source Review Section Appendix A
HF Sinclair Refinery Emission Unit Monitoring
Emission Unit Capacity Controls
AO
Conditions[1]SIP Conditions Monitoring Established Emission Limit Basis of Limit
FCCU #1 Unit 4 8,880 bpd WGS II.B.8 Yes CEMs/Stack Test
40 ppm NOx (7-day rolling average)
22.5 ppm NOx (365-day rolling average)80 ppm NOx (7-day rolling average)?
40 ppm NOx (365-day rolling average)?50 ppm SO2 (7-day rolling average)25 ppm SO2 (365-day rolling average)0.50 lb/1000 lb coke burned Filterable PM10
NSPS Subpart Ja
FCC Feed Heater #1 4H1
68.4 MMBtu/hr
(restricted to 39.9) LNB II.B.9 -- -- -- No limit in new requirements - BACT included in HF Sinclair TSDReformer charge and reheater furnace/waste boiler 6H1 54.7 MMBtu/hr -- -- NOx Limit (new) Stack Test (new) 0.15 lb/MMBtu Based on SLEIS-reported NOx emission factor (originating from AP-42)
Prefractionator Reboiler Heater 6H2 12.0 MMBtu/hr -- -- -- -- --
No limit in new requirements - BACT included in small source BACT documentReformer reheat furnace 6H3 37.7 MMBtu/hr -- -- -- -- -- No limit in new requirements - BACT included in HF Sinclair TSD
HF Alkylation Regeneration Furnace 7H1 4.4 MMBtu/hr -- -- -- -- --
No limit in new requirements - BACT included in small source BACT document
HF Alkylation Depropanizer Reboiler 7H3 33.3 MMBtu/hr -- -- -- -- -- No limit in new requirements - BACT included in HF Sinclair TSD
Crude Furnace #1 8H2 99.0 MMBtu/hr LNB II.B.6 NOx Limit (new) Stack Test
0.04 lb/MMBtu NOx
0.007 lb/MMBtu PM10 Established in AO through UDAQ BACT process
Distillate Hydrosulfurization Unit Reactor Charge Heater (DHDS) 9H1 8.1 MMBtu/hr -- -- -- -- --
No limit in new requirements - BACT included in small source BACT document
DHDS Stripper Reboiler 9H2 4.1 MMBtu/hr -- -- -- -- --
No limit in new requirements - BACT included in small source BACT document
Asphalt Mix Heater 10H1 13.2 MMBtu/hr -- -- -- -- --
No limit in new requirements - BACT included in small source BACT document
Hot Oil Furnace 10H2 (never constructed & removed from permits) 99.0 MMBtu/hr LNB; SCR II.B.6 N/A N/A
0.02 lb/MMBtu NOx0.007 lb/MMBtu PM10 Was never constructed and removed from permits
Straight Run Gas Plant (SRGP) Depentanizer Reboiler 11H1 24.2 MMBtu/hr -- -- -- -- --
No limit in new requirements - BACT included in small source BACT documentNaptha Hydrodesulphurization (NHDS) Unit Reactor Charge Furnace 12H1 50.2 MMBtu/hr ULNB II.B.6 NOx Limit (new) Stack Test 0.10 lb/MMBtu NOx Established in AO through UDAQ BACT process
Isomerization Reactor Feed Furnace 13H1 6.5 MMBtu/hr -- -- -- -- --
No limit in new requirements - BACT included in small source BACT document
SRU with Tailgas Incinerator 20 LTPD Tailgas Incinerator; WGS II.B.11 -- -- --
Established in AO through UDAQ BACT process - emissions from this process are required to be routed through either FCCU WGS system
before being vented to the atmosphere
Distillate Hydrodesulfurization Treatment (DHT) Reactor Charge Heater 19H123.0 MMBtu/hr LNB II.B.6 -- Stack Test
0.007 lb/MMBtu PM100.0054 lb/MMBtu VOCs No limit in new requirements - BACT included in small source BACT document
DHT Reactor Charge Heater 19H2 (never constructed & removed from permits)40.0 MMBtu/hr ULNB II.B.6 N/A N/A
0.04 lb/MMBtu NOx0.007 lb/MMBtu PM10
0.0054 lb/MMBtu VOCs
Was never constructed and removed from permits
Fractionator Charge Heater 20H2 47.0 MMBtu/hr LNB II.B.6 NOx Limit (new) Stack Test (new)
0.007 lb/MMBtu PM10 (existing)
0.04 lb/MMBtu NOx (new) Based on SLEIS-reported NOx emission factor (originating from AP-42)
Fractionator Charge Heater 20H3 39.7 MMBtu/hr LNB II.B.6 -- Stack Test
0.04 lb/MMBtu NOx
0.007 lb/MMBtu PM100.0054 lb/MMBtu VOCs No limit in new requirements - BACT included in HF Sinclair TSD
Crude Unit Furnace 24H1 60.0 MMBtu/hr
(restricted to 32.5)LNB II.B.6 -- Stack Test
0.04 lb/MMBtu NOx0.007 lb/MMBtu PM100.0054 lb/MMBtu VOCs No limit in new requirements - BACT included in HF Sinclair TSD
FCCU #2 Unit 25 8,500 bpd WGS; LoTOx II.B.8 Yes CEMs/Stack Test
80 ppm NOx (7-day rolling average)40 ppm NOx (365-day rolling average)50 ppm SO2 (7-day rolling average)25 ppm SO2 (365-day rolling average)0.50 lb/1000 lb coke burned Filterable PM10
0.3 lb/1000 lb Filterable PM100.60 lb/1000 lb coke burned Total PM10
NSPS Subpart Ja
FCC Feed Heater #2 25H1 17.7 MMBtu/hr LNB II.B.6 -- Stack Test
0.04 lb/MMBtu NOx
0.007 lb/MMBtu PM100.0054 lb/MMBtu VOCs
No limit in new requirements - BACT included in small source BACT
document
Vacuum Furnace Heater 33H1 (never constructed & removed from permits) 130.0 MMBtu/hr LNB; SCR II.B.6 N/A N/A
0.02 lb/MMBtu NOx0.007 lb/MMBtu PM100.0054 lb/MMBtu VOCs Was never constructed and removed from permits
Boiler #4 35.6 MMBtu/hr -- -- -- -- -- No limit in new requirements - BACT included in HF Sinclair TSDBoiler #5 70.0 MMBtu/hr SCR II.B.6 NOx Limit (new) Stack Test 0.02 lb/MMBtu NOx Established in AO through UDAQ BACT process
Boiler #8 92.7 MMBtu/hr LNB; SCR II.B.6 NOx Limit (new) Stack Test
0.02 lb/MMBtu NOx0.007 lb/MMBtu PM10 Established in AO through UDAQ BACT process
Boiler #9 89.3 MMBtu/hr SCR II.B.6 NOx Limit (new) Stack Test
0.02 lb/MMBtu NOx0.007 lb/MMBtu PM10 Established in AO through UDAQ BACT process
Boiler #10 89.3 MMBtu/hr SCR II.B.6 NOx Limit (new) Stack Test
0.02 lb/MMBtu NOx0.007 lb/MMBtu PM10 Established in AO through UDAQ BACT process
Boiler #11 89.3 MMBtu/hr LNB; SCR II.B.6 NOx Limit (new) Stack Test
0.02 lb/MMBtu NOx0.007 lb/MMBtu PM100.004 lb/MMBtu VOCs Established in AO through UDAQ BACT process
Cooling Towers -- Drift Eliminators II.B.12 -- -- -- --North Flare -- FGR System II.B.1.g SO2 Limit CEMs 162 ppm H2S (3-hour rolling average) NSPS Subpart Ja
South Flare -- FGR System II.B.1.g SO2 Limit CEMs 162 ppm H2S (3-hour rolling average) NSPS Subpart JaTank Farm Varies Varies based on type -- -- -- Varies Various requirements based on federal regulation applicabilityLoading/Unloading Varies Varies -- -- -- -- VariesEmergency Equipment Varies Varies II.B.13 -- -- -- Equipment subject to various federal and general regulationsFugitive Emissions N/A Federal Regulations -- -- -- Federal Regulations No conditions included in AO; follow federal regulations and LDAR
Amine Treatment Unit Unit 16 -- -- II.B.10 CEMs CEMs
162 ppm H2S (3-hour rolling average)60 ppm H2S (365-day rolling average)NSPS Subpart Ja
[1] AO DAQE-AN101230053-22
[2] Applicable federal regulations:
NSPS Subpart A: General Provisions
NSPS Subpart Db: Industrial-Commercial-Institutional Steam Generating Units
NSPS Subpart Dc: Small Industrial-Commercial-Institutional Steam Generating Units
NSPS Subpart J: Petroleum Refineries
NSPS Subpart Ja: Petroleum Refineries after 5/14/07
NSPS Subpart K: Storage Vessels 6/11/73-5/19/78NSPS Subpart Kb: Storage Vessels for Petroleum Liquids after 7/23/84
NSPS Subpart UU: Asphalt Processing and Asphalt Roofing ManufactureNSPS 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
NSPS Subpart JJJJ: Stationary SI Internal Combustion Engines
NESHAP Subpart A: General Provisions
NESHAP Subpart FF: Benzene Waste OperationsMACT Subpart A: General Provisions
MACT Subpart R: Gasoline Distribution Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations)MACT Subpart CC: Petroleum Refineries
MACT Subpart UUU: Petroleum Refineries: Unit Specific
MACT Subpart ZZZZ: Stationary RICE
MACT Subpart GGGGG: Site Remediation
PM2.5 SIP Evaluation Report: HF Sinclair Woods Cross Refinery 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
HF Sinclair Refinery
Total Data Entries 76,727 Min (ppm) -0.04 Min (ppm) 0.0002 Min (ppm) -0.04 Min (ppm) 0.0002
Total Invalid Hour Entries 74 Max (ppm) 943.1 Max (ppm) 943 Max (ppm) 162 Max (ppm) 162
% Total Invalid Hour Entries 0.10% Average (ppm) 31.24 Average (ppm) 31.35 Average (ppm) 23.13 Average (ppm) 23.21
% Un-Matched Data 35.39% Standard Deviation 51.07 Standard Deviation 51.12 Standard Deviation 20.24 Standard Deviation 20.23
%Un-Matched Bad Data 4.29%
Limit (ppm H2S) 162 10th 2.6 10th 2.8 10th 2.4 10th 2.573450184
Total Data Entries = 0 252 20th 6.4 20th 6.5 20th 6.2 20th 6.285427772
% Total Data Entries = 0 0.33% 30th 10.9 30th 11.0 30th 10.5 30th 10.56567245
Total Data Entries > Limit 2,401 40th 16.0 40th 16.1 40th 15.3 40th 15.36666667
% Total Data Entries > Limit 3.13% 50th 20.6 50th 20.7 50th 19.9 50th 19.97216364
60th 25.8 60th 25.9 60th 24.8 60th 24.9
70th 30.9 70th 31.0 70th 29.8 70th 29.86666667
Total Data Entries 3,197 80th 37.0 80th 37.1 80th 35.3 80th 35.4
Total Invalid Hour Entries 0 90th 50.1 90th 50.2 90th 44.3 90th 44.37429476
% Total Invalid Hour Entries 0.00% 97th 172.6 97th 173.5 97th 68.1 97th 68.2
% Un-Matched Data 50.33% 99th 300.0 99th 300.0 99th 103.4 99th 103.5
%Un-Matched Bad Data 1.38%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 30,754 40.12% <10% of Limit 16 30,502 39.92% <10% of Limit 16 30,754 41.42% <10% of Limit 16 30,502 41.22%
Total Data Entries = 0 0 <20% of Limit 32 55,199 72.01% <20% of Limit 32 54,947 71.92% <20% of Limit 32 55,199 74.34% <20% of Limit 32 54,947 74.25%
% Total Data Entries = 0 0.00% <30% of Limit 49 68,690 89.61% <30% of Limit 49 68,438 89.58% <30% of Limit 49 68,690 92.51% <30% of Limit 49 68,438 92.48%
Total Data Entries > Limit 256 <40% of Limit 65 71,703 93.54% <40% of Limit 65 71,451 93.52% <40% of Limit 65 71,703 96.57% <40% of Limit 65 71,451 96.56%
% Total Data Entries > Limit 8.01% <50% of Limit 81 72,851 95.04% <50% of Limit 81 72,599 95.02% <50% of Limit 81 72,851 98.11% <50% of Limit 81 72,599 98.11%
<60% of Limit 97 73,377 95.73% <60% of Limit 97 73,125 95.71% <60% of Limit 97 73,377 98.82% <60% of Limit 97 73,125 98.82%
<70% of Limit 113 73,694 96.14% <70% of Limit 113 73,442 96.13% <70% of Limit 113 73,694 99.25% <70% of Limit 113 73,442 99.25%
<80% of Limit 130 73,924 96.44% <80% of Limit 130 73,672 96.43% <80% of Limit 130 73,924 99.56% <80% of Limit 130 73,672 99.56%
<90% of Limit 146 74,087 96.65% <90% of Limit 146 73,835 96.64% <90% of Limit 146 74,087 99.78% <90% of Limit 146 73,835 99.78%
<=100% of Limit 162 74,252 96.87% <=100% of Limit 162 74,000 96.86% <=100% of Limit 162 74,252 100.00% <=100% of Limit 162 74,000 100.00%
Min (ppm) 5.06
Max (ppm) 78.2
Average (ppm) 30.76
Standard Deviation 16.01
10th 14.6
20th 18.2
30th 22.1
40th 24.9
50th 30.0
60th 32.0
70th 33.1
80th 36.5
90th 56.8
97th 70.1
99th 76.7
Percentage of Limit Value (ppm) Total Data Points % of Total Data
<10% of Limit 6 120 3.75%
<20% of Limit 12 257 8.04%
<30% of Limit 18 623 19.49%
<40% of Limit 24 1,114 34.85%
<50% of Limit 30 1,593 49.83%
<60% of Limit 36 2,552 79.82%
<70% of Limit 42 2,613 81.73%
<80% of Limit 48 2,666 83.39%
<90% of Limit 54 2,834 88.65%
<=100% of Limit 60 2,941 91.99%
Data Analysis - Excluding All Data <= 0 (3-Hr Average) 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):
Data Verification - Daily/365-Day Average
Data Analysis - All Data Included (365-Day Averages)
Percentiles (ppm):
Data Verification Data Analysis - All Data Included
UDAQ 2023 Data Request - UDAQ Analysis and Summary
FCCU 4 NOx - Rolling 7-Day Average
HF Sinclair Refinery
Total Data Entries 3,197 Min (ppm) -16.86 Min (ppm) 0.66 Min (ppm) -16.86 Min (ppm) 0.66
Total Invalid Hour Entries 110 Max (ppm) 193.99 Max (ppm) 193.99 Max (ppm) 77.40 Max (ppm) 77.40
% Total Invalid Hour Entries 3.44% Average (ppm) 27.11 Average (ppm) 27.21 Average (ppm) 26.32 Average (ppm) 26.41
% Un-Matched Data 68.00% Standard Deviation 15.04 Standard Deviation 14.91 Standard Deviation 11.93 Standard Deviation 11.77
%Un-Matched Bad Data (>1) 60.71%
%Un-Matched Bad Data (>5) 26.87% 10th 14.07 10th 14.34 10th 14.05 10th 14.16
%Un-Matched Bad Data (>7) 20.43% 20th 15.09 20th 15.09 20th 15.08 20th 15.09
Limit (ppm NOx) 80 30th 16.87 30th 16.96 30th 16.79 30th 16.84
Total Data Entries = 0 7 40th 22.20 40th 22.21 40th 22.17 40th 22.17
% Total Data Entries = 0 0.22% 50th 24.49 50th 24.54 50th 24.36 50th 24.37
Total Data Entries > Limit 26 60th 29.37 60th 29.40 60th 29.15 60th 29.19
% Total Data Entries > Limit 0.81% 70th 33.73 70th 33.75 70th 33.63 70th 33.63
80th 36.98 80th 37.00 80th 36.78 80th 36.79
90th 41.22 90th 41.25 90th 40.75 90th 40.76
97th 51.63 97th 51.64 97th 49.21 97th 49.23
99th 74.03 99th 74.04 99th 59.71 99th 59.72
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 8.00 80 2.59% <10% of Limit 8.00 73 2.37% <10% of Limit 8.00 80 2.61% <10% of Limit 8.00 73 2.39%
<20% of Limit 16.00 817 26.47% <20% of Limit 16.00 810 26.30% <20% of Limit 16.00 817 26.69% <20% of Limit 16.00 810 26.52%
<30% of Limit 24.00 1,503 48.69% <30% of Limit 24.00 1,496 48.57% <30% of Limit 24.00 1,503 49.10% <30% of Limit 24.00 1,496 48.98%
<40% of Limit 32.00 1,993 64.56% <40% of Limit 32.00 1,983 64.38% <40% of Limit 32.00 1,993 65.11% <40% of Limit 32.00 1,983 64.93%
<50% of Limit 40.00 2,724 88.24% <50% of Limit 40.00 2,716 88.18% <50% of Limit 40.00 2,724 88.99% <50% of Limit 40.00 2,716 88.93%
<60% of Limit 48.00 2,957 95.79% <60% of Limit 48.00 2,950 95.78% <60% of Limit 48.00 2,957 96.60% <60% of Limit 48.00 2,950 96.59%
<70% of Limit 56.00 3,023 97.93% <70% of Limit 56.00 3,016 97.92% <70% of Limit 56.00 3,023 98.76% <70% of Limit 56.00 3,016 98.76%
<80% of Limit 64.00 3,035 98.32% <80% of Limit 64.00 3,028 98.31% <80% of Limit 64.00 3,035 99.15% <80% of Limit 64.00 3,028 99.15%
<90% of Limit 72.00 3,053 98.90% <90% of Limit 72.00 3,046 98.90% <90% of Limit 72.00 3,053 99.74% <90% of Limit 72.00 3,046 99.74%
<=100% of Limit 80.00 3,061 99.16% <=100% of Limit 80.00 3,054 99.16% <=100% of Limit 80.00 3,061 100.00% <=100% of Limit 80.00 3,054 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data <= 0 (7-Day Average) Data Analysis - Excluding All Data > 80 (7-Day Average) Data Analysis - Excluding All Data = 0 and > 80 (7-Day Average)
UDAQ 2023 Data Request - UDAQ Analysis and Summary
FCCU 4 SO2 - Rolling 7-Day Average
HF Sinclair Refinery
Total Data Entries 3,197 Min (ppm) 0.00 Min (ppm) 0.00 Min (ppm) 0.00 Min (ppm) 0.00
Total Invalid Hour Entries 92 Max (ppm) 358.87 Max (ppm) 358.87 Max (ppm) 49.40 Max (ppm) 49.40
% Total Invalid Hour Entries 2.88% Average (ppm) 4.89 Average (ppm) 5.67 Average (ppm) 3.45 Average (ppm) 4.06
% Un-Matched Data 82.30% Standard Deviation 18.44 Standard Deviation 19.74 Standard Deviation 7.12 Standard Deviation 7.57
%Un-Matched Bad Data (>1) 34.41%
%Un-Matched Bad Data (>5) 15.83% 10th 0.00 10th 0.04 10th 0.00 10th 0.04
%Un-Matched Bad Data (>7) 11.54% 20th 0.03 20th 0.11 20th 0.01 20th 0.11
Limit (ppm NOx) 50 30th 0.10 30th 0.30 30th 0.09 30th 0.29
Total Data Entries = 0 426 40th 0.31 40th 0.60 40th 0.27 40th 0.56
% Total Data Entries = 0 13.32% 50th 0.66 50th 1.03 50th 0.61 50th 0.99
Total Data Entries > Limit 40 60th 1.31 60th 1.86 60th 1.17 60th 1.74
% Total Data Entries > Limit 1.25% 70th 2.53 70th 3.33 70th 2.29 70th 3.04
50th 5.00 50th 5.94 50th 4.67 50th 5.47
90th 11.12 90th 12.76 90th 9.67 90th 11.44
97th 34.49 97th 36.43 97th 25.51 97th 30.21
99th 58.33 99th 60.55 99th 37.25 99th 38.03
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 5.00 2,486 80.06% <10% of Limit 5.00 2,058 76.82% <10% of Limit 5.00 2,486 81.11% <10% of Limit 5.00 2,058 77.98%
<20% of Limit 10.00 2,761 88.92% <20% of Limit 10.00 2,335 87.16% <20% of Limit 10.00 2,761 90.08% <20% of Limit 10.00 2,335 88.48%
<30% of Limit 15.00 2,961 95.36% <30% of Limit 15.00 2,437 90.97% <30% of Limit 15.00 2,863 93.41% <30% of Limit 15.00 2,437 92.35%
<40% of Limit 20.00 2,934 94.49% <40% of Limit 20.00 2,508 93.62% <40% of Limit 20.00 2,934 95.73% <40% of Limit 20.00 2,508 95.04%
<50% of Limit 25.00 2,966 95.52% <50% of Limit 25.00 2,540 94.81% <50% of Limit 25.00 2,966 96.77% <50% of Limit 25.00 2,540 96.25%
<60% of Limit 30.00 2,986 96.17% <60% of Limit 30.00 2,560 95.56% <60% of Limit 30.00 2,986 97.42% <60% of Limit 30.00 2,560 97.01%
<70% of Limit 35.00 3,020 97.26% <70% of Limit 35.00 2,594 96.83% <70% of Limit 35.00 3,020 98.53% <70% of Limit 35.00 2,594 98.29%
<50% of Limit 40.00 3,049 98.20% <50% of Limit 40.00 2,623 97.91% <50% of Limit 40.00 3,049 99.48% <50% of Limit 40.00 2,623 99.39%
<90% of Limit 45.00 3,058 98.49% <90% of Limit 45.00 2,632 98.25% <90% of Limit 45.00 3,058 99.77% <90% of Limit 45.00 2,632 99.73%
<=100% of Limit 50.00 3,065 98.71% <=100% of Limit 50.00 2,639 98.51% <=100% of Limit 50.00 3,065 100.00% <=100% of Limit 50.00 2,639 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data <= 0 (7-Day Average) Data Analysis - Excluding All Data > 50 (7-Day Average) Data Analysis - Excluding All Data = 0 and > 50 (7-Day Average)
UDAQ 2023 Data Request - UDAQ Analysis and Summary
FCCU 25 NOx - Rolling 7-Day Average
HF Sinclair Refinery
Total Data Entries 2,664 Min (ppm) 0.00 Min (ppm) 2.90 Min (ppm) 0.00 Min (ppm) 2.90
Total Invalid Hour Entries 146 Max (ppm) 200.60 Max (ppm) 200.60 Max (ppm) 79.96 Max (ppm) 79.96
% Total Invalid Hour Entries 5.48% Average (ppm) 24.15 Average (ppm) 24.22 Average (ppm) 23.57 Average (ppm) 23.48
% Un-Matched Data 15.92% Standard Deviation 13.91 Standard Deviation 13.87 Standard Deviation 10.12 Standard Deviation 10.05
%Un-Matched Bad Data (>0.1) 8.93%
%Un-Matched Bad Data (>1) 5.07% 10th 16.46 10th 16.49 10th 16.44 10th 16.48
%Un-Matched Bad Data (3) 3.90% 20th 17.56 20th 17.56 20th 17.55 20th 17.56
Limit (ppm NOx) 80 30th 17.89 30th 17.89 30th 17.87 30th 17.89
Total Data Entries = 0 7 40th 18.37 40th 18.37 40th 18.36 40th 18.37
% Total Data Entries = 0 0.26% 50th 19.09 50th 19.09 50th 19.04 50th 19.06
Total Data Entries > Limit 17 60th 20.73 60th 20.77 60th 20.70 60th 20.71
% Total Data Entries > Limit 0.64% 70th 25.30 70th 25.30 70th 25.21 70th 25.21
80th 29.87 80th 29.87 80th 29.49 80th 29.51
90th 38.56 90th 38.57 90th 37.88 90th 37.97
97th 51.30 97th 51.34 97th 48.97 97th 48.97
99th 69.63 99th 69.65 99th 59.47 99th 59.47
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 8.00 27 1.07% <10% of Limit 8.00 20 0.80% <10% of Limit 8.00 27 1.08% <10% of Limit 8.00 20 0.80%
<20% of Limit 16.00 227 9.02% <20% of Limit 16.00 220 8.76% <20% of Limit 16.00 227 9.08% <20% of Limit 16.00 220 8.82%
<30% of Limit 24.00 1,625 64.54% <30% of Limit 24.00 1,616 64.36% <30% of Limit 24.00 1,625 64.97% <30% of Limit 24.00 1,616 64.80%
<40% of Limit 32.00 2,092 83.08% <40% of Limit 32.00 2,084 82.99% <40% of Limit 32.00 2,092 83.65% <40% of Limit 32.00 2,084 83.56%
<50% of Limit 40.00 2,297 91.22% <50% of Limit 40.00 2,290 91.20% <50% of Limit 40.00 2,297 91.84% <50% of Limit 40.00 2,290 91.82%
<60% of Limit 48.00 2,414 95.87% <60% of Limit 48.00 2,407 95.86% <60% of Limit 48.00 2,414 96.52% <60% of Limit 48.00 2,407 96.51%
<70% of Limit 56.00 2,466 97.93% <70% of Limit 56.00 2,459 97.93% <70% of Limit 56.00 2,466 98.60% <70% of Limit 56.00 2,459 98.60%
<80% of Limit 64.00 2,488 98.81% <80% of Limit 64.00 2,481 98.81% <80% of Limit 64.00 2,488 99.48% <80% of Limit 64.00 2,481 99.48%
<90% of Limit 72.00 2,497 99.17% <90% of Limit 72.00 2,490 99.16% <90% of Limit 72.00 2,497 99.84% <90% of Limit 72.00 2,490 99.84%
<=100% of Limit 80.00 2,501 99.32% <=100% of Limit 80.00 2,494 99.32% <=100% of Limit 80.00 2,501 100.00% <=100% of Limit 80.00 2,494 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data <= 0 (7-Day Average) Data Analysis - Excluding All Data > 80 (7-Day Average) Data Analysis - Excluding All Data = 0 and > 80 (7-Day Average)
UDAQ 2023 Data Request - UDAQ Analysis and Summary
FCCU 25 SO2 - Rolling 7-Day Average
HF Sinclair Refinery
Total Data Entries 2,664 Min (ppm) -3.40 Min (ppm) 0.24 Min (ppm) -3.40 Min (ppm) 0.24
Total Invalid Hour Entries 141 Max (ppm) 221.64 Max (ppm) 221.64 Max (ppm) 49.86 Max (ppm) 49.86
% Total Invalid Hour Entries 5.29% Average (ppm) 9.67 Average (ppm) 9.74 Average (ppm) 8.00 Average (ppm) 8.07
% Un-Matched Data 13.55% Standard Deviation 16.77 Standard Deviation 16.80 Standard Deviation 7.91 Standard Deviation 7.89
%Un-Matched Bad Data (>0.1) 8.52%
%Un-Matched Bad Data (>1) 5.33% 10th 1.10 10th 1.11 10th 1.10 10th 1.11
%Un-Matched Bad Data (3) 4.92% 20th 1.42 20th 1.43 20th 1.40 20th 1.43
Limit (ppm NOx) 50 30th 1.86 30th 1.88 30th 1.82 30th 1.86
Total Data Entries = 0 14 40th 2.39 40th 2.41 40th 2.36 40th 2.38
% Total Data Entries = 0 0.53% 50th 4.87 50th 4.96 50th 4.26 50th 4.53
Total Data Entries > Limit 38 60th 10.71 60th 10.76 60th 10.40 60th 10.50
% Total Data Entries > Limit 1.43% 70th 12.63 70th 12.66 70th 12.45 70th 12.49
50th 14.01 50th 14.02 50th 13.81 50th 13.84
90th 16.94 90th 16.94 90th 16.29 90th 16.34
97th 35.77 97th 35.77 97th 27.07 97th 27.20
99th 95.93 99th 96.67 99th 37.59 99th 37.63
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 5.00 1,270 50.34% <10% of Limit 5.00 1,255 50.02% <10% of Limit 5.00 1,270 51.11% <10% of Limit 5.00 1,255 50.79%
<20% of Limit 10.00 1,461 57.91% <20% of Limit 10.00 1,447 57.67% <20% of Limit 10.00 1,461 58.79% <20% of Limit 10.00 1,447 58.56%
<30% of Limit 15.00 2,142 84.90% <30% of Limit 15.00 2,126 84.73% <30% of Limit 15.00 2,142 86.20% <30% of Limit 15.00 2,126 86.04%
<40% of Limit 20.00 2,360 93.54% <40% of Limit 20.00 2,346 93.50% <40% of Limit 20.00 2,360 94.97% <40% of Limit 20.00 2,346 94.94%
<50% of Limit 25.00 2,396 94.97% <50% of Limit 25.00 2,382 94.94% <50% of Limit 25.00 2,396 96.42% <50% of Limit 25.00 2,382 96.40%
<60% of Limit 30.00 2,425 96.12% <60% of Limit 30.00 2,411 96.09% <60% of Limit 30.00 2,425 97.59% <60% of Limit 30.00 2,411 97.57%
<70% of Limit 35.00 2,443 96.83% <70% of Limit 35.00 2,429 96.81% <70% of Limit 35.00 2,443 98.31% <70% of Limit 35.00 2,429 98.30%
<50% of Limit 40.00 2,472 97.98% <50% of Limit 40.00 2,458 97.97% <50% of Limit 40.00 2,472 99.48% <50% of Limit 40.00 2,458 99.47%
<90% of Limit 45.00 2,479 98.26% <90% of Limit 45.00 2,464 98.21% <90% of Limit 45.00 2,479 99.76% <90% of Limit 45.00 2,464 99.72%
<=100% of Limit 50.00 2,485 98.49% <=100% of Limit 50.00 2,471 98.49% <=100% of Limit 50.00 2,485 100.00% <=100% of Limit 50.00 2,471 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data <= 0 (7-Day Average) Data Analysis - Excluding All Data > 50 (7-Day Average) Data Analysis - Excluding All Data = 0 and > 50 (7-Day Average)
UDAQ 2023 Data Request - UDAQ Analysis and Summary
North Flare H2S - Rolling 3-Hour Average
HF Sinclair Refinery
Total Data Entries 69,192 Min (ppm) 0.00 Min (ppm) 0.03 Min (ppm) 0.00 Min (ppm) 0.03
Total Invalid Hour Entries 921 Max (ppm) 400.90 Max (ppm) 400.90 Max (ppm) 162.00 Max (ppm) 162.00
% Total Invalid Hour Entries 1.33% Average (ppm) 20.44 Average (ppm) 28.48 Average (ppm) 14.09 Average (ppm) 20.12
% Un-Matched Data 10.34% Standard Deviation 46.85 Standard Deviation 53.19 Standard Deviation 26.86 Standard Deviation 30.15
%Un-Matched Bad Data (>1) 7.47%
%Un-Matched Bad Data (3) 5.65% 10th 0.00 10th 1.07 10th 0.00 10th 1.00
%Un-Matched Bad Data (10) 4.54% 20th 0.00 20th 2.10 20th 0.00 20th 2.00
Limit (ppm H2S) 162 30th 0.10 30th 3.10 30th 0.03 30th 3.00
Total Data Entries = 0 19,275 40th 1.80 40th 4.40 40th 1.50 40th 4.20
% Total Data Entries = 0 27.86% 50th 3.10 50th 6.63 50th 2.87 50th 6.10
Total Data Entries > Limit 1,799 60th 5.20 60th 11.10 60th 4.60 60th 9.77
% Total Data Entries > Limit 2.60% 70th 10.00 70th 20.87 70th 8.50 70th 17.60
50th 24.30 50th 39.97 50th 19.20 50th 33.33
90th 59.70 90th 79.34 90th 46.75 90th 62.30
97th 149.18 97th 183.40 97th 96.80 97th 108.67
99th 277.09 99th 302.00 99th 129.94 99th 138.53
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 16.00 51,663 75.67% <10% of Limit 16.00 32,370 66.07% <10% of Limit 16.00 51,663 77.72% <10% of Limit 16.00 32,370 68.58%
<20% of Limit 32.00 56,718 83.08% <20% of Limit 32.00 37,433 76.40% <20% of Limit 32.00 56,718 85.33% <20% of Limit 32.00 37,433 79.31%
<30% of Limit 49.00 60,053 87.96% <30% of Limit 49.00 40,773 83.22% <30% of Limit 49.00 60,053 90.34% <30% of Limit 49.00 40,773 86.39%
<40% of Limit 65.00 62,037 90.87% <40% of Limit 65.00 42,758 87.27% <40% of Limit 65.00 62,037 93.33% <40% of Limit 65.00 42,758 90.59%
<50% of Limit 81.00 63,489 93.00% <50% of Limit 81.00 44,210 90.23% <50% of Limit 81.00 63,489 95.51% <50% of Limit 81.00 44,210 93.67%
<60% of Limit 97.00 64,460 94.42% <60% of Limit 97.00 45,184 92.22% <60% of Limit 97.00 64,460 96.97% <60% of Limit 97.00 45,184 95.73%
<70% of Limit 113.00 65,256 95.58% <70% of Limit 113.00 45,978 93.84% <70% of Limit 113.00 65,256 98.17% <70% of Limit 113.00 45,978 97.42%
<50% of Limit 130.00 65,802 96.38% <50% of Limit 130.00 46,526 94.96% <50% of Limit 130.00 65,802 98.99% <50% of Limit 130.00 46,526 98.58%
<90% of Limit 146.00 66,158 96.90% <90% of Limit 146.00 46,883 95.69% <90% of Limit 146.00 66,158 99.53% <90% of Limit 146.00 46,883 99.33%
<=100% of Limit 162.00 66,473 97.37% <=100% of Limit 162.00 47,196 96.33% <=100% of Limit 162.00 66,473 100.00% <=100% of Limit 162.00 47,196 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data <= 0 (3-Hr Average) Data Analysis - Excluding All Data > 162 (3-Hr Average) Data Analysis - Excluding All Data = 0 and > 162 (3-Hr Average)
UDAQ 2023 Data Request - UDAQ Analysis and Summary
South Flare H2S - Rolling 3-Hour Average
HF Sinclair Refinery
Total Data Entries 65,353 Min (ppm) 0.00 Min (ppm) 0.03 Min (ppm) 0.00 Min (ppm) 0.03
Total Invalid Hour Entries 660 Max (ppm) 316.00 Max (ppm) 316.00 Max (ppm) 161.70 Max (ppm) 161.70
% Total Invalid Hour Entries 1.01% Average (ppm) 5.18 Average (ppm) 8.60 Average (ppm) 4.69 Average (ppm) 7.89
% Un-Matched Data 4.83% Standard Deviation 17.88 Standard Deviation 22.39 Standard Deviation 14.73 Standard Deviation 18.42
%Un-Matched Bad Data (>1) 2.69%
%Un-Matched Bad Data (5) 1.27% 10th 0.00 10th 0.20 10th 0.00 10th 0.20
Limit (ppm H2S) 162 20th 0.00 20th 0.60 20th 0.00 20th 0.60
Total Data Entries = 0 25,738 30th 0.00 30th 0.70 30th 0.00 30th 0.70
% Total Data Entries = 0 39.38% 40th 0.03 40th 1.20 40th 0.00 40th 1.20
Total Data Entries > Limit 126 50th 0.50 50th 1.60 50th 0.40 50th 1.60
% Total Data Entries > Limit 0.19% 60th 0.80 60th 2.00 60th 0.80 60th 2.00
70th 1.60 70th 2.40 70th 1.50 70th 2.40
50th 2.23 50th 7.10 50th 2.20 50th 6.87
90th 10.83 90th 24.30 90th 10.30 90th 23.40
97th 47.57 97th 67.80 97th 44.43 97th 64.08
99th 88.81 99th 106.96 99th 82.37 99th 96.81
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 16.00 59,608 92.14% <10% of Limit 16.00 33,852 86.90% <10% of Limit 16.00 59,608 92.32% <10% of Limit 16.00 33,852 87.18%
<20% of Limit 32.00 61,686 95.35% <20% of Limit 32.00 35,944 92.27% <20% of Limit 32.00 61,686 95.54% <20% of Limit 32.00 35,944 92.57%
<30% of Limit 49.00 62,819 97.10% <30% of Limit 49.00 37,079 95.18% <30% of Limit 49.00 62,819 97.29% <30% of Limit 49.00 37,079 95.49%
<40% of Limit 65.00 63,429 98.05% <40% of Limit 65.00 37,690 96.75% <40% of Limit 65.00 63,429 98.24% <40% of Limit 65.00 37,690 97.07%
<50% of Limit 81.00 63,892 98.76% <50% of Limit 81.00 38,151 97.94% <50% of Limit 81.00 63,892 98.95% <50% of Limit 81.00 38,151 98.25%
<60% of Limit 97.00 64,182 99.21% <60% of Limit 97.00 38,443 98.69% <60% of Limit 97.00 64,182 99.40% <60% of Limit 97.00 38,443 99.01%
<70% of Limit 113.00 64,368 99.50% <70% of Limit 113.00 38,630 99.17% <70% of Limit 113.00 64,368 99.69% <70% of Limit 113.00 38,630 99.49%
<50% of Limit 130.00 64,466 99.65% <50% of Limit 130.00 38,727 99.41% <50% of Limit 130.00 64,466 99.84% <50% of Limit 130.00 38,727 99.74%
<90% of Limit 146.00 64,538 99.76% <90% of Limit 146.00 38,800 99.60% <90% of Limit 146.00 64,538 99.96% <90% of Limit 146.00 38,800 99.93%
<=100% of Limit 162.00 64,567 99.81% <=100% of Limit 162.00 38,829 99.68% <=100% of Limit 162.00 64,567 100.00% <=100% of Limit 162.00 38,829 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data <= 0 (3-Hr Average) Data Analysis - Excluding All Data > 162 (3-Hr Average) Data Analysis - Excluding All Data = 0 and > 162 (3-Hr Average)
PM2.5 SIP Evaluation Report: HF Sinclair Woods Cross Refinery Salt Lake City PM2.5 Serious Nonattainment Area Utah Division of Air Quality Major New Source Review Section Appendix C
HF Sinclair 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)
Reformer Reheat Furnace 6H1 54.7 0.15 8,378 35.94 21.40 1.79 1.64 2.40 2.25
Crude Furnace #1 8H2 99.0 0.04 8,701 17.34 9.83 3.23 1.00E-04 4.34 3.17
NHDS Reactor Charge Furnace 12H1 50.2 0.10 8,494 21.99 7.31 1.64 0.83 2.20 1.12
Fractionator Charge Heater 20H2 47.0 0.04 8,736 8.23 6.28 1.53 2.00E-03 2.06 1.51
Boiler #5 70.0 0.02 6,090 6.13 0.19 2.28 0.23 3.07 0.31
Boiler #8 92.7 0.02 8,612 8.12 0.58 3.03 1.00E-04 4.06 1.43
Boiler #9 89.3 0.02 8,571 7.82 1.91 2.91 1.00E-04 3.91 2.65
Boiler #10 89.3 0.02 8,586 7.82 0.83 2.91 1.00E-04 3.91 2.70
Boiler #11[4]89.3 0.02 8,698 7.82 1.16 2.91 0.07 3.91 0.50
121.23 49.49 22.24 2.77 29.85 15.64
[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
[4] Emissions for Boiler #11 based on 2019 inventory (not installed in 2017)
Source-wide PM2.5 limit adopted by AQB July 1, 2018: 47.6 tons/yr
Source-wide NOx Limit adopted by AQB July 1, 2018: 347.1 tons/yr
Source-wide SO2 Limit adopted by AQB July 1, 2018: 110.3 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]