DAQ-2025-001203

PM2.5 SIP Evaluation Report: Chevron Products Company – Salt Lake 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 Chevron Products Company – Salt Lake 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 Chevron Products Company – Salt Lake 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. Chevron 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: Chevron Salt Lake Refinery (Chevron) Address: 2351 N 1100 W, Salt Lake City, Utah, Davis County
Owner/Operator: Chevron Products Company
UTM coordinates: 4,519,770 m Northing, 422,270 m Easting, Zone 12
1.2 Facility Process Summary The Chevron Refinery is a petroleum refinery with a nominal capacity of approximately 50,000
barrels per day of crude oil. The source consists of one FCCU, a delayed coking unit, a catalytic reforming unit, hydrotreating units and two sulfur recovery units. The source also has the usual assorted heaters, boilers, cooling towers, storage tanks, flares, and similar fugitive emissions.
The refinery operates with a flare gas recovery system on two of its three hydrocarbon flares. 1.3 Facility Criteria Air Pollutant Emissions Sources
The following is a listing of the main emitting units from the Chevron Refinery: Boiler #5 (Low-NOx, FGR) Boiler #6 (Low-NOx, FGR) Boiler #7 (Low-NOx, FGR) Cooling Tower #1 Cooling Tower #2

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Cooling Tower #3 Cooling Tower #4 (Grandfathered)
Crude Unit Furnace #1 (Low-NOx) Crude Unit Furnace #2 (Low-NOx) FCC Furnace #1
FCC Furnace #2 HDN Furnace #1 HDN Furnace #2
Reformer Furnace F-1 Reformer Furnace F-2 Reformer Furnace F-3 Alkylation Furnace (LNB) Coker Furnace HDS Furnace #1 (LNB) HDS Furnace #2 (LNB) VGO Furnace #1 (LNB)
VGO Furnace #2 (LNB) Amine Unit #1 Amine Unit #2
SRU #1 (Sulfur Recovery Unit #1) SRU #2 (Sulfur Recovery Unit #2) Tail Gas Treatment Unit and Tail Gas Incinerator #1
Tail Gas Treatment Unit and Tail Gas Incinerator #2 FCCU and Catalyst Regenerator Flameless Thermal Oxidizer
Coker Flare (Flare #1) FCCU Flare (Flare #2) Alkylation Flare (Flare #3)
Diesel-powered back-up equipment Three Reformer Compressor Drivers (natural gas-fired) Tank Farm Loading/Unloading Fugitives Wastewater Treatment Plant This is not meant to be a complete listing of all equipment which may be involved or required
during permitting activities at the refinery, rather it is a listing of all significant emission units or emission unit groups (such as the tank farm). See Appendix A for a more complete listing of all refinery emission units and emission unit groups. See Appendix B for supporting documentation
for all units with CEMs. Please note that these data 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, Chevron’s baseline actual emissions were determined to be the following (in tons per year)1: Table 1-1: Actual Emissions

1 see References: Item #11

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Pollutant Actual Emissions (Tons/Year)
PM2.5 32.9 SO2 23.9
NOx 375.6 VOC 298.1 NH3 8.9

The current PTE values for Chevron, 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-AN101190097-182) are as follows:
Table 1-2: Current Potential to Emit
Pollutant Potential to Emit (Tons/Year)
PM2.5 110.0 SO2 383.3 NOx 766.5
VOC 1,242.0 NH3 32.6*
* 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; other facilities were held to zero growth. This decision was largely based on source type, and how each source type operates. The refineries have reported to UDAQ as a production group that
they are operating at capacity and are not planning any production or major emission increases in the time frame covered by the SIP BACT analysis. For these reasons, UDAQ used zero growth for all projection years beyond the 2016 baseline inventory. For Chevron, between the years of 2015 and 2017, there were three NSR permitting actions that had effects requiring a modification to the listed equipment – while other permitting actions took place, the effects were either minimal, or would have no effect in projected actual emissions. In 2015, an AO was issued to incorporate consent decree required NOx limits on the FCCU
regenerator stack. In 2016, two additional AOs were issued, one to replace Boilers #1, #2 and #4 with new Boiler #7, while a second AO removed the use of HF polymer oil as fuel, placed limits

2 see References: Item #7

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on the reformer compressors, and made numerous other changes in various emission points (cooling tower #3, boilers #5 and #6, alky unit). All of these changes are included in the 2017
emission rows; and a summary of the modified emission totals for 2017 are shown below in Table 2-1. Table 2-1: Modeled Emission Values
Pollutant Actual Emissions (Tons/Year)
PM2.5 33.99 SO2 23.62 NOx 260.87 VOC 301.81
NH3 8.90

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.
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

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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 Process Heaters and Boilers: Boilers #5 and #6, Crude Unit Heaters #1 and #2, Alkylation Furnace, Coker Furnace, and FCC Unit Furnace
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. Although Boilers #1, #2 and #4 appear in the first emission table in the modeling input
spreadsheet, they do not appear in subsequent projection years. In 2016, Chevron replaced existing boilers #1, #2 and #4 with a new boiler (#7). This was completed in AO DAQE-AN101190094-16, where BACT for the new boiler was determined to be low-NOx burners and
flue gas recirculation (FGR). Existing boilers #5 and #6 have identical controls to #7. Both boilers #5 and #6 are 171 MMBtu/hr and fired on either refinery fuel gas or natural gas. Crude Unit Heaters #1 and #2 provide the first source of heat for the crude oil entering the refinery. They are also the largest furnaces in the refinery at a combined 245.1 MMBtu/hr and share a common stack. They currently use low NOx burners (LNB). The Alkylation Furnace and Coker Furnace are the largest heaters at the refinery not currently
using LNB or ultra-low-NOx burners (ULNB). The FCC Unit Furnaces were chosen as being representative of smaller-sized heaters.
These boilers and heaters were selected for the BACT analysis as being the most representative of

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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the various process items in this category, the largest and/or highest emitting units, and the most “uncontrolled.” Conducting the analysis on these units will provide the most cost effective $/ton
emission reductions for all fuel-fired process equipment (heaters and boilers) at the refinery. Table 4-1: 2017 Estimated Emissions – Process Heaters and Boilers
PM2.5 SO2 NOx VOC NH3
Boiler #5 2.4 0.008 15.5 1.7 0.8 Boiler #6 2.2 0.007 14.1 1.5 0.7
Crude Furnace #1 & #2 3.2 0.01 20.6 2.3 1.3
Alkylation Furnace 1.6 0.007 10.8 1.2 0.7
Coker Furnace 1.3 0.005 17.2 0.9 0.6
FCC Unit Furnaces #1 & #2 0.72 0.003 9.5 0.3 0.3
Originally the Alkylation Furnace was allowed to burn alkylation polymer oil as a SIP exemption. During NSR permitting for upgrades to the Alkylation Unit in 2016, the option to burn alkylation polymer was removed (DAQE-AN101190095-17). Thus, Chevron did not analyze this option in
its own analysis or its subsequent follow-up documentation. 4.1 PM2.5
No add-on controls for particulates were considered 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. Chevron did review the use of electrostatic precipitators (ESPs) and wet gas scrubbers (WGS) for particulate control. Chevron determined neither control was commercially available or technically feasible for control of particulate emissions. Good
combustion controls and use of gaseous fuels are considered the only available and technically feasible control option. 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. Chevron 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 4.2.1 Available Control Technology By consolidating all process heaters and boilers together into a single group for BACT
consideration DAQ is able to consider controls on some emissions from this group which would ordinarily be dropped as 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

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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. Chevron did review FGD as a possible control and also determined it had not been commercially accepted for use on gaseous fuel-fired sources.
Chevron also reviewed whether WGS could be used as an available control. Again, 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. WGS will not be considered further. 4.2.2 Evaluation of Technical Feasibility of Available Controls
N/A. These are standard limits which exist in two established federal requirements (NSPS subparts). Both limits have been met by Chevron with no concerns or issues being reported. 4.2.3 Evaluation and Ranking of Technically Feasible Controls The refinery is already subject to the requirements of Subpart J, and has been for some time.
During the review of the various RACT evaluations made as part of the moderate PM2.5 SIP, DAQ determined that the fuel gas H2S limit from Subpart Ja would apply equally to all refineries in the nonattainment area and elected to make this a refinery general requirement. Chevron has
been operating under this requirement since January 1, 2015. 4.2.4 Further Evaluation of Most Effective Controls
No additional evaluation is required. Chevron has been operating under both limits, and both limits are applicable to the source regardless of the status of the PM2.5 SIP. 4.2.5 Selection of BACT Controls UDAQ recommends that the Subpart Ja fuel gas H2S limit of 60 ppmv on a 365-day rolling average and the Subpart J fuel gas H2S limit of 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. Chevron 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. Chevron 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

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emission limits, and the basis of those limits. 4.3 NOx The following additional information was supplied on recent permitting actions for the equipment
in this section: DAQE-AN101190094-16 was issued for the replacement of existing boilers #1, 2, and 4 with a new boiler (#7). In this AO, BACT was determined to be low-NOx burners and flue gas
recirculation (FGR). New boiler #7 is subject to federal NSPS (40 CFR 60) Subparts A, Db, and Ja, and MACT (40 CFR 63 NESHAP) Subparts A and DDDDD. The installation of the new boiler does not trigger or change the applicability of any other federal requirements at the refinery. The AO DAQE-AN101190097-18 included additional changes for producing Tier 3 fuels, and reconfirmed BACT for several process heaters.
4.3.1 Available Control Technology Chevron evaluated the installation of ULNB and the application of selective catalytic reduction
(SCR) for the process heaters and boilers. Additional control options also include sorbent injection, SNCR, flue gas recirculation (FGR), and WGS with LoTOx. 4.3.2 Evaluation of Technical Feasibility of Available Controls Installing and operating ULNB is technically feasible. FGR, SCR and SNCR are all technically
feasible as retrofit controls, although specific space concerns, piping requirements or temperature needs may limit the technical usefulness of these control options on any particular heater or boiler. Sorbent injection is also technically feasible, but requires additional control equipment,
such as a baghouse, for capture of the reacted sorbent. FGR is specifically not viable on those process heaters and boilers already equipped with ULNB. The control technology is redundant, as ULNB already makes use of recirculation to lower NOx emissions by reducing oxygen content in the inlet gas. For those boilers not already equipped with ULNB, FGR can be a viable option if it is incorporated into the design of a new unit – especially those units where forced draft air preheating is used. While Chevron does use forced draft air preheating on four units at the refinery, FGR is not a viable technology for consideration.
Boilers #5 and #6 are already equipped with FGR for NOx control, and would therefore gain no additional benefit from this technology. The only other forced draft furnaces are F21001/2 in the Crude Unit. When FGR is retrofit onto an existing unit, the capacity of the unit is reduced as the
reduction in available oxygen lowers the maximum available power/steam output. The reduction can be mitigated somewhat with additional tuning and adjustments, but this becomes a case of diminishing returns. Thus, FGR can really only be retrofitted on units which have additional
fired capacity. Unfortunately, there is no additional capacity in the crude furnaces. FGR is eliminated as a control option.
SNCR has been eliminated on the basis of temperature control. SNCR systems are sensitive to temperature fluctuations and require sufficient residence time to allow for complete reaction between the ammonia/urea reagent and the NOx being controlled. Most of the heaters and boilers
are used with variable demand loads that create variable temperature exhaust zones that are difficult to control with an unforgiving system like SNCR. Often the exhaust temperature drops below the optimum range of SNCR effectiveness. SNCR is eliminated as a control option.

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SCR is a viable control option. The ammonia slip inherent with SCRs makes this a less desirable
control option due to ammonia also being considered a precursor emission for PM2.5. WGS is technically infeasible as has been discussed previously. WGS is primarily used for the
control of acid gases, and is only viable for control of NOx emissions once a LoTOx unit has been included. As the use of WGS has already been eliminated from consideration for control of SO2 and other acid gases, the additional expense of LoTOx does not improve or rectify this
situation. WGS will not be considered further. 4.3.3 Evaluation and Ranking of Technically Feasible Controls Ranking the remaining technically feasible controls based on their control effectiveness is the next step in the analysis. For the existing units at the refinery, Chevron analyzed retrofitting ULNB and SCR as controls
based on emission rates for new facilities of 0.01 lb/MMBtu (ULNB) and 0.006 lb/MMBtu (SCR)4. Although not considered by Chevron, sorbent injection remains a viable option for all of the heaters and boilers, but achieves roughly half of the control efficiency of ULNB. It cannot be
used in conjunction with SCR, as injection prior to the SCR catalyst would foul the catalyst bed, and injection after the catalyst leaves insufficient residence time for effective control. It also cannot be used in conjunction with ULNB, as the inherent recirculation of the burners would
cause the sorbent to be carried back into the burner injectors potentially plugging them. This yields the following results:
Table 4-2: Ranking of Technically Feasible Controls – Process Heaters and Boilers Emission Unit ULNB lb/MMBtu SCR lb/MMBtu Sorbent lb/MMBtu
Boiler #5 0.018 0.011 0.036
Boiler #6 0.018 0.011 0.036
Crude Furnace #1 & #2* 0.036 0.009 0.072
Alkylation Furnace 0.040 0.009 0.080
Coker Furnace 0.036 0.014 0.072
FCC Unit Furnaces #1 & #2** 0.030 0.013 0.060
* combined ** each
4.3.4 Further Evaluation of Most Effective Controls Chevron provided an economic evaluation of both ULNB and SCR5. Sorbent injection was not directly evaluated by the source, but UDAQ was able to evaluate this control option using information from other sources. Installing ULNB or SCR on Boilers #5 and #6 would involve removal of the existing LNB and FGR controls. The remaining units evaluated in this section were essentially uncontrolled units
and would not require this same demolition work. Otherwise all the units were evaluated similarly. Estimated control costs and related NOx emission reductions for each control option
4 see References: Item #10 5 see References: Item #8

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are shown below in Table 3-3. Table 4-3: Estimated Control Costs and Emission Reductions – Process Heaters and Boilers
Emission Unit ULNB SCR Sorbent
Boiler #5 $64,000/ton $95,000/ton $735,000/ton
6.7 tons 12.6 tons 3.4 tons
Boiler #6 $66,000/ton $102,000/ton $806,000/ton
6.2 tons 11.7 tons 3.1 tons
Crude Furnaces $70,000/ton $118,134/ton $352,000/ton
14.1 tons* 17 tons* 7.1 tons*
Alkylation Furnace $56,000/ton $260,000/ton $625,000/ton
7.99 tons 8.4 tons 4.0 tons
Coker Furnace $50,000/ton $120,000/ton $373,000
13.3 tons 15.5 tons 6.7 tons
FCCU Furnaces $47,000/ton $438,000/ton $676,000
7.4 tons* 8.6 tons* 3.7 tons*
* combined
None of these additional controls are considered economically viable. 4.3.5 Selection of BACT Controls As all additional control options were eliminated for economic reasons, UDAQ recommends that
Chevron continue to operate all process heaters and boilers with the existing burners and controls in place as BACT. Good combustion practices will be maintained. Chevron 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:
• F-11005 Boiler #5: 0.20 lb/MMBtu
• F-11006 Boiler #6: 0.20 lb/MMBtu
• F-11007 Boiler #7: 0.20 lb/MMBtu
• F-21001 Crude Furnace #1: 0.09 lb/MMBtu
• F-21002 Crude Furnace #2: 0.09 lb/MMBtu
• F-32021 FCC Furnace #1: 0.17 lb/MMBtu
• F-32023 FCC Furnace #2: 0.17 lb/MMBtu
• F-35001 Reformer Furnace F-1: 0.17 lb/MMBtu
• F-35002 Reformer Furnace F-2: 0.17 lb/MMBtu
• F-36017 Alkylation Furnace: 0.12 lb/MMBtu

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• F-70001 Coker Furnace: 0.16 lb/MMBtu
• F-66100 VGO Furnace #1: 0.05 lb/MMBtu
• F-66200 VGO Furnace #2: 0.05 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. Chevron 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 Chevron 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). Ammonia emissions would be
more of a concern if SCR or SNCR had been chosen as a viable control option. However, as no ammonia injection is being used, no ammonia slip can result. UDAQ does not recommend ammonia controls on the heaters and boilers at this time. Good combustion practices are required through existing permit requirements. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. 5.0 BACT for the FCCU Regenerator The fluidized catalytic cracking unit, or FCCU, is a reactor where pre-heated feedstock is combined with a very hot catalyst in order to “crack” or break the long-chain hydrocarbon molecules making up the feedstock. The long-chain molecules are broken down into shorter,
lighter molecular weight hydrocarbons. These lighter materials then rise to the top of the reactor where they are removed and sent elsewhere in the refinery for further processing. The spent catalyst is removed from the recovered material through a series of 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

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operating around 1300ºF. Catalyst coke contains a high amount of entrapped impurities depending on the chemical nature of the feedstock. Sulfur, various nitrogen compounds, trace
metals and other compounds may be present. These materials will be released during combustion of the coke and depending on the design of the regenerator may be altered during the combustion process as well. The regenerator is the primary point of emissions from the FCCU.
The feed to the Chevron FCCU is hydrotreated – meaning that it is preheated and combined with hydrogen gas in the VGO (vacuum gas oil) and HDN (hydrodenitrification) units. These units
contain a fixed bed hydrotreating catalyst to begin removal of sulfur and nitrogen from the feed by replacing these elements with hydrogen. The sulfur and nitrogen become H2S and ammonia. 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 FCCU operates in complete combustion mode. Although the emission inventory lists a “CO boiler” this unit is not a true CO emission burning boiler, since such a device would only be present in a partial burn FCCU. In 2016, there were no listed emissions from this unit and by
2017 the unit had been physically removed from the site. Cyclones are used to remove catalyst particles from the combustion gases exiting the regenerator, and an ESP is used for final control of particulate emissions.
Following the procedures outlined in Section 2 above, the 2017 corrected emissions from the FCCU regenerator are as follows:
PM2.5 = 6.12 tons, SO2 = 9.34 tons, NOx = 18.22 tons, VOC = 0.0 tons, NH3 = 1.53 tons. 5.1 PM2.5 5.1.1 Available Control Technology
For control of particulate emissions from a FCCU regenerator, a source can choose 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. 5.1.2 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.

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5.1.3 Evaluation and Ranking of Technically Feasible Controls
In terms of efficiency, for control of particulate emissions, the available controls would be ranked as follows:
• Pulse jet fabric filter • FGF
• WGS • ESP Fabric filters have the highest efficiency but are designed only to control particulate emissions. Because of their high efficiency, they suffer from a problem other control options do not have. Catalytic coke burn-off can be extremely sticky, and the fabric in these baghouses can easily 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.
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. However, only venturi-type WGS systems can reach the same level of filterable control efficiency as fabric filters/FGF, and these have much higher energy and operating costs. Use of a high efficiency ESP is the typical default option. Chevron currently employs this option for particulate control and it will be used as the baseline case for economic evaluation. 5.1.4 Further Evaluation of Most Effective Controls
The top two control options, the fabric filter and the FGF are essentially identical in control efficiency. Should Chevron add a FGF or fabric filter control, emissions of 0.2 lb/1000 lb of coke
burned are possible. WGS is slightly less efficient, with reported values of 0.3 lb/1000 lb coke burned. Chevron’s current ESP is limited to 1 lb/1000 lb coke burned by both the moderate PM2.5 SIP as well as the emission limitations of 40 CFR 63 Subpart UUU and 40 CFR 60
Subpart Ja. Chevron’s most recent Method 5F testing showed an emission rate of 0.57 lb/1000 lb coke burned. Thus, an estimated emission reduction of 2 tons (filterable only) of PM2.5 are possible through installation of either fabric filtration or FGF, while approximately 3 tons of
PM2.5 (filterable+condensable) might be possible with WGS. Although Chevron did not provide estimated annualized costs for either fabric filtration or FGF, some estimation of costs is still possible. Based on values provided for other facilities, the estimated control costs for each of the
three controls is as follows: Fabric Filtration: $181,000/ton of PM2.5 (filterable only)

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FGF: $600,000/ton of PM2.5 (filterable only) WGS: $591,000/ton of PM2.5 (filterable+condensable)
None of these controls are economically feasible. 5.1.5 Selection of BACT Controls UDAQ recommends that Chevron continue to use the existing cyclone + ESP system to control
emissions of particulate from the FCCU catalyst regenerator. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. Chevron 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. 5.2 SO2
5.2.1 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 use of normal catalyst use, and then removes the SO2 from the exhaust gases through wet contact scrubbing.
These options, while not necessarily mutually exclusive, do have impacts on the control options for other pollutants. Feed 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. 5.2.2 Evaluation of Technical Feasibility of Available Controls All of the listed controls are technically feasible. Currently Chevron uses a combination of feed hydrotreating and deSOx catalyst injection for SO2 control, which represents the baseline case for
this refinery. 5.2.3 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 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 is addressed through use of the previously selected ESP for particulate control.

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Feed hydrotreating has also been demonstrated to meet the Subpart Ja limits. In Chevron’s
particular case, feedstocks are processed through the hydrocracking unit and gas oil desulfurization prior to being sent to the FCCU.
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. However, Chevron is already using two of these effective control options, the addition of a third would not show any additional
SO2 emission reductions. 5.2.4 Further Evaluation of Most Effective Controls Chevron submitted an economic analysis for installation and use of a WGS system, but only where this system would be applied for control of other pollutants6. The expected emission rate(s) for SO2 from such a system is no lower than Chevron’s current permitted and actual emissions. No additional emission reductions are expected. The cost for installation and
operation of a WGS was estimated at $1,776,000 annually. However, with no expected emission reductions, the cost per ton is undefined (division by zero). Therefore, WGS cannot be recommended as a control technique.
5.2.5 Selection of BACT Controls
UDAQ recommends that Chevron continue to use feed hydrotreating and SOx reducing catalyst as needed to meet the Subpart Ja FCCU SO2 limits. These limits have already been established in Section IX, Part H.11.g of the SIP and are required through existing permit requirements.
Monitoring, recordkeeping and reporting requirements are included as well. The existing limits account for current process variability while still limiting SO2 emissions from the FCCU. Therefore, the existing limits are considered BACT. For a summary of the most recent CEMs
data to support these conclusions, see Appendix B. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. Chevron 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. 5.3 NOx Chevron submitted a NOI for updates to the NOx limit, titled: DAQE-AN101190085 FCC NOx
Limit Required by Consent Decree, U.S. v. Chevron USA Inc. Case No. C 03-04650 (N.D. Cal.) This resulted in the following AO: DAQE-AN101190092-15.
5.3.1 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

6 see References: Item #8

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Low-NOx promoter catalysts and NOx reducing additives 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.
5.3.2 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.
Chevron, 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.
5.3.3 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. While Chevron has a current limit of 59 ppm NOx on a 365-day rolling average for the FCC regenerator stack, actual emissions have been averaging
17 and 13 ppm for 2016 and 2017 respectively. Installation of either SCR or WGS/LoTOx on a similarly sized new unit would require a limit of approximately 40 ppm on a 365-day rolling average – yielding a NOx emission reduction of 5.9 tons annually, based on current actual
emissions. 5.3.4 Further Evaluation of Most Effective Controls
Using the expected NOx emission reduction and the estimated annual cost to install and operate both a SCR and WGS/LoTOx system, the approximate control cost can be derived. Chevron
provided an economic analysis of both systems7, and from that the estimated control cost of SCR is $675,000/ton of NOx, while the control cost of WGS/LoTOx is $329,000/ton of NOx. Neither control option is economically feasible.

7 see References: Item #8

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Both SCR and SNCR have an additional drawback in the form of ammonia slip. In order to control NOx, ammonia is injected to reduce the NOx to N2 and water. Ideally, a stoichiometric
amount of ammonia would be added – just enough to fully reduce the amount of NOx present in the exhaust stream. However, some amount of ammonia will always pass through the process unreacted; and since the process possesses some degree of variability, a small amount of
additional ammonia is added to account for minor fluctuations. The ammonia which passes through the process unreacted and exits in the exhaust stream is termed “slip” (sometimes “ammonia slip”). The amount varies from facility to facility, but ranges from almost zero to as
high as 30 ppm in poorly controlled systems. In the case of SCR systems in particular, the catalyst also degrades over time, and the degree of slip will gradually increase as increasing amounts of ammonia are needed to maintain NOx reduction performance. Please see the section on ammonia considerations for additional information. 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. None of these control options is a viable choice for Chevron who handles NOx emissions through
feed hydrotreating and attains the same final level of control. 5.3.5 Selection of BACT Controls
UDAQ does not recommend any additional controls be installed. Chevron should continue to hydrotreat the feed prior to the feed entering the FCCU, and continue to meet the rolling 365-day
and rolling seven-day limits on NOx emissions from the FCCU as required by NSPS Subpart Ja. The existing limits account for current process variability while still limiting NOx emissions from the FCCU. Therefore, the existing limits are considered BACT. For a summary of the most
recent CEMs data to support these conclusions, see Appendix B. No additional controls are required for BACT; thus, no additional limits are required to be established for the SIP. Chevron 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. 5.4 VOC and Ammonia Considerations
UDAQ was unable to locate any additional controls to reduce emissions of VOCs from the FCCU regenerator. In 2016, Chevron’s listed VOC emissions from this unit were 0 tons. Chevron 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

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are relatively small, amounting to just 1.53 tons annually in Chevron’s case. The second mechanism is the injection of ammonia for control of NOx emissions using either SCR or SNCR
as a control process. The injection of ammonia is fairly common among refineries in the U.S., but does not occur among the refineries in Utah. None of the refineries located in the Salt Lake City PM2.5 NAA use 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. 6.0 BACT for the SRUs 6.1 SO2 Chevron operates two well-controlled sulfur recovery plants meeting the established 95% sulfur
recovery required under the PM10 SIP (SIP Section IX, Part H.1). Generically, the sulfur recovery systems at the various refineries located in the PM2.5 non-attainment areas are referred to as sulfur recovery units or SRUs. For purposes of this review a “well-controlled SRU” is one
that is already operating with a tail gas treatment system followed by tail gas incineration. 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, this sulfur is recovered in liquid form from the SRU 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.
Through the heat of combustion, some NOx is formed (thermal NOx), but particulate and VOC emissions are very low. Following the procedures outlined in Section 2 above, the 2017 corrected emissions from the two SRUs are as follows: SRU #1: PM2.5 = 0.12 tons, SO2 = 6.73 tons, NOx = 0.82 tons, VOC = 0.09 tons, NH3 = 0.05 tons.
SRU #2: PM2.5 = 0.13 tons, SO2 = 3.44 tons, NOx = 1.67 tons, VOC = 0.09 tons, NH3 = 0.05 tons.
It should be noted, that in Chevron’s case, the effluent gases from both SRUs are sent to a single TGTU and TGI unit. 6.1.1 Available Control Technology Three control systems were identified to further control emissions from a well-controlled SRU.
For purposes of this review a “well -controlled SRU” is one that is already operating with a tail gas treatment system followed by tail gas incineration. • LoCat • WGS • Caustic Scrubbing

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LoCat is unusual in that it can serve as both a final treatment following the SRU (both in addition
to, or in-lieu of a tail gas unit) or as a fuel gas sulfur removal unit (in case the SRU itself goes down).
WGS is a final control option, where the exhaust from the SRU is sent to the WGS in-lieu of tail gas treatment.
Caustic scrubbing is typically used as a replacement for a SRU, such as a redundant back-up device, but can be used as a final scrubbing process. 6.1.2 Evaluation of Technical Feasibility of Available Controls All controls are technically feasible. 6.1.3 Evaluation and Ranking of Technically Feasible Controls
Although all three options are technically feasible, none is a good option as an add-on control. Well-controlled SRUs can achieve 99.9% or better sulfur recovery efficiency rates. Chevron’s
SRUs show SO2 emissions of approximately 10 tons per year, additional add-on controls will not be cost effective at these low inlet loadings. 6.1.4 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, and either LoCat or WGS could be applied in addition to the existing controls, the costs of these additional add-on measures would be well above $250,000/ton.
6.1.5 Selection of BACT Controls UDAQ recommends that Chevron continue to operate the existing TGTU and TGI as SO2 control for both SRUs. The SRUs are monitored by CEM. Chevron is subject to the PM10 SIP and PM2.5 SIP refinery requirements found at Section IX Parts H.1.g and H.11.g. These practices are required through existing permit requirements. The existing emission limitations were established based on NSPS Subpart Ja, using the equations found in 40 CFR 60.102a(f). These emission
limitations were established based on the application of the best system of emission reduction while taking into consideration costs and impacts. The existing limits account for current process variability while still limiting SO2 emissions from the SRUs. 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. Chevron will comply with any applicable emission limits in
Section IX, Part H.11. See Appendix A for a complete listing of existing permit conditions, established emission limits, and the basis of those limits. 7.0 BACT for 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

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analysis.
Cooling towers found in refineries have a secondary concern. It is possible for the cooling water to pick up volatile compounds during the heat transfer process, and for these compounds to be released as VOCs. As the levels of VOCs in refinery cooling water can be large enough to
deserve their own controls, a separate BACT analysis is provided. 7.1 VOCs
7.1.1 Available Control Technology UDAQ employed the services of a contractor during review of the RACT evaluations for the moderate PM2.5 SIP8. 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. 7.1.2 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.
7.1.3 Evaluation and Ranking of Technically Feasible Controls
N/A This has become a refinery general SIP requirement. 7.1.4 Further Evaluation of Most Effective Controls N/A This has become a refinery general SIP requirement. 7.1.5 Selection of BACT Controls
UDAQ recommends that Chevron 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. Chevron will comply with any applicable emission limits in Section IX, Part H.11. 8.0 BACT for Fugitives In this context, fugitives are referring to fugitive VOC emissions. While Chevron 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.

8 see References: Item #3

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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. 8.1 VOCs 8.1.1 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 Chevron) became subject to the requirements of low-leak LDAR (Subpart GGGa) as part of the requirements of the moderate PM2.5 SIP. 8.1.2 Evaluation of Technical Feasibility of Available Controls
N/A Low-leak LDAR is technically feasible, and Chevron became subject to its requirements on January 1, 2017. 8.1.3 Evaluation and Ranking of Technically Feasible Controls N/A Chevron is already implementing the requirements of 40 CFR 60 Subpart GGGa.
8.1.4 Further Evaluation of Most Effective Controls
N/A Chevron is already implementing the requirements of 40 CFR 60 Subpart GGGa. 8.1.5 Selection of RACT Controls
UDAQ recommends that Chevron 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. Chevron will comply with any applicable emission limits in Section IX, Part H.11.
9.0 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. 9.1 VOC 9.1.1 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

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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 and 40 CFR 63 Subpart
CC. 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. 9.1.2 Evaluation of Technical Feasibility of Available Controls The use of slotted guide poles and vapor controls are 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.
9.1.3 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. 9.1.4 Further Evaluation of Most Effective Controls Chevron is already required to follow the tank degassing requirements of Section IX, Part H.11.g.
The remaining vapor controls were all evaluated by Chevron and were found not to be economically feasible, with cost effectiveness values in excess of $200,000/ton of VOC control9. 9.1.5 Selection of BACT Controls UDAQ recommends that Chevron 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. Chevron will comply
with any applicable emission limits in Section IX, Part H.11. 10.0 BACT for Wastewater System
10.1 VOC
The wastewater treatment system at Chevron consists primarily of a system of drains that route runoff water and stormwater to an induced air floatation (IAF) unit, which separates entrained oils and volatiles from the wastewater. Chevron currently operates the IAF with a regenerative
thermal oxidizer (RTO) to control VOC emissions. Pursuant to Approval Order DAQE-AN101190104-22, dated September 26, 2022, Chevron requested a modification to update its existing wastewater treatment plant. The update will

9 see References: Item #8

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include transitioning the existing IAF units to two new dissolved nitrogen flotation (DNF) units. Upon completion of startup and initial commissioning, the DNF units are allowed in place of the
IAF system. The existing RTO will control these processes. 10.1.1 Available Control Technology
Because of Chevron’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. For the primary collection system, Chevron currently uses: a collection sump, IAF, and biological contactors, which are all covered and the vapors recovered for destruction. Alternatively, Chevron could opt for an API (American Petroleum Institute) oil-water separator (often referred to simply as an API). Similarly, the destruction method chosen by Chevron is a RTO. Alternatively, the use of carbon canisters, non-regenerative thermal oxidation (flaring), or vapor recovery (refrigeration or alternative method), are all potentially available methods of controlling the recovered vapors.
10.1.2 Evaluation of Technical Feasibility of Available Controls
Either the use of an API or IAF is technically feasible. 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). 10.1.3 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. 10.1.4 Further Evaluation of Most Effective Controls Chevron did not conduct an economic analysis of the available control options. However, based on the estimated possible emission reductions and information provided by other refineries, the control cost of installing and using the carbon canister option is approximately $8,000/ton of
VOC removed. Either thermal oxidation option has a control cost of over $75,000/ton of VOC removed. However, Chevron has already installed and is operating the RTO control option – which defines that as the base case.
10.1.5 Selection of BACT Controls
UDAQ recommends that Chevron continue to operate the existing wastewater control system of IAF and RTO as BACT for the wastewater treatment plant. Operation of the IAF (or DNF upon completion of startup and initial commissioning) and RTO are required in Part H.12.d.viii. No
additional controls are required for BACT, thus no additional limits other than those established in H.12.d.viii are required to be established for the SIP. 11.0 BACT for Flares 11.1 Flare Gas Emissions

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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.
11.1.1 Available Control Technology There are two parts to refinery flares, as outlined in the Refinery General RACT Evaluation10. 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).
11.1.2 Evaluation of Technical Feasibility of Available Controls Neither part is technically infeasible.
11.1.3 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 Evaluation11, most refineries will begin 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, Chevron implemented a flare gas recovery system on its hydrocarbon flares as part of the C.U.R.E. project in 2011. This system greatly reduced the emissions from both the North and South Flares, transforming both emission units into true “upset only” flares. The third flare was primarily a dedicated flare for the HF alkylation unit and cannot be classified as a hydrocarbon flare due to the HF acid present. Flare gas recovery on this unit would be technically infeasible, and DAQ has already acknowledged this infeasibility provision with the wording of the language in the general refinery requirement. Chevron has begun the process of eliminating the use of HF polymer/HF acid in its processes with an NOI: DAQE-AN101190092 Reformer Compressor
Limits Required by Consent Decree, U.S. v. Chevron USA Inc. DOJ Case No. 90-5-2-1-07639, Civil Action No. 2:13-cv-00721-EJF resulting in an NSR permit issued for the Isoalkyl project (DAQE-AN101190095-17) in 2017.
11.1.4 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.
11.1.5 Selection of BACT Controls
10 see References: Item #3 11 see References: Item #3

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DAQ recommends that Chevron continue to operate its existing flare gas recovery system in accordance with the general refinery SIP requirements found in Section IX Part H.11.g; as well as
implement the general refinery SIP requirement “Requirements on Hydrocarbon Flares” as outlined in the Refinery General RACT Evaluation. 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. Chevron 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. 12.0 Additional Feasible Measures and Most Stringent Measures
12.1 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). 12.2 Additional Feasible Measures at Chevron 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 June 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. 12.3 Most Stringent Measures at Chevron 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

26
those control measures which are either included in the SIP for any other NAAQS, or have been achieved in practice in any state, and that can feasibly be implemented in the relevant PM2.5
NAAQS nonattainment area. This is further refined and clarified in 40 CFR 51.1010(b), to include the following Steps:
Step 1) The state shall identify the most stringent measures for reducing direct PM2.5 and PM2.5 plan precursors adopted into any SIP or used in practice to control emissions in any state.
Step 2) The state shall reconsider and reassess any measures previously rejected by the state during the development of any previous Moderate area or Serious area attainment plan control strategy for the area. Step 3) The state may make a demonstration that a measure identified is not technologically or economically feasible to implement in whole or in part by 5 years after the applicable attainment date for the area, and may eliminate such whole or partial measure from further consideration. Step 4) Except as provided in Step 3), the state shall adopt and implement all control measures
identified under Steps 1) and 2) that collectively shall achieve attainment as expeditiously as practicable, but no later than 5 years after the applicable attainment date for the area. 12.3.1 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 12-1: 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, deNOx catalyst, feed hydro-treating, LoTOx Heaters/Boilers NOx ULNB, SCR Ammonia only if SCR is used, feedback controls
Flares Flare Gas flare minimization program
SRU SO2 second tail gas treatment unit (TGTU), WGS
NOx WGS
Cooling Towers VOC MACT CC requirements
Fugitives VOC NSPS GGGa LDAR requirements Tanks VOC tank degassing requirements Wastewater Treatment VOC 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. 12.3.2 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

27
Stationary Sources, which includes the application of RACT at those sources, can be found in the SIP at Section IX Part H. Limits and practices specific to PM2.5 may be found in subsections 11,
12, and 13 of Part H. Accompanying Section IX Part H was a TSD that included multiple evaluation reports similar to
this document for each large stationary source identified and listed in each nonattainment area. UDAQ conducted a review of those measures included in each previous evaluation report which contained emitting units which were at all similar to those installed and operating at Chevron.
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 Chevron in its BACT analysis report. This was the deferment of VOC controls for the wastewater treatment systems at four Salt Lake City area refineries. Chevron did include an analysis of the wastewater treatment system, and considered previous steps (such as the IAF
and RTO) previously undertaken to reduce emissions. This updated analysis has been reviewed as part of the UDAQ BACT review in Section 12 above. 12.3.3 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 12-2: Feasibility Determination Emission Unit Pollutant MSM Previously Identified Is Method Feasible?
PM2.5 GCP, fuel type, FGF/WGS See below

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FCCU Regenerator SO2 deSOx catalyst, WGS See below
NOx GCP, deNOx catalyst, feed
hydro-treating, LoTOx
See below
Heaters/Boilers NOx ULNB, SCR See below
Ammonia NH3 feedback See below
Flares Flare Gas flare minimization program Yes SRU SO2 TGTU or WGS No, high cost NOx WGS No, high cost
Cooling Towers VOC MACT CC Yes
Fugitives VOC LDAR Yes
Tanks VOC tank degassing Yes
WW Treatment VOC carbon canister / oxidation Yes, see below
Most of the entries in the above table were determined to be feasible on a technological basis. However, in several cases two distinct paths exist that are mutually exclusive. Two control techniques could serve equally as BACT/BACM or MSM, but they are not simply
interchangeable. Once a source has elected to follow a particular path for emission control, needing to change over to the alternative control path would involve considerable expense as well as complete removal of the existing system(s). In many cases this would also involve shutting
down operation of the source for an extended period of time – posing additional economic burden on the source.
One particular example of this is the application (or lack) of WGS. Wet gas scrubbing has the capability of removing both particulates and acid gases (SO2 and derivatives) and, if the LoTOx option has been pursued, NOx as well. However, this control system is not compatible with other
control systems such as fabric filtration (baghouses or FGF), catalytic controls (SCR), or tail gas treatment (as these are also catalytic controls). If the WGS is installed secondary to the existing controls, these would render the use of WGS redundant and extremely cost ineffective (the inlet
concentrations would simply be too low to be viable). Alternatively, the WGS would be installed as the primary control, creating a similar situation for the “existing” controls, but with an additional problem of a now water saturated exhaust stream and a greatly lowered exhaust temperature. Removing the existing controls to swap to the new control option is often millions of dollars above and beyond the millions already spent on the primary BACT level control. In Chevron’s case, the company opted for feed hydro-treating, which is a pretreatment solution that effectively eliminates the need for after-process controls normally chosen as MSM. This mechanism of pollution control is not typically chosen as MSM as it requires a complete redesign
of the underlying production process – and can rarely be accomplished within the SIP development window, let alone within the MSM timeframe.
The costs for WGS or a second TGTU on the SRU do not currently justify including either of these controls as MSM. With total expected emissions from the SRU of just 10 tons, UDAQ cannot recommend either control option as MSM.
13.0 New PM2.5 SIP – General Requirements
The general requirements for all listed sources are found in SIP Subsection IX.H.11. These serve as a means of consolidating all commonly used and often repeated requirements into a central location for consistency and ease of reference. As specifically stated in subsection IX.H.11.a
below, these general requirements apply to all sources subsequently listed in either IX.H.12 (Salt Lake City) or IX.H.13 (Provo/Orem), and are in addition to (and in most cases supplemental to)

29
any source-specific requirements found within those two subsections.
IX.H.11.a. This paragraph states that the terms and conditions of Subsection IX.H.11 apply to all sources subsequently addressed in the following subsections IX.H.12 and IX.H.13. It also clarifies that should any inconsistency exist between the general requirements and the source
specific requirements, then the source specific requirements take precedence. IX.H.11.b Paragraph i: States that the definitions found in State Rule 307-101-2, Definitions,
apply to SIP Section IX.H. Since this is stated for the Section (IX.H), it applies equally to IX.H.11, IX.H.12 and IX.H.13. A second paragraph (ii), includes a new definition for natural gas curtailment for those sources in IX.H.12 and IX.H.13 that reference it. IX.H.11.c This is a recordkeeping provision. Information used to determine compliance shall be recorded for all periods the source is in operation, maintained for a minimum period of five (5) years, and made available to the Director upon request. As the general recordkeeping requirement of Section IX.H, it will often be referred to and/or discussed as part of the
compliance demonstration provisions for other general or source specific conditions. It also includes provisions referring to the reporting of emission inventories and reporting deviations (paragraph ii).
IX.H.11.d Statement that emission limitations apply at all times that the source or emitting unit is in operation, unless otherwise specified in the source specific conditions listed in IX.H.12
or IX.H.13. It also clarifies that particulate emissions consist of both the filterable and condensable fractions unless otherwise specified in IX.H.12 or IX.H.13.
This is the definitive statement that emission limits apply at all times – including periods of startup or shutdown. It may be that specific sources have separate defined limits that apply during alternate operating periods (such as during startup or shutdown), and these limits will be
defined in the source specific conditions of either IX.H.12 or IX.H.13. Conditions 1.a, 1.b and 1.d are declaratory statements, and have little in the way of compliance provisions. Rather, they define the framework of the other SIP conditions. As condition 1.c is the primary recordkeeping requirement, it shall be further discussed under item 4.2 below. IX.H.11.e This is the main stack testing condition, and outlines the specific requirements for demonstrating compliance through stack testing. Several subsections detailing Sample Location,
Volumetric Flow Rate, Calculation Methodologies and Stack Test Protocols are all included – as well as those which list the specific accepted test methods for each emitted pollutant species (PM10, NOx, or SO2). Finally, this subsection also discusses the need to test at an acceptable
production rate, and that production is limited to a set ratio of the tested rate. IX.H.11.f This condition covers the use of CEMs and opacity monitoring. While it
specifically details the rules governing the use of continuous monitors (both emission monitors and opacity monitors), it also covers visible opacity observations through the use of EPA reference method 9.
Both conditions 11.e and 11.f serve as the mechanism through which sources conduct monitoring for the verification of compliance with a particular emission limitation.
13.1 Monitoring, Recordkeeping and Reporting

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As stated above, the general requirements IX.H.11.a through IX.H.11.f primarily serve as declaratory or clarifying conditions, and do not impose compliance provisions themselves.
Rather, they outline the scope of the conditions which follow in the source specific requirements of IX.H.12 and IX.H.13.
For example, most of the conditions in those subsections include some form of short-term emission limit. This limitation also includes a compliance demonstration methodology – stack test, CEM, visible opacity reading, etc. In order to ensure consistency in compliance
demonstrations and avoid unnecessary repetition, all common monitoring language has been consolidated under IX.H.11.e and IX.H.11.f. Similarly, all common recordkeeping and reporting provisions have been consolidated under IX.H.11.c. 14.0 Revised PM2.5 SIP – General Refinery Requirements The revised PM2.5 SIP incorporates several new requirements that apply specifically to those petroleum refineries listed in Section IX.H.12 of the SIP. Some subsections of IX.H.11.g also
apply more broadly and could affect additional petroleum refineries in addition to those listed in IX.H.12. Where this greater applicability exists for a particular condition or limitation, such will be noted in the discussion for that requirement.
IX.H.11.g.i.A This condition covers SO2 emissions from fluidized catalytic cracking units (FCCUs). The limit is 50 ppmvd @ 0% excess air on a 7-day rolling average
basis, as well as 25 ppmvd @ 0% excess air on a 365-day rolling average basis. The condition is based on 40 CFR 60 Subpart Ja, and includes the same limitation found in that
subpart. Compliance is demonstrated by CEM, as outlined in 40 CFR 60.105a(g) – also from Subpart Ja.
IX.H.11.g.i.B This condition addresses PM emissions from FCCUs. The limit is 1.0 lb PM per 1000 lb coke burned. The emission limit applies on a 3-hour average basis. The emission limit is derived from 40 CFR 60 Subpart Ja, although Subpart Ja does not specifically state that the limit applies on a 3-hour average. Instead it states that compliance will be demonstrated via a performance test using Method 5, 5b or 5f, using an average of three 60-minute (minimum) test runs.
Compliance is demonstrated by stack test as outlined in 40 CFR 60.106(b). This stack testing procedure is from Subpart J, rather than Subpart Ja. The equations utilized and reference methods involved are identical between the two subparts; however, the protocol to follow for
testing is much more direct and straightforward in §60.106(b). The condition also requires the installation of a continuous parameter monitoring system (CPMS)
to monitor and record operating parameters for determination of source-wide PM10 emissions. IX.H.11.g.ii This condition limits the H2S content of gases burned within any refinery located
within (or affecting) an area of PM2.5 or PM10 nonattainment. The limit is 60 ppm H2S or less as described in 40 CFR 60.102a on a rolling average of 365 days. Compliance is demonstrated through continuous H2S monitoring, as outlined in 40 CFR 60.107a. Both the limitation and the compliance methodology are based on 40 CFR 60 Subpart Ja.

31
IX.H.11.g.iii This condition places limits on heat exchangers in VOC service.
The condition requires that all heat exchangers in VOC service meet the requirements of 40 CFR 63.654, which requires use of the “Modified El Paso Method” for calculation of VOC emissions.
Sources are allowed an option to use another EPA-approved method if allowed by the Director. An exemption is also given for heat exchangers that meet specific criteria that are outlined within the condition language.
IX.H.11.g.iv Leak Detection and Repair Requirements. This condition subjects each source to the requirements of 40 CFR 60 Subpart GGGa – also known as Enhanced LDAR. The Sustainable Skip Period provisions of that subpart have also been retained. IX.H.11.g.v This condition establishes new requirements on hydrocarbon flares.
First, it states that all hydrocarbon flares are subject to Subpart Ja (40 CFR 60.100a-109a) if not previously subject.
Second it requires that each major source refinery either: 1) install a flare gas recovery system designed to limit hydrocarbon flaring from each affected flare during normal operations below
the values listed in Subpart Ja (specifically 40 CFR 60.103a(c)), or 2) limit flaring during normal operations to 500,000 scfd or less for each affected flare.
This requirement is based on Subpart Ja, and is designed to incorporate the flare gas recovery requirements of that subpart ahead of the normal implementation schedule. The refineries located in, or impacting, the nonattainment areas are relatively small. As a consequence, the possibility
that they would trigger the flare gas recovery provisions of Subpart Ja in the near term (5-10 years) was very small. Although one of the refineries had elected to install a flare gas recovery system voluntarily, the system only addressed a part of the refinery’s total flaring capacity, and was not originally designed to Subpart Ja specifications. The first paragraph is already applicable to all refineries, while the second paragraph is applicable as of January 1, 2019. IX.H.11.g.vi This condition requires that vapor control devices be employed during tank degassing operations. Some provisions are made for connecting and
disconnecting degassing equipment. Notification must also be made to the Director prior to performing such an operation – unless an emergency situation is at play.
This condition applies to sources beyond just refineries – any owner/operator of any stationary tank meeting the outlined criteria must fulfill the requirements of this condition.
IX.H.11.g.vii No Burning of Liquid Fuel Oil in Stationary Sources – Establishes that no petroleum refineries in or affecting any PM nonattainment or maintenance area
shall be allowed to burn liquid fuel oil in stationary sources except during natural gas curtailments or as specified in the individual subsections of Section IX, Part H. The use of diesel fuel meeting the specifications of 40 CFR 80.510 in standby
or emergency equipment is exempt from this requirement. This requirement addresses a provision of the original PM10 SIP, which prevented the refineries

32
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.
14.1 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. 15.0 Revised PM2.5 SIP – Chevron Specific Requirements
The Chevron specific conditions in Section IX.H.12 address those limitations and requirements that apply only to the Chevron Refinery in particular. The following controls were determined as necessary for the PM2.5 SIP to satisfy BACT.
IX.H.12.d.i This condition establishes NOx emission limits for 13 combustion units at Chevron.
These emission limitations were determined as necessary for BACT. This condition requires initial and ongoing stack testing for all units except Boiler #7 to ensure emission limitations and
existing control requirements are being met. Compliance for the emission limit for Boiler #7 will be determined through the use of CEMs. IX.H.12.d.vii This condition requires the use of BACT-level controls on the three compressor engines through establishment of ppmvd emission limits on each of engines. Stack testing for compliance monitoring is also required.

33
The installation of these controls was required under DAQE-AN101190092 Reformer
Compressor Limits Required by Consent Decree, U.S. v. Chevron USA Inc. DOJ Case No. 90-5-2-1-07639, Civil Action No. 2:13-cv-00721-EJF. This condition will be added to incorporate the control requirements of this BACT analysis, which recommended NOx limitations on the three
engines. 15.1 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.d.i through IX.H.12.d.vii. As appropriate, these monitoring requirements are complemented by the general provisions of IX.H – specifically 11.e for stack testing, 11.f for CEMs and other continuous monitors, and 11.c for recordkeeping and reporting.
Where necessary, additional monitoring, recordkeeping and/or reporting requirements have been directly included in the language of IX.H.12.b to address specific concerns. 16.0 References 1. Chevron, PM2.5 SIP Major Point Source RACT Documentation - Salt Lake Refinery
2. Chevron - response to information request, dated June 11, 2014 3. UDSHW Contract No. 12601, Work Assignment No. 7, Utah PM2.5 SIP RACT Support - TechLaw Inc.
4. DAQE-AN0101190085-11 5. DAQE-AN101190092-15 6. DAQE-AN101190094
7. DAQE-AN101190095-17 8. DAQE-AN101190097-18 9. Chevron Products Company – Response to SIP PM2.5 BACT Analysis Request, dated April 26, 2017 10. Chevron Products Company – Response to Serious Nonattainment Area State Implementation Plan Control Strategy Requirements; DAQE-062-17, dated October 13, 2017 11. Chevron Products Company – SIP PM2.5 BACT Updated to PTE, dated March 23, 2018 12. Final Chevron Products - Salt Lake Refinery 10119 PM2.5 SIP BACT.xlsx, dated May 16,
2018 Additional references reviewed during UDAQ BACT research:
3-2-1-2.pdf. (n.d.). Retrieved from https://www.netl.doe.gov/File%20Library/Research/Coal/energy%20systems/turbines/ha
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bact_boilheatfurn.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bac
t/bact_boilheatfurn.pdf
bact_bulkgasterm.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_bulkgasterm.pdf
bact_cooltow.pdf. (n.d.). Retrieved from
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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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t/bact_flares.pdf
bact_fugitives.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_fugitives.pdf
bact_loading.pdf. (n.d.-a). Retrieved from
https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_loading.pdf
bact_loading.pdf. (n.d.-b). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bac
t/bact_loading.pdf
bact_processfurn.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bac

35
t/bact_processfurn.pdf
bact_sru.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bac
t/bact_sru.pdf
bact_turbines.pdf. (n.d.). Retrieved from https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_turbines.pdf
C302-4-(BMK750-1000-Alt-Derate).pdf. (n.d.). Retrieved from
http://aerco.com/sites/default/files/document/document/C302-4-%28BMK750-1000-Alt-Derate%29.pdf
chapter7.pdf. (n.d.). Retrieved from http://www.valleyair.org/busind/pto/bact/chapter7.pdf
Current Rules. (n.d.). Retrieved from http://www.baaqmd.gov/rules-and-
compliance/current-rules
Development, O. of R. &. (n.d.). ENVIRONMENTAL TECHNOLOGY VERIFICATION REPORT, NOX CONTROL TECHNOLOGIES, CATALYTICA COMBUSTION SYSTEMS, INC., XONON FLAMELESS COMBUSTION SYSTEM. Retrieved October 17, 2017, from
https://cfpub.epa.gov/si/si_public_record_Report.cfm?dirEntryID=86205
DPFs and DOCs: The new components at the heart of your Tier 4 engine | Equipment World | Construction Equipment, News and Information | Heavy Construction Equipment. (n.d.). Retrieved December 6, 2017, from https://www.equipmentworld.com/maintenance-24/
Electric Power Monthly - U.S. Energy Information Administration. (n.d.). Retrieved March 7, 2018, from https://www.eia.gov/electricity/monthly/
epm.pdf. (n.d.). Retrieved from https://www.eia.gov/electricity/monthly/current_month/epm.pdf
ffdg.pdf. (n.d.). Retrieved from https://www3.epa.gov/ttncatc1/dir1/ffdg.pdf
fnoxdoc.pdf. (n.d.). Retrieved from https://www3.epa.gov/ttncatc1/dir1/fnoxdoc.pdf
iron. (n.d.). Retrieved from https://www.chemguide.co.uk/inorganic/transition/iron.html
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endix%205.1C_BACT%20Analysis.pdf
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36
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oltow.html
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ading.html
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rb.html
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37
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PM2.5 SIP Evaluation Report: Chevron Products Company – Salt Lake Refinery Salt Lake City PM2.5 Serious Nonattainment Area Utah Division of Air Quality Major New Source Review Section Appendix A
Chevron Refinery Emission Unit Monitoring
Emission Unit Capacity Controls
AO
Conditions[1]SIP Conditions Monitoring Established Emission Limit Basis of Limit
F-11005 Boiler #5 171 MMBtu/hr LNB; FGR II.B.2 NOx Limit (new) Stack Test 0.2 lb/MMBtu NOx NSPS Subpart Db
F-11006 Boiler #6 171 MMBtu/hr LNB; FGR II.B.3 NOx Limit (new) Stack Test 0.2 lb/MMBtu NOx NSPS Subpart Db
F-11007 Boiler #7 225 MMBtu/hr LNB; FGR -- NOx Limit (new) CEMs
Limit: 0.1 or 0.2 lbs/MMBtu NOx (low
heat vs high heat release rate)Subpart Db 60.44(b)NSPS Subpart Db
16001 Cooling Tower #1 -- Drift Eliminators -- -- -- -- --
16002 Cooling Tower #2 -- Drift Eliminators -- -- -- -- --
16003 Cooling Tower #3 -- Drift Eliminators -- -- -- -- --
16004 Cooling Tower #4 -- Drift Eliminators -- -- -- -- --
F21001 Crude Unit Furnace #1 130 MMBtu/hr LNB -- NOx Limit (new) Stack Test 75 ppm Source supplied based on past stack tests
F21002 Crude Unit Furnace #2 115.1 MMBtu/hr LNB -- NOx Limit (new) Stack Test 75 ppm
Combined with F21001 Crude Unit Furnace #1 - source supplied based
on past stack tests
F-32021 FCC Furnace #1 48.2 MMBtu/hr -- -- NOx Limit (new) Stack Test (new) 0.17 lb/MMBtu
XRG Technologies NOx study submitted as part of PM2.5 Serious SIP
BACT Analysis
F-32023 FCC Furnace #2 48.2 MMBtu/hr -- -- NOx Limit (new) Stack Test (new) 0.17 lb/MMBtu
XRG Technologies NOx study submitted as part of PM2.5 Serious SIP
BACT Analysis
F-71010 HDN Furnace #1 15.6 MMBtu/hr -- -- -- -- --
No limit in new requirements - BACT included in small source BACT
document
F-71030 HDN Furnace #2 36.3 MMBtu/hr -- -- -- -- -- No limit in new requirements - BACT included in Chevron TSD
F-35001 Reformer Furnace F-1 52.3 MMBtu/hr -- -- NOx Limit (new) Stack Test (new) 0.17 lb/MMBtu
XRG Technologies NOx study submitted as part of PM2.5 Serious SIP
BACT Analysis
F-35002 Reformer Furnace F-2 45 MMBtu/hr -- -- NOx Limit (new) Stack Test (new) 0.17 lb/MMBtu
XRG Technologies NOx study submitted as part of PM2.5 Serious SIP
BACT Analysis
F-35003 Reformer Furnace F-3 31.7 MMBtu/hr -- -- -- -- -- No limit in new requirements - BACK included in Chevron TSD
F-36017 Alkylation Furnace 108 MMBtu/hr LNB -- NOx Limit (new) Stack Test 80 ppm Source supplied based on past stack tests
F-70001 Coker Furnace 139.2 MMBtu/hr -- -- NOx Limit (new) Stack Test 135 ppm Source supplied based on past stack tests
F-64010 HDS Furnace #1 19 MMBtu/hr LNB -- -- -- --
No limit in new requirements - BACT included in small source BACT
document
F-64011 HDS Furnace #2 27.3 MMBtu/hr LNB -- -- -- --
No limit in new requirements - BACT included in small source BACT
document
F-66100 VGO Furnace #1 40 MMBtu/hr LNB -- NOx Limit (new) Stack Test (new) 0.05 lb/MMBtu
Based on SLEIS-reported NOx post control emission factor (originating
from AP-42)
F-66200 VGO Furnace #2 66 MMBtu/hr LNB -- NOx Limit (new) Stack Test (new) 0.05 lb/MMBtu
Based on SLEIS-reported NOx post control emission factor (originating
from AP-42)
Amine Unit #1 -- -- -- -- -- -- --
Amine Unit #2 -- -- -- -- -- -- --
SRU #1 -- TGTU & Incinerator II.B.4; II.B.5 No CEMs 250 ppm SO2 (12-hour rolling average) NSPS Subpart Ja
SRU #2 -- TGTU & Incinerator II.B.4; II.B.6 No CEMs 250 ppm SO2 (12-hour rolling average) NSPS Subpart Ja
FCCU w/ Catalyst Regenerator -- Cyclone & ESP II.B.7 Yes CEMs/Stack Test
25 ppm SO2 (365-day rolling average)50 ppm SO2 (7-day rolling average)
57.8 ppm NOx (365-day rolling average)
106 ppm NOx (7-day rolling average)1 lb PM/1000 lb coke burned
NSPS Subpart Ja
F61312 Flameless Thermal Oxidizer -- -- -- -- -- -- --
Coker Flare (Flare #1) -- FGR System II.B.10.d SO2 Limit CEMs 162 ppm SO2 (3-hour rolling average) NSPS Subpart Ja
FCCU Flare (Flare #2) -- FGR System II.B.10.d SO2 Limit CEMs 162 ppm SO2 (3-hour rolling average) NSPS Subpart Ja
Alkylation Flare (Flare #3) -- FGR System II.B.10.d SO2 Limit CEMs 162 ppm SO2 (3-hour rolling average) NSPS Subpart Ja
Emergency Equipment (Diesel) Varies Varies II.B.8 -- -- -- Equipment subject to various federal and general regulations
K35001 Reformer Compressor Drivers 16 MMBtu/hr NSCR II.B.9 NOx Limit Stack Test 236 ppm NOx Existing limits from AO
K35002 Reformer Compressor Driver 16 MMBtu/hr NSCR II.B.9 NOx Limit Stack Test 208 ppm NOx Existing limits from AO
K35003 Reformer Compressor Driver 16 MMBtu/hr NSCR II.B.9 NOx Limit Stack Test 230 ppm NOx Existing limits from AO
Tank Farm Varies --
II.B.10.c[1] &
II.B.2.c[2]-- -- Varies Various requirements based on federal regulation applicability
Loading/Unloading Varies VRU PrimaryVRU Secondary II.B.3[2]-- Stack Test 10 mg VOC/L gasoline loaded Varies
Fugitives N/A Federal Regulations II.B.10.b -- -- Federal Regulations Follow federal regulations and LDAR
Wastewater Treatment Plant -- IAF & RTO II.B.2[2]-- -- -- --
Fuel Gas Mix Point N/A Not an emission unit II.B.1.b CEMs CEMs
162 ppm H2S (3-hour rolling average)60 ppm H2S (365-day rolling average)NSPS Subpart Ja
[1] AO DAQE-AN101190106-22
[2] AO DAQE-AN101190104-22
[3] Applicable federal regulations:
NSPS Subpart A: General Provisions
NSPS Subpart Db: Industrial-Commercial-Institutional Steam Generating Units
NSPS Subpart J: Petroleum Refineries
NSPS Subpart Ja: Petroleum Refineries after 5/14/07
NSPS Subpart Kb: Storage Vessels for Petroleum Liquids after 7/23/84
NSPS Subpart GGG: VOC Equipment Leaks in Petroleum Refineries 1/4/83 - 11/7/06
NSPS Subpart GGGa: VOC Equipment Leaks in Petroleum Refineries after 11/7/06
NSPS Subpart QQQ: VOC Emissions from Petroleum Refinery WWTP
NSPS Subpart IIII: Stationary CI Internal Combustion Engines
NESHAP Subpart A: General Provisions
NESHAP Subpart FF: Benzene Waste Operations
MACT Subpart A: General Provisions
MACT Subpart CC: Petroleum Refineries
MACT Subpart UUU: Petroleum Refineries: Unit Specific
MACT Subpart EEEE: Organic Liquids Distribution (Non-Gasoline)
MACT Subpart ZZZZ: Stationary RICE
MACT Subpart DDDDD: Industrial, Commercial, Institutional Boilers and Heaters
PM2.5 SIP Evaluation Report: Chevron Products Company – Salt Lake 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
FCC SO2- Rolling 7 Day Average
Chevron
Total Data Entries 3,189 Min (ppm) 0 Min (ppm) 0 Min (ppm) 0 Min (ppm) 0
Total Invalid Day Entries 0 Max (ppm) 57 Max (ppm) 57 Max (ppm) 47 Max (ppm) 47
% Total Invalid Day Entries 0.00% Average (ppm) 12 Average (ppm) 12 Average (ppm) 12 Average (ppm) 12
% Un-Matched Data 73.78% Standard Deviation 7 Standard Deviation 7 Standard Deviation 7 Standard Deviation 7
%Un-Matched Bad Data (>1) 38.48%
%Un-Matched Bad Data (>3) 13.48% 10th 3 10th 0 10th 3 10th 3
%Un-Matched Bad Data (>5) 5.39% 20th 6 20th 6 20th 6 20th 6
%Un-Matched Bad Data (>7) 1.94% 30th 8 30th 8 30th 8 30th 8
Limit (ppm SO2) 50 40th 10 40th 10 40th 10 40th 10
Total Data Entries <= 0 4 50th 12 50th 12 50th 12 50th 12
% Total Data Entries <= 0 0.13% 60th 14 60th 14 60th 14 60th 14
Total Data Entries > Limit 4 70th 16 70th 16 70th 16 70th 16
% Total Data Entries > Limit 0.13% 80th 18 80th 18 80th 18 80th 18
90th 21 90th 21 90th 21 90th 21
97th 25 97th 25 97th 25 97th 25
99th 30 99th 30 99th 29 99th 29
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 5 524 16.43% <10% of Limit 5 520 16.33% <10% of Limit 5 524 16.45% <10% of Limit 5 520 16.35%
<20% of Limit 10 1,240 38.88% <20% of Limit 10 1,236 38.81% <20% of Limit 10 1,240 38.93% <20% of Limit 10 1,236 38.86%
<30% of Limit 15 2,093 65.63% <30% of Limit 15 2,089 65.59% <30% of Limit 15 2,093 65.71% <30% of Limit 15 2,089 65.67%
<40% of Limit 20 2,784 87.30% <40% of Limit 20 2,780 87.28% <40% of Limit 20 2,784 87.41% <40% of Limit 20 2,780 87.39%
<50% of Limit 25 3,100 97.21% <50% of Limit 25 3,096 97.21% <50% of Limit 25 3,100 97.33% <50% of Limit 25 3,096 97.33%
<60% of Limit 30 3,160 99.09% <60% of Limit 30 3,156 99.09% <60% of Limit 30 3,160 99.22% <60% of Limit 30 3,156 99.21%
<70% of Limit 35 3,177 99.62% <70% of Limit 35 3,173 99.62% <70% of Limit 35 3,177 99.75% <70% of Limit 35 3,173 99.75%
<80% of Limit 40 3,184 99.84% <80% of Limit 40 3,180 99.84% <80% of Limit 40 3,184 99.97% <80% of Limit 40 3,180 99.97%
<90% of Limit 45 3,184 99.84% <90% of Limit 45 3,180 99.84% <90% of Limit 45 3,184 99.97% <90% of Limit 45 3,180 99.97%
<=100% of Limit 50 3,185 99.87% <=100% of Limit 50 3,181 99.87% <=100% of Limit 50 3,185 100.00% <=100% of Limit 50 3,181 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification - SO2 Data Analysis - All Data Included (SO2) Data Analysis - Excluding All Data <= 0 (SO2) Data Analysis - Excluding All Data > 50 (SO2) Data Analysis - Excluding All Data <= 0 and > 50 (SO2)
UDAQ 2023 Data Request - UDAQ Analysis and Summary
FCC NOX- Rolling 7 Day Average
Chevron
Total Data Entries 3,189 Min (ppm) 0 Min (ppm) 0 Min (ppm) 0 Min (ppm) 0
Total Invalid Day Entries 0 Max (ppm) 66 Max (ppm) 66 Max (ppm) 66 Max (ppm) 66
% Total Invalid Day Entries 0.00% Average (ppm) 21 Average (ppm) 21 Average (ppm) 21 Average (ppm) 21
% Un-Matched Data 91.66% Standard Deviation 11 Standard Deviation 11 Standard Deviation 11 Standard Deviation 11
%Un-Matched Bad Data (>1) 71.78%
%Un-Matched Bad Data (>7) 13% 10th 9 10th 9 10th 9 10th 9
Limit (ppm NOX) 106 20th 12 20th 12 20th 12 20th 12
Total Data Entries <= 0 0 30th 14 30th 14 30th 14 30th 14
% Total Data Entries <= 0 0.00% 40th 16 40th 16 40th 16 40th 16
Total Data Entries > Limit 0 50th 19 50th 19 50th 19 50th 19
% Total Data Entries > Limit 0.00% 60th 22 60th 22 60th 22 60th 22
70th 26 70th 26 70th 26 70th 26
80th 32 80th 32 80th 32 80th 32
90th 38 90th 38 90th 38 90th 38
97th 45 97th 45 97th 45 97th 45
99th 50 99th 50 99th 50 99th 50
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 11 538 16.87% <10% of Limit 11 538 16.87% <10% of Limit 11 538 16.87% <10% of Limit 11 538 16.87%
<20% of Limit 21 1,840 57.70% <20% of Limit 21 1,840 57.70% <20% of Limit 21 1,840 57.70% <20% of Limit 21 1,840 57.70%
<30% of Limit 32 2,572 80.65% <30% of Limit 32 2,572 80.65% <30% of Limit 32 2,572 80.65% <30% of Limit 32 2,572 80.65%
<40% of Limit 42 2,998 94.01% <40% of Limit 42 2,998 94.01% <40% of Limit 42 2,998 94.01% <40% of Limit 42 2,998 94.01%
<50% of Limit 53 3,173 99.50% <50% of Limit 53 3,173 99.50% <50% of Limit 53 3,173 99.50% <50% of Limit 53 3,173 99.50%
<60% of Limit 64 3,185 99.87% <60% of Limit 64 3,185 99.87% <60% of Limit 64 3,185 99.87% <60% of Limit 64 3,185 99.87%
<70% of Limit 74 3,189 100.00% <70% of Limit 74 3,189 100.00% <70% of Limit 74 3,189 100.00% <70% of Limit 74 3,189 100.00%
<80% of Limit 85 3,189 100.00% <80% of Limit 85 3,189 100.00% <80% of Limit 85 3,189 100.00% <80% of Limit 85 3,189 100.00%
<90% of Limit 95 3,189 100.00% <90% of Limit 95 3,189 100.00% <90% of Limit 95 3,189 100.00% <90% of Limit 95 3,189 100.00%
<=100% of Limit 106 3,189 100.00% <=100% of Limit 106 3,189 100.00% <=100% of Limit 106 3,189 100.00% <=100% of Limit 106 3,189 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification - NOX Data Analysis - All Data Included (NOX) Data Analysis - Excluding All Data <= 0 (NOX) Data Analysis - Excluding All Data > 106 (NOX) Data Analysis - Excluding All Data <= 0 and > 106 (NOX)
UDAQ 2023 Data Request - UDAQ Analysis and Summary
Flare 1 H2S - Rolling 3-Hour Average
Chrevon
Total Data Entries 43,817 Min (ppm) 0 Min (ppm) 0.00 Min (ppm) 0 Min (ppm) 0
Total Invalid Hour Entries 140 Max (ppm) 352 Max (ppm) 352 Max (ppm) 162 Max (ppm) 162
% Total Invalid Hour Entries 0.32% Average (ppm) 3.55 Average (ppm) 3.57 Average (ppm) 2 Average (ppm) 2
% Un-Matched Data 5.60% Standard Deviation 21.41 Standard Deviation 21.48 Standard Deviation 11 Standard Deviation 11
%Un-Matched Bad Data >1 1.73%
%Un-Matched Bad Data >3 1.09% 10th 0 10th 0 10th 0 10th 0
%Un-Matched Bad Data >5 0.83% 20th 0 20th 0 20th 0 20th 0
Limit (ppm H2S) 162 30th 0 30th 0 30th 0 30th 0
Total Data Entries = 0 284 40th 0 40th 0 40th 0 40th 0
% Total Data Entries = 0 0.65% 50th 0 50th 0 50th 0 50th 0
Total Data Entries > Limit 290 60th 0 60th 0 60th 0 60th 0
% Total Data Entries > Limit 0.66% 70th 0 70th 0 70th 0 70th 0
80th 0 80th 0 80th 0 80th 0
90th 0 90th 1 90th 1 90th 1
97th 26 97th 26 97th 19 97th 19
99th 114 99th 115 99th 55 99th 55
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 41,905 95.94% <10% of Limit 16 41,621 95.92% <10% of Limit 16 41,905 96.58% <10% of Limit 16 41,621 96.56%
<20% of Limit 32 42,588 97.51% <20% of Limit 32 42,304 97.49% <20% of Limit 32 42,588 98.16% <20% of Limit 32 42,304 98.15%
<30% of Limit 49 42,883 98.18% <30% of Limit 49 42,599 98.17% <30% of Limit 49 42,883 98.84% <30% of Limit 49 42,599 98.83%
<40% of Limit 65 43,035 98.53% <40% of Limit 65 42,751 98.52% <40% of Limit 65 43,035 99.19% <40% of Limit 65 42,751 99.18%
<50% of Limit 81 43,122 98.73% <50% of Limit 81 42,838 98.72% <50% of Limit 81 43,122 99.39% <50% of Limit 81 42,838 99.39%
<60% of Limit 97 43,192 98.89% <60% of Limit 97 42,908 98.88% <60% of Limit 97 43,192 99.55% <60% of Limit 97 42,908 99.55%
<70% of Limit 113 43,234 98.99% <70% of Limit 113 42,950 98.98% <70% of Limit 113 43,234 99.65% <70% of Limit 113 42,950 99.65%
<80% of Limit 130 43,298 99.13% <80% of Limit 130 43,014 99.13% <80% of Limit 130 43,298 99.79% <80% of Limit 130 43,014 99.79%
<90% of Limit 146 43,344 99.24% <90% of Limit 146 43,060 99.23% <90% of Limit 146 43,344 99.90% <90% of Limit 146 43,060 99.90%
<=100% of Limit 162 43,387 99.34% <=100% of Limit 162 43,103 99.33% <=100% of Limit 162 43,387 100.00% <=100% of Limit 162 43,103 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data = 0 Data Analysis - Excluding All Data > 162 Data Analysis - Excluding All Data = 0 and > 162
UDAQ 2023 Data Request - UDAQ Analysis and Summary
Flare 2 H2S - Rolling 3-Hour Average
Chrevon
Total Data Entries 43,817 Min (ppm) 0.00 Min (ppm) 0.00 Min (ppm) 0 Min (ppm) 0
Total Invalid Hour Entries 171 Max (ppm) 377 Max (ppm) 377 Max (ppm) 162 Max (ppm) 162
% Total Invalid Hour Entries 0.39% Average (ppm) 8.53 Average (ppm) 8.90 Average (ppm) 5 Average (ppm) 6
% Un-Matched Data 11.00% Standard Deviation 31.66 Standard Deviation 32.28 Standard Deviation 18 Standard Deviation 18
%Un-Matched Bad Data >1 3.38%
%Un-Matched Bad Data >3 1.92% 10th 0 10th 0 10th 0 10th 0
%Un-Matched Bad Data >5 1.49% 20th 0 20th 0 20th 0 20th 0
Limit (ppm H2S) 162 30th 0 30th 0 30th 0 30th 0
Total Data Entries = 0 1,802 40th 0 40th 0 40th 0 40th 0
% Total Data Entries = 0 4.13% 50th 0 50th 0 50th 0 50th 0
Total Data Entries > Limit 623 60th 0 60th 0 60th 0 60th 0
% Total Data Entries > Limit 1.43% 70th 1 70th 1 70th 1 70th 1
80th 4 80th 4 80th 3 80th 4
90th 0 90th 14 90th 10 90th 11
97th 86 97th 88 97th 54 97th 56
99th 195 99th 199 99th 105 99th 106
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 39,692 90.94% <10% of Limit 16 37,890 90.55% <10% of Limit 16 39,692 92.26% <10% of Limit 16 37,890 87.14%
<20% of Limit 32 40,874 93.65% <20% of Limit 32 39,072 93.38% <20% of Limit 32 40,874 95.00% <20% of Limit 32 39,072 94.79%
<30% of Limit 49 41,562 95.23% <30% of Limit 49 39,760 95.02% <30% of Limit 49 41,562 96.60% <30% of Limit 49 39,760 96.46%
<40% of Limit 65 41,989 96.20% <40% of Limit 65 40,187 96.04% <40% of Limit 65 41,989 97.60% <40% of Limit 65 40,187 97.49%
<50% of Limit 81 42,261 96.83% <50% of Limit 81 40,459 96.69% <50% of Limit 81 42,261 98.23% <50% of Limit 81 40,459 98.15%
<60% of Limit 97 42,498 97.37% <60% of Limit 97 40,696 97.26% <60% of Limit 97 42,498 98.78% <60% of Limit 97 40,696 98.73%
<70% of Limit 113 42,689 97.81% <70% of Limit 113 40,887 97.71% <70% of Limit 113 42,689 99.22% <70% of Limit 113 40,887 99.19%
<80% of Limit 130 42,842 98.16% <80% of Limit 130 41,040 98.08% <80% of Limit 130 42,842 99.58% <80% of Limit 130 41,040 99.56%
<90% of Limit 146 42,937 98.38% <90% of Limit 146 41,135 98.31% <90% of Limit 146 42,937 99.80% <90% of Limit 146 41,135 99.79%
<=100% of Limit 162 43,023 98.57% <=100% of Limit 162 41,221 98.51% <=100% of Limit 162 43,023 100.00% <=100% of Limit 162 41,221 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data = 0 Data Analysis - Excluding All Data > 162 Data Analysis - Excluding All Data = 0 and > 162
UDAQ 2023 Data Request - UDAQ Analysis and Summary
Flare 3 H2S - Rolling 3-Hour Average
Chrevon
Total Data Entries 43,817 Min (ppm) 0.00 Min (ppm) 0.00 Min (ppm) 0 Min (ppm) 0
Total Invalid Hour Entries 5 Max (ppm) 300 Max (ppm) 300 Max (ppm) 148 Max (ppm) 148
% Total Invalid Hour Entries 0.01% Average (ppm) 0.58 Average (ppm) 5.65 Average (ppm) 0 Average (ppm) 4
% Un-Matched Data 22.52% Standard Deviation 8.27 Standard Deviation 25.35 Standard Deviation 4 Standard Deviation 12
%Un-Matched Bad Data >1 10.94%
%Un-Matched Bad Data >5 4.65% 10th 0 10th 0 10th 0 10th 0
Limit (ppm H2S) 162 20th 0 20th 0 20th 0 20th 0
Total Data Entries = 0 39,349 30th 0 30th 0 30th 0 30th 0
% Total Data Entries = 0 89.81% 40th 0 40th 0 40th 0 40th 0
Total Data Entries > Limit 29 50th 0 50th 0 50th 0 50th 0
% Total Data Entries > Limit 0.07% 60th 0 60th 0 60th 0 60th 0
70th 0 70th 1 70th 0 70th 1
80th 0 80th 2 80th 0 80th 2
90th 0 90th 8 90th 0 90th 8
97th 1 97th 51 97th 1 97th 39
99th 9 99th 81 99th 8 99th 71
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 43,507 99.30% <10% of Limit 16 4,158 93.17% <10% of Limit 16 43,507 99.37% <10% of Limit 16 4,158 93.78%
<20% of Limit 32 43,627 99.58% <20% of Limit 32 4,278 95.85% <20% of Limit 32 43,627 99.64% <20% of Limit 32 4,278 96.48%
<30% of Limit 49 43,676 99.69% <30% of Limit 49 4,327 96.95% <30% of Limit 49 43,676 99.76% <30% of Limit 49 4,327 97.59%
<40% of Limit 65 43,713 99.77% <40% of Limit 65 4,364 97.78% <40% of Limit 65 43,713 99.84% <40% of Limit 65 4,364 98.42%
<50% of Limit 81 43,769 99.90% <50% of Limit 81 4,420 99.04% <50% of Limit 81 43,769 99.97% <50% of Limit 81 4,420 99.68%
<60% of Limit 97 43,777 99.92% <60% of Limit 97 4,428 99.22% <60% of Limit 97 43,777 99.99% <60% of Limit 97 4,428 99.86%
<70% of Limit 113 43,780 99.93% <70% of Limit 113 4,431 99.28% <70% of Limit 113 43,780 99.99% <70% of Limit 113 4,431 99.93%
<80% of Limit 130 43,782 99.93% <80% of Limit 130 4,433 99.33% <80% of Limit 130 43,782 100.00% <80% of Limit 130 4,433 99.98%
<90% of Limit 146 43,782 99.93% <90% of Limit 146 4,433 99.33% <90% of Limit 146 43,782 100.00% <90% of Limit 146 4,433 99.98%
<=100% of Limit 162 43,783 99.93% <=100% of Limit 162 4,434 99.35% <=100% of Limit 162 43,783 100.00% <=100% of Limit 162 4,434 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data = 0 Data Analysis - Excluding All Data > 162 Data Analysis - Excluding All Data = 0 and > 162
UDAQ 2023 Data Request - UDAQ Analysis and Summary
RFG H2S - Rolling 3-Hour Average & Rolling 365-Day Average
Chevron
Total Data Entries 43,817 Min (ppm) 0 Min (ppm) 0 Min (ppm) 0 Min (ppm) 0
Total Invalid Hour Entries 4 Max (ppm) 300 Max (ppm) 300 Max (ppm) 162 Max (ppm) 162
% Total Invalid Hour Entries 0.01% Average (ppm) 2.40 Average (ppm) 7 Average (ppm) 2 Average (ppm) 5
% Un-Matched Data 15.21% Standard Deviation 12.58 Standard Deviation 20 Standard Deviation 7 Standard Deviation 11
%Un-Matched Bad Data <1 5.84%
%Un-Matched Bad Data <5 1.64% 10th 0 10th 0 10th 0 10th 0
Limit (ppm H2S) 162 20th 0 20th 0 20th 0 20th 0
Total Data Entries <= 0 28,111 30th 0 30th 0 30th 0 30th 0
% Total Data Entries <= 0 64.16% 40th 0 40th 1 40th 0 40th 1
Total Data Entries > Limit 84 50th 0 50th 2 50th 0 50th 2
% Total Data Entries > Limit 0.19% 60th 0 60th 5 60th 0 60th 5
70th 0 70th 6 70th 0 70th 6
80th 2 80th 8 80th 1 80th 8
Total Data Entries 1,461 90th 7 90th 11 90th 7 90th 11
Total Invalid Hour Entries 11 97th 12 97th 28 97th 12 97th 22
% Total Invalid Hour Entries 0.75% 99th 30 99th 93 99th 24 99th 60
% Un-Matched Data 1.30%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
%Un-Matched Bad Data<1 0.00% <10% of Limit 16 43,102 98.38% <10% of Limit 16 14,991 95.47% <10% of Limit 16 43,102 98.57% <10% of Limit 16 14,991 95.99%
Limit (ppm H2S) 60 <20% of Limit 32 43,396 99.05% <20% of Limit 32 15,285 97.34% <20% of Limit 32 43,396 99.24% <20% of Limit 32 15,285 97.87%
Total Data Entries = 0 0 <30% of Limit 49 43,528 99.35% <30% of Limit 49 15,417 98.18% <30% of Limit 49 43,528 99.54% <30% of Limit 49 15,417 98.71%
% Total Data Entries = 0 0.00% <40% of Limit 65 43,597 99.51% <40% of Limit 65 15,486 98.62% <40% of Limit 65 43,597 99.70% <40% of Limit 65 15,486 99.15%
Total Data Entries > Limit 0 <50% of Limit 81 43,623 99.57% <50% of Limit 81 15,512 98.79% <50% of Limit 81 43,623 99.76% <50% of Limit 81 15,512 99.32%
% Total Data Entries > Limit 0.00% <60% of Limit 97 43,659 99.65% <60% of Limit 97 15,548 99.02% <60% of Limit 97 43,659 99.84% <60% of Limit 97 15,548 99.55%
<70% of Limit 113 43,692 99.72% <70% of Limit 113 15,581 99.23% <70% of Limit 113 43,692 99.92% <70% of Limit 113 15,581 99.76%
<80% of Limit 130 43,705 99.75% <80% of Limit 130 15,594 99.31% <80% of Limit 130 43,705 99.95% <80% of Limit 130 15,594 99.85%
<90% of Limit 146 43,716 99.78% <90% of Limit 146 15,605 99.38% <90% of Limit 146 43,716 99.97% <90% of Limit 146 15,605 99.92%
<=100% of Limit 162 43,729 99.81% <=100% of Limit 162 15,618 99.47% <=100% of Limit 162 43,729 100.00% <=100% of Limit 162 15,618 100.00%
Min (ppm) 1
Max (ppm) 3.80
Average (ppm) 2.17
Standard Deviation 0.89
10th 0.99
20th 1.24
30th 1.56
40th 1.95
50th 2.18
60th 2.40
70th 2.75
80th 2.92
90th 3.50
97th 3.78
99th 3.79
Percentage of Limit Value (ppm) Total Data Points % of Total Data
<10% of Limit 6 1,826 125.93%
<20% of Limit 12 1,826 125.93%
<30% of Limit 18 1,826 125.93%
<40% of Limit 24 1,826 125.93%
<50% of Limit 30 1,826 125.93%
<60% of Limit 36 1,826 125.93%
<70% of Limit 42 1,826 125.93%
<80% of Limit 48 1,826 125.93%
<90% of Limit 54 1,826 125.93%
<=100% of Limit 60 1,826 125.93%
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 - Hourly/3-Hr Average Data Analysis - All Data Included (3-Hr Average)
UDAQ 2023 Data Request - UDAQ Analysis and Summary
SRU 1 SO2 - Rolling 12-Hour Average
CHEVRON
Total Data Entries 43,808 Min (ppm) 0 Min (ppm) 0.00053004 Min (ppm) 0 Min (ppm) 0.0
Total Invalid Hour Entries 19 Max (ppm) 952 Max (ppm) 952 Max (ppm) 10 Max (ppm) 249.9
% Total Invalid Hour Entries 0.04% Average (ppm) 146.88 Average (ppm) 156.40 Average (ppm) 95.1 Average (ppm) 102.0
% Un-Matched Data 54.62% Standard Deviation 178.31 Standard Deviation 179.91 Standard Deviation 41.60 Standard Deviation 34.0
%Un-Matched Bad Data <1 22.69%
%Un-Matched Bad Data <5 9.82% 10th 54 10th 65 10th 48 10th 63.9
Limit (ppm VOC) 250 20th 70 20th 76 20th 68 20th 74.0
Total Data Entries = 0 2,664 30th 81 30th 87 30th 78 30th 82.5
% Total Data Entries = 0 6.08% 40th 94 40th 97 40th 89 40th 93.5
Total Data Entries > Limit 4,094 50th 102 50th 106 50th 98 50th 100.9
% Total Data Entries > Limit 9.35% 60th 115 60th 118 60th 107 60th 110.8
70th 126 70th 128 70th 119 70th 121.4
80th 138 80th 140 80th 129 80th 130.2
90th 202 90th 248 90th 141 90th 141.4
97th 790 97th 804 97th 159 97th 160.1
99th 918 99th 920 99th 186 99th 189.3
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 25 3,518 8.03% <10% of Limit 25 854 2.08% <10% of Limit 25 3,518 8.86% <10% of Limit 25 854 2.31%
<20% of Limit 50 4,088 9.34% <20% of Limit 50 1,424 3.46% <20% of Limit 50 4,088 10.30% <20% of Limit 50 1,424 3.85%
<30% of Limit 75 10,447 23.86% <30% of Limit 75 7,783 18.93% <30% of Limit 75 10,447 26.32% <30% of Limit 75 7,783 21.02%
<40% of Limit 100 20,733 47.35% <40% of Limit 100 18,069 43.94% <40% of Limit 100 20,733 52.23% <40% of Limit 100 18,069 48.79%
<50% of Limit 125 30,128 68.80% <50% of Limit 125 27,464 66.78% <50% of Limit 125 30,128 75.90% <50% of Limit 125 27,464 74.16%
<60% of Limit 150 37,764 86.24% <60% of Limit 150 35,100 85.35% <60% of Limit 150 37,764 95.14% <60% of Limit 150 35,100 94.79%
<70% of Limit 175 39,101 89.29% <70% of Limit 175 36,437 88.60% <70% of Limit 175 39,101 98.50% <70% of Limit 175 36,437 98.40%
<80% of Limit 200 39,400 89.98% <80% of Limit 200 36,736 89.33% <80% of Limit 200 39,400 99.26% <80% of Limit 200 36,736 99.20%
<90% of Limit 225 39,552 90.32% <90% of Limit 225 36,888 89.70% <90% of Limit 225 39,552 99.64% <90% of Limit 225 36,888 99.61%
<=100% of Limit 250 39,695 90.65% <=100% of Limit 250 37,031 90.04% <=100% of Limit 250 39,695 100.00% <=100% of Limit 250 37,031 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data = 0 Data Analysis - Excluding All Data > 250 Data Analysis - Excluding All Data = 0 and > 250
UDAQ 2023 Data Request - UDAQ Analysis and Summary
SRU 2 SO2 - Rolling 12-Hour Average
CHEVRON
Total Data Entries 43,808 Min (ppm) -19 Min (ppm) 0 Min (ppm) -19 Min (ppm) 0
Total Invalid Hour Entries 0 Max (ppm) 6921 Max (ppm) 6921 Max (ppm) 250 Max (ppm) 250
% Total Invalid Hour Entries 0.00% Average (ppm) 136 Average (ppm) 141 Average (ppm) 113 Average (ppm) 118
% Un-Matched Data 56.57% Standard Deviation 197 Standard Deviation 199 Standard Deviation 40 Standard Deviation 34
%Un-Matched Bad Data <1 22.60%
%Un-Matched Bad Data <5 6.30% 10th 77 10th 80 10th 77 10th 80
Limit (ppm VOC) 250 20th 87 20th 89 20th 86 20th 88
Total Data Entries = 0 1,513 30th 95 30th 97 30th 94 30th 96
% Total Data Entries = 0 3.45% 40th 103 40th 104 40th 102 40th 103
Total Data Entries > Limit 1,493 50th 111 50th 113 50th 109 50th 111
% Total Data Entries > Limit 3.41% 60th 122 60th 124 60th 119 60th 121
70th 134 70th 136 70th 132 70th 133
80th 148 80th 149 80th 144 80th 145
90th 172 90th 173 90th 163 90th 164
97th 289 97th 308 97th 191 97th 191
99th 759 99th 790 99th 220 99th 221
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 25 1,688 3.85% <10% of Limit 25.0 175 0.41% <10% of Limit 25 1,688 3.99% <10% of Limit 25 175 0.43%
<20% of Limit 50 1,824 4.16% <20% of Limit 50.0 311 0.74% <20% of Limit 50 1,824 4.31% <20% of Limit 50 311 0.76%
<30% of Limit 75 3,492 7.97% <30% of Limit 75.0 1,979 4.68% <30% of Limit 75 3,492 8.25% <30% of Limit 75 1,979 4.85%
<40% of Limit 100 15,999 36.52% <40% of Limit 100.0 14,486 34.25% <40% of Limit 100 15,999 37.81% <40% of Limit 100 14,486 35.50%
<50% of Limit 125 27,426 62.61% <50% of Limit 125.0 25,913 61.27% <50% of Limit 125 27,426 64.81% <50% of Limit 125 25,913 63.51%
<60% of Limit 150 35,541 81.13% <60% of Limit 150.0 34,028 80.45% <60% of Limit 150 35,541 83.99% <60% of Limit 150 34,028 83.40%
<70% of Limit 175 39,810 90.87% <70% of Limit 175.0 38,297 90.55% <70% of Limit 175 39,810 94.08% <70% of Limit 175 38,297 93.86%
<80% of Limit 200 41,408 94.52% <80% of Limit 200.0 39,895 94.33% <80% of Limit 200 41,408 97.86% <80% of Limit 200 39,895 97.78%
<90% of Limit 225 41,957 95.77% <90% of Limit 225.0 40,444 95.62% <90% of Limit 225 41,957 99.15% <90% of Limit 225 40,444 99.12%
<=100% of Limit 250 42,315 96.59% <=100% of Limit 250.0 40,802 96.47% <=100% of Limit 250 42,315 100.00% <=100% of Limit 250 40,802 100.00%
Percentiles (ppm): Percentiles (ppm): Percentiles (ppm): Percentiles (ppm):
Data Verification Data Analysis - All Data Included Data Analysis - Excluding All Data = 0 Data Analysis - Excluding All Data > 250 Data Analysis - Excluding All Data = 0 and > 250
UDAQ 2023 Data Request - UDAQ Analysis and Summary
Boiler 7 NOx - Daily Average
CHEVRON
Total Data Entries 1,803 Min (ppm) 0
Total Invalid Hour Entries 0 Max (ppm) 278
% Total Invalid Hour Entries 0.00% Average (ppm) 53
% Un-Matched Data 92.29% Standard Deviation 14
%Un-Matched Bad Data <1 76.87%
%Un-Matched Bad Data <12 12.70% 10th 36
Limit (NOx) None 20th 45
Total Data Entries = 0 1 30th 50
% Total Data Entries = 0 0.06% 40th 53
50th 54
60th 56
70th 58
80th 60
90th 62
97th 70
99th 97
Data Verification Data Analysis - All Data Included
Percentiles (ppm):
PM2.5 SIP Evaluation Report: Chevron Products Company – Salt Lake Refinery Salt Lake City PM2.5 Serious Nonattainment Area Utah Division of Air Quality Major New Source Review Section Appendix C
Chevron 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)[6]
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)
F-11005 Boiler #5 171.0 0.20 8,345 142.70 10.11 5.58 1.92 7.49 0.15
F-11006 Boiler #6 171.0 0.20 8,290 141.76 8.29 5.58 2.44 7.49 0.19
F-11007 Boiler #7[4]225.0 0.20 8,760 197.10 21.31 7.34 2.25 9.86 0.03
F-21001 Crude Furnace #1[5]130.0 0.09 8,728 51.06 11.56 4.24 1.76 5.69 0.14
F-21002 Crude Furnace #2[5]115.1 0.09 8,728 45.21 11.56 3.76 1.76 5.04 0.14
F-32021 FCC Furnace #1 48.2 0.17 8,488 34.78 7.03 1.57 0.53 2.11 0.04
F-32023 FCC Furnace #2 48.2 0.17 8,488 34.78 5.16 1.57 0.39 2.11 0.03
F-35001 Reformer Furnace F-1 52.3 0.17 8,057 35.82 8.33 1.71 0.63 2.29 0.05
F-35002 Reformer Furnace F-2 45.0 0.17 8,057 30.82 8.33 1.47 0.63 1.97 0.05
F-36017 Alkylation Furnace 108.0 0.12 8,760 56.76 10.28 3.52 1.56 4.73 0.12
F-70001 Coker Furnace 139.2 0.16 8,393 93.46 18.33 4.54 1.39 6.10 0.11
F-66100 VGO Furnace #1 40.0 0.05 7,928 7.93 2.20 1.31 0.52 1.75 0.04
F-66200 VGO Furnace #2 66.0 0.05 7,972 13.15 3.54 2.15 0.84 2.89 0.07
885.32 126.02 44.35 16.61 59.52 1.15
[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 #7 based on 2019 inventory (not installed in 2017)
[5] Crude Furnace #1 and #2 reported together in 2017 inventory
[6]Calculated using 2017 Hours of Operation
Source-wide PM2.5 limit adopted by AQB July 1, 2018: 110.0 tons/yr
Source-wide NOx Limit adopted by AQB July 1, 2018: 766.5 tons/yr
Source-wide SO2 Limit adopted by AQB July 1, 2018: 393.3 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]