Document na1vbZ9nNE60x1o4BxmDdNXm

MountainWest Pipeline - Fidlar Compressor Station Full Compliance Evaluation (FCE) On-Site Inspection Inspection Date: September 16, 2024 Inspection Report Date: October 7, 2024 EPA Representatives: Michael Stovern, Colin Schwartz, Chris Andrade, James Floyd Tribal Representatives: Lonnie Favel, Alverna Nelson Company Representatives: Rod White, Derek Forsberg, Les Barney, Jean Semborski Inspection Report Prepared By: Michael Stovern - Environmental Scientist, Air & Toxics Technical Enforcement, US EPA Inspection Report Reviewed By: Last Inspection: Scott Patefield - Manager, Air & Toxics Technical Enforcement, US EPA SCOTT PATEFIELD Date: 2024.11.04 14:03:21 -07'00' Digitally signed by SCOTT PATEFIELD March 12, 2019 Operating Status: Operating Applicable Requirements: Title V; 40 CFR Part 60, Subpart GG - Standards of Performance for Stationary Gas Turbines; 40 CFR Part 60, Subpart JJJJ Standards of Performance for Stationary Spark Ignition Internal Combustion Engines; 40 CFR Part 63, Subpart ZZZZ - National Emissions Standards for Hazardous Pollutants for Stationary Reciprocating Internal Combustion Engines Title V Permit Number: V-UO-000002-2013.00 Replaces Permit Number: V-OU-0002-05.01 MNSR Permit Number: SMNSR-UO-000002-2017.003 Issue Date: January 8, 2018 Effective Date: February 7, 2018 Expiration Date: February 7, 2023 Issue Date: March 5, 2018 Facility Information and Emission Unit Identification Parent Company Name: Plant Operator & Name: Plant Location: County, State: Reservation: Tribe: Responsible Official: SIC Code: Dominion Energy Questar Pipeline, LLC (Dominion) Fidlar Compressor Station (Fidlar) SW , NW , Section 16, T9S, R22E Latitude 40.038898, Longitude -109.453585 Uintah, Utah Uintah & Ouray Indian Reservation Ute Indian Tribe Vice President, Western Pipeline Operations 4922 - Natural Gas Transmission 1 AFS ID: Other CAA Permits: 49-047-00023 Tribal Minor New Source Review (MNSR) permit number SMNSR-UO-0000022013.001 incorporates the requested emission limits for Engine FS02, which are outlined in Section V of the Title V permit. Overall Inspection Findings: No concerns were identified during the inspection. This final inspection report is not a final determination of compliance. Description of Operations The Fidlar Compressor Station (Fidlar) receives natural gas from and delivers it to any one of Dominion's main lines that transport natural gas east, west and north to existing markets and interconnecting points with other interstate pipelines. There are currently four compressors operating at Fidlar. Natural gas-fired turbine drive three compressors, and a natural-gas fired internal combustion engine drives the other compressor. The facility is also equipped with a natural gas-fired reciprocating internal combustion engine used to drive a standby emergency generator. The generator provides electric power to the compressor station during power outages only. All equipment at Fidlar burns pipeline quality natural gas as its only fuel source. Natural gas enters the station then passes through separator tanks, which allow any entrained liquids to drop out of the natural gas. Liquids and sludge are temporarily stored on site and then removed by truck. The natural gas then passes through gas scrubbers consisting of cloth type filters to remove gas laden impurities. Impurities are occasionally blown to the pressurized storage vessel or sludge tank. Natural gas pressure is then boosted by the compressor units. After compression, the natural gas is cooled by cooling fans which draw ambient air over the pipes to the cool the gas. There is no contact between the cooling air and natural gas. There are numerous shutdown and relief valves associated with the facility. A natural gas fired boiler provides heat to the buildings. A natural gas fired line heater is used to prevent station fuel gas line freezing. General Inspection Observations and Commentary This Full Compliance Evaluation (FCE) was conducted via an on-site inspection and follow-up record review. Opening Meeting: The EPA inspectors, Tribal reps and Williams staff met at the Chipeta gas plant facility at 2:15 pm on 9/16/2024. The inspectors presented their credentials to the staff and made introductions. The inspectors started the opening meeting at 3:00 pm by stating that the purpose of the inspection was to complete a Full Compliance Evaluation (FCE) of the facility with respect to all applicable Clean Air Act (CAA) regulations. The inspectors started by asked a series of questions regarding facility operations, monitoring and recordkeeping. The opening meeting was completed at 3:15 pm. Walk Through Inspection Observations: 2 No equipment was operating at the time of the inspection. The facility walkthrough started at the inlet pig catcher area that serviced mainlines 80, 103, 59 and 40. Inlet pressures for these pipeline vary between 6501000 psi. outlet pressures from the facility are 850-900 psi. Buildings identified during the facility walkthrough include: supply shed, motor control center for electrical, telecom, boiler for heat trace, tool shed and a GC building. The boiler for heat trace was identified as Weil Mclain, Model 88 series 1. One tank was identified onsite and is used for pigging, scrubber and slug catcher liquids. The tank was uncontrolled and there was emissions coming from it as observed using OGI (see MOV_3562). Both the suction and discharge ESD vents were observed to be leaking during the inspection (see MOV_3561). Two Solar Saturn 10 turbines (FS01 and FS03) were identified and not operational at the time of the inspection. One White Superior engine (FS02) was identified and not operational. One Solar Centaur turbine (FS05) was identified and not operational. Lastly, one generator engine was identified as Cummins GTA-28 (FS07) and was not operational at the time of inspection. Facility walkthrough ended at 4:08 pm. The inspectors began the close out meeting 4:10 pm. The inspectors discussed the emissions observed from the ESD suction and discharge open ended lines and requested that repairs be conducted and verification of repair sent to the EPA inspector in follow-up. The company representatives provided an email with video verification of repairs to the leaking ESD blowdown emissions on 10/4/2024. The close out meeting ended at 4:30 pm. 3 Potential to Emit (PTE) Potential to emit means the maximum capacity of Fidlar to emit any air pollutant under its physical and operational design. The Fidlar Compressor Station is a Title V "major" source (PTE greater than 100 tons per year (tpy) for the following criteria pollutants: nitrogen oxides (NOx) and carbon monoxide (CO)). The potential to emit for Hazardous Air Pollutants (HAP), including formaldehyde (CH2O), is below "major" source thresholds of 10 tpy for a single HAP or 25 tpy for any combination of HAPs. See Table 1, below, for facility-wide and emission unit-specific potential to emit data for Fidlar. The emission data is from EPA's Statement of Basis for the Draft Title V Permit, V-UO-000002-2013.00. Table 1: Potential to Emit in Tons per Year (tpy) Dominion Energy Questar Pipeline, Fidlar Compressor Station1 Emission Unit Id. FS01 FS02 FS03 FS05 FS07 FS08 QPC Tank QPC Loadout Insignificant Units NOx 29.22 20.49 29.22 24.67 0.71 0 0 0 1.07 TOTAL 105.38 NOx - oxides of nitrogen SO2 - sulfur dioxide CO - carbon monoxide VOC 0.11 10.25 0.11 0.36 0.36 4.24 3.45 0.08 Regulated Air Pollutants (tpy) SO2 PM10 CO 0.07 0.34 47.43 0.07 0.97 20.49 0.07 0.34 47.43 0.23 1.13 19.80 <0.010 0.03 1.42 0 0 0 0 0 0 0 0 0 Lead 0 0 0 0 0 0 0 0 0.07 <0.010 0.08 0.90 0 19.02 0.45 2.90 137.46 0 VOC - volatile organic compounds PM10 - particulate matter with a diameter 10 microns or less HAP - hazardous air pollutants (see Clean Air Act Section 112(b)) HAP 0.04 1.42 0.04 0.12 0.05 0.02 0.12 0.003 <0.01 1.82 1 From Title V Permit Statement of Basis for 2013 Permit. 4 Permit Number V-UO-000002-2013.00 Requirements and Compliance Status I. Facility Information and Emission Unit Identification B. Facility Emission Points Table 2: Source Emission Points Emission Unit ID Description (2) 11.16 MMBtu/hr* (1,019 hp*), natural gas-fired turbines for natural gas compression. Solar Saturn T-1001S-205 FS01 FS03 Serial Number: 21035 Installed: 6/20/2016 Serial Number: 20950 Installed: 3/10/2016 (1) 37.05 MMBtu/hr (4,028 hp), natural gas-fired turbine for natural gas compression. Solar Centaur T4700S Control Equipment None Applicable Regulations NSPS Subpart A NSPS Subpart GG None NSPS Subpart A NSPS Subpart GG FS05 FS02 FS07 QPC Tank QPC Tank Loadout Serial Number: OHA16-C0314 Installed: 3/28/2016 (1) 10.79 MMBtu/hr (1,061 hp), natural gas-fired engine for natural gas compression. White Superior 12G-825, 4 stroke rich burn Serial Number: 299499 Installed: 12/3/1983 (1) 6.54 MMBtu/hr (643 hp), natural gas-fired stand by engine for emergency power generator. Cummins GTA28 CC, rich burn Serial Number: 25352466 Installed: 11/18/2010 (1) 400 bbl* condensate sludge storage tank, 42,000 gal/year* throughput Serial Number: unknown Installed: pre-1991 (1) 42,000 gal/year tank truck loading unit Serial Number: unknown Installed: pre-1991 AFR* & NSCR* (installed 9/1995) AFR & NSCR None None NSPS Subpart A NSPS Subpart A NSPS Subpart JJJJ MACT Subpart ZZZZ N/A N/A FS08 Fugitive emissions from valves, seals, pumps, etc. None N/A * MMBtu = million British thermal units; hp = horsepower; AFR = air-to-fuel ratio; NSCR = non-selective catalytic reduction; bbl = barrel; gal/year = gallons per year 5 Equipment FS01 FS03 (2) 1019 hp Solar Saturn T-1001S-205 FS05 (1) 4028 Solar Centaur T4700S FS02 (1) 1061 White Superior 12G-825 Table 3: Requirements for Emission Units Applicable Requirements Limitations Monitoring Method Interval Title V NSPS Subpart GG NOx: 150 ppm SO2: 20.0 grains or less of total sulfur per 100 standard cubic feet of gas NOx: portable analyzer SO2: tariff sheet NOx: Quarterly SO2: N/A Title V NSPS Subpart GG NOx: 167 ppm SO2: 20.0 grains or less of total sulfur per 100 standard cubic feet of gas NOx: portable analyzer SO2: tariff sheet NOx: Quarterly SO2: N/A Title V SMNSR NOx: 2.0 g/hp-hr 4.68 lbs/hr Performance test Annually FS07 (1) 643 hp Cummins GTA28 CC QPC Tank 400 bbl condensate sludge storage tank QPC Tank Loadout 42,000 gal/yr tank truck loading unit FS08 Fugitive Emissions Title V NSPS Subpart JJJJ MACT Subpart ZZZZ N/A N/A N/A NOx: 160 ppmvd at 15% O2 CO: 540 ppmvd at 15% O2 VOC: 86 ppmvd at 15% O2 N/A N/A N/A Performance test Every 3 years or 8,760 hours N/A N/A N/A N/A N/A N/A 6 II. Requirements for Engine Unit FS02 A. Synthetic Minor New Source Review Permit Requirements This source is subject to the requirements of the synthetic Minor New Source Review (MNSR) permit SMNSRUO-000002-2013.001, issued by the EPA on November 1, 2016, in accordance with the requirements at 40 CFR 49.158. The MNSR permit requirements established enforceable restrictions on the emissions of nitrogen oxides (NOX) from engine FS02. Notwithstanding conditions in this permit, the permittee shall comply with all applicable requirements of the MNSR permit. Observations: Nothing to evaluate with this general condition. B. Requirements for Engine Unit FS02 1. Construction and Operational Limits (a) The Permittee shall install, operate and maintain emission controls as specified in the MNSR permit on one (1) reciprocating internal combustion engine used for compression, meeting the following specifications: (i) Operated as a 4-stroke rich-burn (4SRB) engine; (ii) Fired with natural gas; and (iii) Limited to a maximum site rating of 1,061 site rated (hp). (b) Only the engine that is operated and controlled as specified in the MNSR permit is approved for installation under the MNSR permit. Observations: During the inspection a White Superior engine was located on site. However, the engine nameplate could not be identified. 2. Emission Limits (a) NOX emissions from the 1,061 hp 4SRB engine shall not exceed: (1) 4.68 pounds per hour (lb/hr); and (2) 2.0 grams per horsepower-hour (g/hp-hr). (b) Emission limits specified in the MNSR permit shall apply at all times unless otherwise specified in the MNSR permit. Observations: The engine was not running during the inspection. Williams representatives stated that FS02 has not operated since March 2019. During the previous inspection the total runtime was noted as 341. During the facility walkthrough the engine had 346 hours of runtime. It appears the engine ran for about 5 hours since the previous inspection. 7 3. Control and Operational Requirements (a) The Permittee shall ensure that the 1,061 hp 4SRB engine is equipped with an air-to-fuel ratio (AFR) control system and a non-selective catalytic reduction (NSCR) system capable of reducing uncontrolled NOX emissions to meet the emission limits specified in the MNSR permit. (b) The Permittee shall replace the oxygen (O2) sensor on the AFR controller on the 1,061 hp 4SRB engine within every 2,190 hours of engine run time. (c) The Permittee shall install, operate and maintain a temperature-sensing device (i.e., thermocouple or resistance temperature detectors) before the NSCR control system to continuously monitor the exhaust temperature at the inlet of the NSCR control system. The temperature-sensing device shall be calibrated and operated by the Permittee according to manufacturer specifications or equivalent specifications developed by the Permittee or vendor. The temperature-sensing device shall be accurate to within 0.75% of span. (d) Except during startups, which shall not exceed 30 minutes, the engine exhaust temperature at the inlet to the NSCR control system shall be maintained and at all times the engine operated in accordance with the NSCR manufacturer's specifications for optimum performance. (e) During operation, the pressure drop across the NSCR control system on the engine shall be maintained to within 2 inches of water from the baseline pressure drop measured during the most recent performance test. The baseline pressure drop across the NSCR control system shall be determined at 100% 10% of the engine load measured during the most recent performance test. (f) The Permittee shall only fire the engine with natural gas. The natural gas shall be pipeline quality in all respects except that the carbon dioxide (CO2) concentration in the gas is not required to be within pipeline quality. (g) The Permittee shall follow, for the engine and respective NSCR control system, the manufacturer recommended maintenance schedule and procedures, or equivalent maintenance schedule and procedures developed by the Permittee or vendor, to ensure optimum performance of the engine and its respective catalytic control system. (h) The Permittee may rebuild or replace an existing permitted engine with an engine of the same horsepower rating, and configured to operate in the same manner as the engine being rebuilt or replaced. Any emission limits, requirements, control technologies, testing or other provisions that apply to the permitted engine that are replaced shall also apply to the rebuilt or replacement engine. (i) The Permittee may resume operation without the NSCR control system during an engine breakin period, not to exceed 200 operating hours, for rebuilt and replacement engines. Observations: Engine FS02 is equipped with AFR and NSCR for NOx control. The unit was not running at the time of the inspection. Since the unit has not operated for 2,190 hours, no replacement of the O2 sensor on the AFR controller is required. Inlet temperature and pressure drop across the NSCR are continuously measured and recorded when the engine is running. Williams representatives stated that the engine has not operated since March 8 2019 so no temperature and pressure drop data were provided. 4. Performance Testing Requirements (a) Performance tests shall be conducted on the 1,061 hp 4SRB engine for measuring NOX emissions to demonstrate compliance with each emission limitation in the MNSR permit. The performance tests shall be conducted in accordance with appropriate reference methods specified in 40 CFR part 60, appendix A and 40 CFR part 63, appendix A or an EPA-approved American Society for Testing and Materials (ASTM) method. The Permittee may submit to the EPA a written request for approval of an alternate test method, but shall only use that alternate test method after obtaining approval from the EPA. (i) An initial performance test shall be conducted within 45 calendar days of the effective date of the MNSR permit. (ii) Subsequent performance tests shall be conducted within 12 consecutive months after the most recent performance test. (iii) Performance tests shall be conducted within 45 calendar days of startup of the engine after cleaning or replacement of the NSCR control system catalyst. (iv) Performance tests shall be conducted within 45 calendar days of startup of each rebuilt or replaced engine. (b) The Permittee shall not perform engine tuning or make any adjustments to engine settings, NSCR control system settings, processes or operational parameters the day of or during the engine testing. Any such tuning or adjustments may result in a determination by the EPA that the test is invalid. Artificially increasing an engine load to meet test requirements is not considered engine tuning or adjustments. (c) The Permittee shall not abort any engine tests that demonstrate non-compliance with any NOX emission limits in the MNSR permit. (d) Performance tests conducted on the 1,061 hp 4SRB engine for measuring NOX emissions shall meet the following requirements: (i) The pressure drop across the NSCR control system and the inlet temperature to the NSCR control system shall be measured and recorded at least once per test during all performance tests. (ii) The Permittee shall measure carbon monoxide (CO) emissions from the 1,061 hp 4SRB engine simultaneously with all performance tests for NOX emissions. CO emissions shall be measured using a portable analyzer and protocol approved in writing by the EPA. [Note to Permittee: Although the MNSR permit does not contain CO emission limits for this engine, CO measurement requirements have been included as an indicator to ensure compliance with Condition C.4(b) of the MNSR permit (Section II.B in this permit). Questar has received approval from the EPA to use CEMs equipment to measure CO emissions.] (iii) All performance tests shall be conducted at maximum operating rate (90% to 110% of the maximum achievable load available at the time of the test). The Permittee may submit to the EPA a written request for approval of an alternate load level for testing, but shall only test at that alternate load level after obtaining written approval from the EPA. 9 (iv) During each test run, data shall be collected on all parameters necessary to document how emissions were measured and calculated (such as test run length, minimum sample volume, volumetric flow rate, moisture and oxygen corrections, etc.). (v) Each test shall consist of at least three 1-hour or longer valid test runs. Emission results shall be reported as the arithmetic average of all valid test runs and shall be in terms of the emission limits in the MNSR permit. (vi) A performance test plan shall be submitted to the EPA for approval within 30 calendar days of the effective date of the MNSR permit. (vii) Performance test plans that have already been approved by the EPA for the emission unit approved in the MNSR permit may be used in lieu of new test plans unless the EPA requires the submittal and approval of new test plans. The Permittee may submit new plans for EPA approval at any time. (viii) The test plans shall include and address the following elements: (A) Purpose of the test; (B) Engine and NSCR control system to be tested; (C) Expected engine operating rate during the test; (D) Sampling and analysis procedures (sampling locations, test methods, laboratory identification); (E) Quality assurance plan (calibration procedures and frequency, sample recovery and field documentation, chain of custody procedures); and (F) Data processing and reporting (description of data handling and quality control procedures, report content). (e) The Permittee shall notify the EPA at least 30 calendar days prior to a scheduled performance testing. The Permittee shall notify the EPA at least 1 week prior to a scheduled performance testing if the testing cannot be performed. (f) If the results of a complete and valid performance test of the emissions from the permitted engine demonstrate noncompliance with the emission limits in the MNSR permit, the engine shall be shut down as soon as safely possible and appropriate corrective action shall be taken (e.g., repairs, catalyst cleaning, catalyst replacement). The Permittee shall notify the EPA in writing within 24 hours of each such shut down. The engine must be retested within 7 days of being restarted and the emissions must meet the applicable limits in the MNSR permit. If the retest shows that the emissions continue to exceed the limits in the MNSR permit, the engine shall again be shut down as soon as safely possible, and the engine may not operate, except for purposes of startup and testing, until the Permittee demonstrates through testing that the emissions do not exceed the emission limits in the MNSR permit. (g) If a permitted engine is not operating, the Permittee does not need to start up the engine solely to conduct a performance test. The performance test requirements apply when the facility begins operating again. Observations: Engine FS02 has not operated since March 2019 and so no performance tests have been conducted since that date. 10 5. Monitoring Requirements (a) The Permittee shall continuously measure the engine exhaust temperature at the inlet to the NSCR control system at all times the engine operates. (b) Except during startups, which shall not exceed 30 minutes, if the engine's exhaust temperature at the inlet to the NSCR control system deviates from the acceptable range specified by the manufacturer then the following actions shall be taken. The Permittee's completion of any or all of these actions shall not constitute, nor qualify as, an exemption from the NOX emission limits in the MNSR permit. (i) Within 24 hours of determining a deviation of the engine exhaust temperature at the inlet to the NSCR control system, the Permittee shall investigate. The investigation shall include testing the temperature sensing device, inspecting the engine for performance problems and assessing the NSCR control system for possible damage that could affect NSCR control system effectiveness (including, but not limited to, catalyst housing damage and fouled, destroyed or poisoned catalyst). (ii) If the engine exhaust temperature at the inlet to the NSCR control system can be corrected by following the engine manufacturer recommended procedures or equivalent procedures developed by the Permittee or vendor and the NSCR control system has not been damaged, then the Permittee shall correct the engine exhaust temperature at the inlet to the NSCR control system within 24 hours of inspecting the engine and NSCR control system. (iii) If the engine exhaust temperature at the inlet to the NSCR control system cannot be corrected using the engine manufacturer recommended procedures or equivalent procedures developed by the Permittee or vendor, or the NSCR control system has been damaged, then the affected engine shall cease operating immediately and shall not be returned to routine service until the following has been met: (A) The engine exhaust temperature at the inlet to the NSCR control system is measured and found to be within the acceptable temperature range for that engine; and (B) The NSCR control system has been repaired or replaced, if necessary. (c) The Permittee shall monitor the pressure drop across the NSCR control system on the engine at least once every hour that the engine operates, beginning with the effective date of the MNSR permit, using pressure sensing devices before and after the NSCR control system to obtain a direct reading of the pressure drop (also referred to as the differential pressure). [Note to Permittee: Differential pressure measurements, in general, are used to show the pressure across the filter elements. This information will determine when the elements in the NSCR control system are fouling, blocked or blown out and thus require cleaning or replacement.] (d) If the pressure drop reading exceeds 2 inches of water from the baseline pressure drop reading taken during the most recent performance test, then the following actions shall be taken. The Permittee's completion of any or all of these actions shall not constitute, nor qualify as, an exemption from any other emission limits in the MNSR permit: (i) Within 24 hours of determining a deviation of the pressure drop across the NSCR control system, the Permittee shall investigate. The investigation shall include testing the pressure transducers and assessing the NSCR control system for possible damage that 11 could affect catalytic system effectiveness (including, but not limited to, catalyst housing damage and plugged, fouled, destroyed or poisoned catalyst). (ii) If the pressure drop across the NSCR control system can be corrected by following the NSCR control system manufacturer recommended procedures or equivalent procedures developed by the Permittee or vendor, and the NSCR control system has not been damaged, then the Permittee shall correct the problem within 24 hours of inspecting the NSCR control system. (iii) If the pressure drop across the NSCR control system cannot be corrected using the NSCR control system manufacturer recommended procedures or equivalent procedures developed by the Permittee or vendor, or the NSCR control system is damaged, then the Permittee shall do one of the following: (A) Conduct a performance test within 45 calendar days, as specified in the MNSR permit, to ensure that the emission limits are being met and to re-establish the pressure drop across the NSCR control system. The Permittee shall perform a portable analyzer test for CO and NOX to establish a new temporary pressure drop baseline until a performance test can be scheduled and completed; or (B) Cease operating the affected engine immediately. The engine shall not be returned to routine service until the pressure drop is measured and found to be within the acceptable pressure range for that engine as determined from the most recent performance test. Corrective action may include removal and cleaning of the catalyst or replacement of the catalyst. (e) The Permittee shall monitor NOX and CO emissions from the exhaust of the NSCR control system on the engine at least quarterly to demonstrate compliance with the engines NOX emission limits in the MNSR permit. To meet this requirement, the Permittee shall: (i) Measure NOX and CO emissions at the normal operating load using a portable analyzer and a monitoring protocol approved by the EPA or conduct a performance test as specified in the MNSR permit; (ii) Measure the NOX and CO emissions simultaneously; and (iii) Commence monitoring for NOX and CO emissions within 45 calendar days of the Permittee's submittal of the initial performance test results for NOX emissions, as appropriate, to the EPA. (f) The Permittee shall not perform engine tuning or make any adjustments to engine settings, NSCR control system settings, processes or operational parameters the day of or during measurements. Any such tuning or adjustments may result in a determination by the EPA that the result is invalid. Artificially increasing an engine load to meet monitoring requirements is not considered engine tuning or adjustments. (g) If the results of 2 consecutive quarterly portable analyzer measurements demonstrate compliance with NOX emission limits, the required monitoring frequency may change from quarterly to semi-annually. (h) If the results of any semi-annual portable analyzer measurement demonstrates non-compliance with the NOX emission limits, the required test frequency shall revert back to quarterly. (i) The Permittee shall submit portable analyzer specifications and NOX and CO monitoring protocols to the EPA at the following address for approval at least 45 calendar days prior to the date of initial portable analyzer monitoring: 12 U.S. Environmental Protection Agency, Region 8 Office of Enforcement, Compliance & Environmental Justice Air Toxics and Technical Enforcement Program, 8ENF-AT 1595 Wynkoop Street Denver, Colorado 80202 (j) Portable analyzer specifications and monitoring protocols that have already been approved by the EPA for the emission units approved in the MNSR permit may be used in lieu of new protocols unless the EPA determines it is necessary to require the submittal and approval of a new protocol. The Permittee may submit a new protocol for EPA approval at any time. (k) The Permittee is not required to conduct emissions monitoring and parametric monitoring of exhaust temperature and NSCR control system differential pressure on the engine if it has not operated during the monitoring period. The Permittee shall certify that the engine did not operate during the monitoring period in the annual report specified in Condition I.E.1 of the MNSR permit. Observations: Engine FS02 has not operated since March 2019 and so no performance tests have been conducted since that date. 6. Recordkeeping Requirements (a) Records shall be kept of manufacturer and/or vendor specifications and maintenance requirements developed by the manufacturer, vendor or Permittee for the engine, AFR control system, NSCR control system, temperature-sensing device and pressure-measuring devices. (b) Records shall be kept of all calibration and maintenance conducted for the engine, catalytic control system, temperature-sensing device and pressure-measuring device. (c) Records shall be kept that are sufficient to demonstrate that the fuel for the engine is pipeline quality natural gas in all respects, with the exception of CO2 concentrations. (d) Records shall be kept of all temperature measurements required in the MNSR permit, as well as a description of any corrective actions taken pursuant to the MNSR permit. (e) Records shall be kept of all pressure drop measurements required in the MNSR permit, as well as a description of any corrective actions taken pursuant to the MNSR permit. (f) Records shall be kept of all required testing and monitoring in the MNSR permit. The records shall include the following: (i) The date, place, and time of sampling or measurements; (ii) The dates analyses were performed; (iii) The company or entity that performed the analyses; (iv) The analytical techniques or methods used; (v) The results of such analyses or measurements; and (vi) The operating conditions as existing at the time of sampling or measurement. (g) Records shall be kept of all NSCR control system catalyst replacements or repairs, AFR control 13 system replacements, engine rebuilds and replacements. (h) Records shall be kept of each rebuilt or replacement engine break-in period, pursuant to the requirements of the MNSR permit, where an existing engine that has been rebuilt or replaced resumes operation without the NSCR control system, for a period not to exceed 200 hours. (i) Records shall be kept of each time the engine is shut down due to a deviation in the inlet temperature to the NSCR control system or pressure drop across a NSCR control system. The Permittee shall include in the record the cause of the problem, the corrective action taken and the timeframe for bringing the pressure drop and inlet temperature range into compliance. Observations: The facility provided all requested records. C. Requirements for Records Retention 1. The Permittee shall retain all records required by the MNSR permit for a period of at least 5 years from the date the record was created. 2. Records shall be kept in the vicinity of the facility, such as at the facility, the location that has day-today operational control over the facility or the location that has day-to-day responsibility for compliance of the facility. Observations: Records appear to be kept, as required. D. Requirements for Reporting 1. Annual Emission Reports (a) The Permittee shall submit a written annual report of the actual annual emissions from the 1,061 hp 4SRB engine each year no later than April 1st. The annual report shall cover the period for the previous calendar year. All reports shall be certified to truth and accuracy by the responsible official. (b) The report shall include NOX emissions. (c) The report shall be submitted to: U.S. Environmental Protection Agency, Region 8 Office of Partnerships & Regulatory Assistance Tribal Air Permitting Program, 8P-AR 1595 Wynkoop Street Denver, Colorado 80202 The report may be submitted via electronic mail to R8AirPermitting@epa.gov. 14 2. All other documents required to be submitted under the MNSR permit, with the exception of the Annual Emission Reports, shall be submitted to: U.S. Environmental Protection Agency, Region 8 Office of Enforcement, Compliance & Environmental Justice Air Toxics and Technical Enforcement Program, 8ENF-AT 1595 Wynkoop Street Denver, Colorado 80202 Documents may be submitted via electronic mail to R8AirReportEnforcement@epa.gov. 3. The Permittee shall promptly submit to the EPA a written report of any deviations of emission or operational limits specified in the MNSR permit and a description of any corrective actions or preventative measures taken. A "prompt" deviation report is one that is post marked or submitted via electronic mail to r8airreportenforcement@epa.gov as follows: (a) Within 30 days from the discovery of a deviation that would cause the Permittee to exceed the emission limits or operational limits if left uncorrected for more than 5 days after discovering the deviation; and (b) By April 1st for the discovery of a deviation of recordkeeping or other permit conditions during the preceding calendar year that do not affect the Permittee's ability to meet the emission limits. 4. The Permittee shall submit a written report for any required performance tests to the EPA Regional Office within 60 days after completing the tests. 5. The Permittee shall submit any record or report required by the MNSR permit upon EPA request. Observations: The engine has not operated since March 2019 and the annual emission reports confirm that by showing zero emissions for FS02 between 2019-2023. III. Standards of Performance for Stationary Gas Turbines - 40 CFR Part 60, Subpart GG A. Applicability 40 CFR part 60, subpart GG applies to the following emission units: 1. Solar Saturn T-1001S-205 engine identified as FS01 in Table 2 of this permit; 2. Solar Saturn T-1001S-205 engine identified as FS03 in Table 2 of this permit; 3. Solar Centaur T4700S engine identified as FS05 in Table 2 of this permit. Observations: During the inspection EPA couldn't read the serial numbers on FS01 and FS03. The serial number read on FS05 was as follows: OGH22-C6196 which matches their off permit change conducted in 2022. B. Requirements for Engines FS01, FS03 and FS05 1. The Permittee must meet the requirements for 40 CFR part 60, subpart GG by meeting the following 15 requirements for all applicable emission units: (a) Follow nitrogen oxides fuel emissions standards listed as specified in 60.332(a)(2); (b) Follow sulfur dioxide fuel emission standards as specified in 60.333(a) and 60.333(b). However, the permittee can and has opted to demonstrate compliance with the sulfur dioxide limit specified in 60.333 by continually verifying that the fuel used meets the definition of natural gas to avoid sulfur monitoring. Should the permittee use fuel that does not meet the definition of natural gas, the operator will revert immediately back to applicable requirements listed in 60.333(b). [40 CFR 60.332, 40 CFR 60.333] 2. Emission units FS01, FS03, and FS05 shall be exempt from the NOX emission standard when being fired with an emergency fuel. For the purpose of this requirement, the term "emergency fuel" means "a fuel fired by a gas turbine only during circumstances, such as natural gas curtailment or breakdown of delivery system, that makes it impossible to fire natural gas in the gas turbine." [40 CFR 60.331(r), 40 CFR 60.332(k) Table 7: NSPS GG Turbine Emission Standards for Fidlar Pollutant NOx SO2 Emission Unit(s) FS01 & FS03 FS05 FS01, FS03 & FS05 Emission Standard 150 ppm 167 ppm 0.015 percent by volume at 15% O2 on a dry basisa Regulatory Reference 40 CFR 60.332(a)(2) 40 CFR 60.333(a) a Fuel sulfur monitoring can be avoided by verifying that the fuel used meets the definition of natural gas (20.0 grains or less of total sulfur per 100 standard cubic feet of gas). Observations: Results of performance tests and quarterly monitoring (see Tables 8 and 9, below) indicate compliance with the required NOx emission standards. In lieu of fuel sulfur monitoring, Williams has opted to demonstrate compliance with the SO2 limit by verifying that the fuel used meets the definition of natural gas (20.0 grains or less of total sulfur per 100 standard cubic feet of gas) pursuant to 40 CFR. 60.331(u). Williams provided a document that listed a gas specification of 5 grain of total sulfur per thousand cubic feet specification. This is less than the maximum allowed total sulfur content of 20.0 grains/100 scf (0.068% by weight) pursuant to 40 CFR 60.334(h)(3)(i) and the 8000 ppm (0.8% by weight) sulfur limit at 40 CFR 60.333(b). C. Testing and Initial Compliance Requirements 1. Initial performance testing is required for off permit replacement units for affected turbines. The permittee shall comply with the initial performance test requirements of 40 CFR 60.8(a)-(f) for measuring NOX emissions from replaced units FS01, FS03, and FS05 within 60 days after achieving the maximum production rate at which the turbines will be operated, but not later than 180 days after the initial startup of the turbines. 16 2. The permittee shall comply with the test methods and procedures of 40 CFR 60.335(a), (b) and (c) when conducting the initial performance test for NOX for affected emission units. Observations: The source indicated that a swap of FS05 turbine occurred in 2021. During the inspection, source representatives indicated that the hour meter on the turbines were as follows: FS01 - 36,134 hours; FS03 - 29,921 hours; and FS05 - 8,489 hours. Performance testing was conducted on units FS01, FS03, and FS05 since 2019. See Table 8, below. Table 8: Off Permit Changes and Initial Testing Results for NOx Emission Unit FS01 FS03 FS05 Replacement Date and Notes 6/22/16 Solar Saturn T-1001S205 (same make/model) 3/19/16 - 3/20/16 Solar Saturn T1001S (same make/model) August 2022 Solar Centaur T4700S (same make/model) Serial Startup Number Date Initial Testing Date Avg. NOx NOx Test Emission Results Standard (ppmvd at 15% O2) 21035 6/22/16 8/3/16 63.33 150 20950 3/20/16 6/7/16 42.86 150 OHG22- August C6196 2022 8/31/22 77.1 167 D. Monitoring Requirements 1. The permittee shall comply with the requirements of 40 CFR 60.334(h) for monitoring of sulfur content and nitrogen content of the fuel being burned in the affected emission units. 2. The permittee shall demonstrate that gaseous fuel burned in the affected turbine engines meets the definition of natural gas pursuant to 60.331(u). Observations: The turbines fire suction gas, which is governed by the FERC. As described above, the suction gas contains less than 0.5 grains of total sulfur per 100 standard cubic feet of gas. This is less than the maximum allowed total sulfur content at 40 CFR 60.334(h)(3)(i) of 20.0 grains/100 scf. 3. The permittee shall demonstrate the gas quality characteristics in a current, valid purchase contract, tariff sheet, or transportation contract for the gaseous fuel, specifying that the maximum total sulfur content of the fuel is 20.0 grains/100 scf or less. 4. The permittee shall measure NOX from the affected emission units at least once every quarter to show compliance with the requirements of 40 CFR 60.332(a)(2). To meet this requirement, the permittee shall measure NOX emission from each turbine using a portable analyzer and the monitoring protocol approved by the EPA, or by using a Mobile Test Van (MTV) and the monitoring protocols approved by the EPA. 5. Monitoring shall begin in the first calendar quarter following the EPA notification to the applicant of the approval of the monitoring protocol. 6. If an emission unit is inoperable for 1,500 hours or more in any calendar quarter, the permittee is exempt 17 from conducting NOX monitoring for the emissions unit for that quarter only. [40 CFR 60.331, 60.332, 60.334] Observations: Quarterly monitoring is conducted on Emission Units FS01, FS03, and FS05. Results of monitoring since the last full compliance evaluation are displayed in Table 9, below, and indicate compliance with applicable limits. Table 9: Results of Quarterly NOx Monitoring for Turbines FS01, FS03, and FS05 Emission Unit FS01 FS03 Test Date(s) 3/13/2019 5/8/2019 7/23/2019 12/4/2019 1/15/2020 5/14/2020 7/14/2020 10/27/2020 3/30/2021 5/26/2021 7/14/2021 10/14/2021 1/25/2022 5/24/2022 9/20/2022 11/15/2022 3/7/2023 6/14/2023 8/15/2023 11/21/2023 3/5/2024 5/1/2024 3/13/2019 5/8/2019 7/23/2019 12/4/2019 1/15/2020 5/14/2020 7/14/2020 10/27/2020 3/30/2021 5/26/2021 7/14/2021 10/14/2021 1/25/2022 5/24/2022 9/20/2022 11/15/2022 3/7/2023 6/14/2023 8/15/2023 11/21/2023 3/5/2024 5/1/2024 Avg. NOx (ppmvd at 15% O2) 53.98 54.08 47.53 62.02 57.20 51.87 53.64 57.05 62.20 53.22 47.62 58.96 66.18 57.95 53.51 77.81 80.37 61.52 52.93 83.49 72.27 53.12 59.87 55.31 52.17 61.75 61.43 50.37 58.83 50.97 59.99 56.82 56.00 52.37 65.25 59.24 53.38 49.94 68.57 60.23 58.99 82.65 61.04 79.87 18 NOx Permit Limits (ppm) 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 3/13/2019 41.26 150 5/8/2019 30.23 150 7/23/2019 18.95 150 12/4/2019 34.36 150 1/15/2020 38.01 150 5/14/2020 19.98 150 7/14/2020 16.07 150 10/27/2020 29.50 150 3/30/2021 41.89 150 5/26/2021 21.93 150 FS05 7/14/2021 14.70 150 10/14/2021 33.39 150 1/25/2022 32.58 150 5/24/2022 24.57 150 9/20/2022 23.21 150 11/15/2022 41.76 150 3/7/2023 28.19 150 6/14/2023 28.48 150 8/15/2023 25.12 150 11/21/2023 38.85 150 3/5/2024 37.82 150 5/1/2024 33.91 150 E. Notifications, Reports and Records 1. The permittee must maintain records as specified in 60.7 and 71.6. 2. The permittee must follow the recordkeeping requirements when firing an emergency fuel as specified in 60.331. 3. The permittee must monitor operations as specified in 60.334. 4. The permittee must submit reports as specified in 60.7, 60.8 and 71.6. [40 CFR 60.331, 60.334] Observations: Records appear to be maintained as required According to Williams, no emergency fuels have been fired at the Fidlar Compressor Station. The turbines fire suction gas, which is governed by the FERC. As described above, the suction gas contains less than 0.5 grains of total sulfur per 100 standard cubic feet of gas. This is less than the maximum allowed total sulfur content at 40 CFR 60.334(h)(3)(i) of 20.0 grains/100 scf. Reports of all initial performance tests have been submitted to EPA. IV. Standards of Performance for Stationary Spark Ignition Combustion Engines - 40 CFR Part 60, Subpart JJJJ A. Applicability CFR part 60, subpart JJJJ applies to the following engine: 19 1. Cummins GTA28 CC engine identified as FS07 in Table 2 of this permit. [40 CFR 60.4230] Observations: The engine tag showing that the serial number of the engine is 25352466 and that the engine was manufactured on 10/20/10 was observed when on-site. B. Emission Standards for Owners and Operators The Permittee, as an owner or operator of a 2010 model year non-emergency SI ICE must comply with the emission standards set in 40 CFR part 60, subpart JJJJ Table 1. [40 CFR 60.4233(e)] Table 10: NSPS Subpart JJJJ Emission Standards for Unit FS07 Pollutant NOx CO VOC Limit 1.0 g/hp-hr or 82 ppmvd at 15% O2 2.0 g/hp-hr or 270 ppmvd at 15% O2 0.7 g/hp-hr or 60 ppmvd at 15% O2 Observations: Results of performance tests on Unit FS07 indicate compliance with the emission standards for NOx, CO, and VOC. (See Table 11, below.) C. Compliance Requirements for Owners and Operators The Permittee, as the owner or operator of the SI ICE, must: 1. Comply with the emission standards; 2. Operate and maintain the stationary SI ICE and control device according to the manufacturer's emissionrelated written instructions; 3. Only change those settings that are permitted by the manufacturer; 4. Meet the requirements of 40 CFR parts 90 or 1054, as they apply; and 5. Install a non-resettable hour meter as required in 60.4237(a). [40 CFR 60.4243, 60.4237] Observations: Engine FS07 is a non-certified engine. Although the most recent performance test results (from June 5, 2023) indicate that FS07 meets the standards applicable to non-emergency engines in Table 1 of 40 CFR Part 60, Subpart JJJJ (82 ppmvd NOx, 270 ppmvd CO, 60 ppmvd VOC), a non-resettable meter was factory-installed on FS07 at the time of manufacture in October 2010. At the time of the on-site inspection, EPA recorded a meter reading on Engine FS07 of 675.7 hours. D. Testing Requirements for Owners and Operators 20 1. Follow procedures outlined in 60.4244(a)-(f) for conducting performance tests; 2. Reference method performance tests shall be conducted, according to 40 CFR 60.4244, upon startup and for all replacement engines for FS07 that are non-certified to measure NOX, CO and VOC emissions to demonstrate compliance with the emission limits. In addition, the permittee must conduct subsequent performance tests on non-certified engines every 8,760 hours of operation or 3 years, whichever comes first as specified in 60.4243(b)(2)(ii); and 3. The performance tests for NOX, CO and VOC shall be conducted in accordance with the test methods specified in Table 2 of 40 CFR 60, subpart JJJJ. Observations: FS07 was last performance tested on 6/5/23. [40 CFR 60.4244, 60.4243] Table 11: Results of NSPS Subpart JJJJ Performance Testing for Unit FS07 (NOx, CO, VOC) Unit S/N Test Avg. NOx NOx Limit Avg. CO CO Limit Date(s) (ppmvd at 15% O2) 25352466 5/10/23 47.23 82 20.36 270 25352466 5/15/20 28 82 38 270 * VOC levels reported as NMHC through the use of a Methane Cutter Avg. VOC* 3.3 3 VOC Limit 60 60 E. Recordkeeping Requirements The Permittee, as the owner or operator of the SI ICE, must: 3. Comply with this subpart and all documentation supporting any notification; 4. Maintain records describing any maintenance conducted on the engine; 5. Maintain records of whether FS07 is a certified engine or non-certified engine and follow applicable certifications, documentation, and emission standards; and 6. Keep and maintain records of the hours of operation if FS07 does not meet the standards applicable to non-emergency through the non-resettable hour meter. [40 CFR 60.4245(a)-(b)] Observations: Records of hours of operation have been maintained as required and provided as part of this inspection. The source provided EPA with a log of operating hours for FS07. During the inspection, EPA recorded an engine operating time of 672 hours on the non-resettable hour meter. The source provided records showing it conducts annual maintenance on the engine. The source shared the summary of the annual maintenance done which included looking at the belts, hoses and spark plugs. Additionally, the source indicated that if typically do an oil analysis, rather than change the oil, if the engine was only run for 50-60 hours in a year. Records appear to be maintained as required. F. Notifications and Reporting Requirements 1. The permittee must, for engines that have not been certified by an engine manufacturer to meet the 21 emissions standards in 60.4231, submit an initial notification as required in 60.7(a)(1). The notification must include all information as specified in 60.4245(c). 2. The permittee must submit a copy of each performance test as required by 60.4244 and this section within 60 days after the test has been completed. [40 CFR 60.4244, 60.4245] Observations: There was no initial notification nor performance test reporting obligations since EPA's last inspection report. V. National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines - 40 CFR Part 63, Subpart ZZZZ A. Applicability 40 CFR part 63, subpart ZZZZ applies to the following emission unit(s): 1. Cummins GTA28 CC engine identified as FS07 in Table 2 of this permit. [40 CFR 63.6585] This engine is an affected source that meets a criteria in 63.6590(c)(1)-(7) and must meet the requirements of 40 CFR part 63, subpart ZZZZ by meeting the requirements of 40 CFR part 60, subpart JJJJ, for spark ignition engines. No further requirements apply for this engine under 40 CFR part 63. [40 CFR 63.6590(c)] Observations: Since Emission Unit FS07 is a new or reconstructed stationary RICE located at an area source of HAPs, it meets the requirements of 40 CFR 63.6590(c)(1). Therefore, this unit meets the requirements of MACT Subpart ZZZZ by meeting the requirements of NSPS Subpart JJJJ. 22 VI. Facility-Wide Requirements [40 CFR 71.6(a)(1)] Conditions in this section of the permit apply to all emissions units located at the facility, including any units not specifically listed in Table 2 of the Facility Emission Points section of this permit. A. General Recordkeeping Requirements [40 CFR 71.6(a)(3)(ii)] The permittee shall comply with the following generally applicable recordkeeping requirements: 1. If the Permittee determines that his or her stationary source that emits (or has the potential to emit, without considering controls) one or more hazardous air pollutants (HAPs) is not subject to a relevant standard or other requirement established under 40 CFR Part 63, the Permittee shall keep a record of the applicability determination on site at the source for a period of 5 years after the determination, or until the source changes its operations to become an affected source, whichever comes first. The record of the applicability determination shall include an analysis (or other information) that demonstrates why the Permittee believes the source is unaffected (e.g., because the source is an area source). [40 CFR 63.10(b)(3)] 2. Records shall be kept of off permit changes, as required by the Off Permit Changes section of this permit. Observations: Williams indicated that there had been one off-permit changes. The off-permit change was for a core exchange for unit FS05. The stated that: "The proposed turbine core exchange project fixed capital cost of the new components is less than 50 percent of the cost that would be required to construct a comparable entirely new facility and therefore, the proposed turbine core exchange project does not trigger reconstruction per NSPS Subpart A". B. General Reporting Requirements [40 CFR 71.6(a)(3)(iii)] 1. The Permittee shall submit to the EPA all reports of any required monitoring under this permit semiannually. The first report shall cover the period from the effective date of this permit through December 31, 2018 Thereafter, the report shall be submitted semi-annually, by April 1st and October 1st of each year. The report due on April 1st shall cover the 6 month period ending on the last day of December before the report is due. The report due on October 1st shall cover the 6-month period ending on the last day of June before the report is due. All instances of deviations from permit requirements shall be clearly identified in such reports. All required reports shall be certified by a responsible official consistent with the Submissions section of this permit. To help Part 71 Permittees meet reporting responsibilities, the EPA has developed a form "SIXMON" for 6 month monitoring reports. The form may be found on the EPA's website at: https://www.epa.gov/title-v-operating-permits/epa-issued-operating-permits] 2. "Deviation" means any situation in which an emissions unit fails to meet a permit term or condition. A deviation is not always a violation. A deviation can be determined by observation or through review of data obtained from any testing, monitoring, or recordkeeping established in accordance with 71.6(a)(3)(i) and (a)(3)(ii). For a situation lasting more than 24 hours which constitutes a deviation, each 24 hour period is considered a separate deviation. Included in the meaning of deviation are any of the following: 23 (a) A situation where emissions exceed an emission limitation or standard; (b) A situation where process or emissions control device parameter values indicate that an emission limitation or standard has not been met; or (c) A situation in which observations or data collected demonstrate noncompliance with an emission limitation or standard or any work practice or operating condition required by the permit. 3. The Permittee shall promptly report to the EPA deviations from permit requirements, including those attributable to upset conditions as defined in this permit, the probable cause of such deviations, and any corrective actions or preventive measures taken. "Prompt" is defined as follows: (a) Any definition of "prompt" or a specific time frame for reporting deviations provided in an underlying applicable requirement as identified in this permit. (b) Where the underlying applicable requirement fails to address the time frame for reporting deviations, reports of deviations will be submitted based on the following schedule: (i) For emissions of a HAP or a toxic air pollutant (as identified in the applicable regulation) that continue for more than an hour in excess of permit requirements, the report must be made within 24 hours of the occurrence. (ii) For emissions of any regulated air pollutant, excluding a HAP or a toxic air pollutant that continues for more than two (2) hours in excess of permit requirements, the report must be made within 48 hours. (iii) For all other deviations from permit requirements, the report shall be submitted with the semi-annual monitoring report. (c) If any of the conditions in (i) or (ii) of paragraph (b) above are met, the Permittee must notify the EPA by telephone (1-800-227-6312), facsimile (303-312-6409), or by email to r8airreportenforcement@epa.gov based on the timetables listed above. [Notification must specify that this notification is a deviation report for a Part 71 permit]. A written notice, certified consistent with the Submissions section of this permit must be submitted within ten working days of the occurrence. All deviations reported under this section must also be identified in the 6-month report required under Condition 1. in this section of this permit. [Explanatory note: To help Part 71 Permittees meet reporting responsibilities, the EPA has developed a form "PDR" for prompt deviation reporting. The form may be found on the EPA's website at: https://www.epa.gov/title-v-operating-permits/epa-issued-operating-permits] Observations: Since the last full compliance evaluation was conducted, the source has submitted all required Semi-Annual Reports by the applicable deadlines. (See Table 12, below.) Table 12: Facility-Wide Semi-Annual Reports Reporting Period 1st half 2019 2nd half 2019 1st half 2020 Report Date 9/30/19 3/19/20 9/24/20 24 Notes No deviations reported. No deviations reported. No deviations reported. 2nd half 2020 1st half 2021 2nd half 2021 1st half 2022 2nd half 2022 1st half 2023 2nd half 2023 1st half 2024 1/21/21 7/1/21 1/19/22 7/12/22 1/6/23 7/21/23 1/9/24 7/25/24 No deviations reported. No deviations reported No deviations reported. No deviations reported. No deviations reported. No deviations reported. No deviations reported. No deviations reported. 25 VII. General Provisions A. Annual Fee Payment [40 CFR 71.9] The permittee shall pay an annual permit fee each year no later than April 1st. The fee shall cover the previous calendar year. The fee payment shall be in United States currency and shall be paid by money order, bank draft, certified check, corporate check, or electronic funds transfer payable to the order of the U.S. Environmental Protection Agency. The permittee shall submit annually an updated fee calculation worksheet form and confirmation of actual fee paid by the same deadline as required for fee payment. Fee calculation worksheets shall be certified as to truth, accuracy, and completeness by a responsible official. The permittee shall retain fee calculation worksheets and other emissions-related data used to determine fee payment for 5 years following submittal of fee payment. Observations: Annual fees received for the Fidlar Compressor Station are displayed in Table 5, below. Table 4: Annual Fees Received for Fidlar Reporting Year 2019 2020 2021 2022 2023 Fee Paid 1,399.06 1,291.44 730.99 1,029.52 1,021.60 B. Annual Emissions Inventory [40 CFR 71.9(h)(1)(2)] The permittee shall submit an annual emissions report of its actual emissions for both criteria pollutants and regulated HAPs for this source for the preceding calendar year for fee assessment purposes. The annual emissions report shall be certified by a responsible official and shall be submitted each year to EPA by April 1st. Observations: Annual emissions reports received for the Fidlar Compressor Station are displayed in Table 6, below. Reports were submitted on or before April 1st of the relevant calendar year. Pollutant NOx VOC SO2 PM10 Total HAPs Table 5: Annual Emissions Reported for Fidlar 2019 23.3 0.9 0.3 0.9 0.1 2020 21.9 1.0 0.2 1.2 0.1 Actual Emissions (tpy) 2021 10.7 0.8 0.1 0.8 0.1 2022 15.2 0.8 0.1 0.5 0.1 2023 14.6 0.7 0.1 0.5 0.1 C. Compliance Requirements [40 CFR 71.6(a)(6), Section 113(a) and 113(e)(1) of the CAA, and 40 CFR 51.212, 52.12, 52.33, 60.11(g), 61.12] 3. Compliance Certifications [40 CFR 71.6(c)(5)] (a) The Permittee shall submit to the EPA a certification of compliance with permit terms and conditions, including emission limitations, standards, or work practices annually by April 1st, and shall cover the same 12-month period as the two consecutive semi-annual monitoring reports. 26 [Explanatory note: To help Part 71 Permittees meet reporting responsibilities, the EPA has developed a reporting form for annual compliance certifications. The form may be found on the EPA's website at: https://www.epa.gov/title-v-operating-permits/epa-issued-operating-permits ] (b) The compliance certification shall be certified as to truth, accuracy, and completeness by a responsible official consistent with 40 CFR 71.5(d). (c) The certification shall include the following: (i) Identification of each permit term or condition that is the basis of the certification; (ii) The identification of the method(s) or other means used for determining the compliance status of each term and condition during the certification period, and whether such methods or other means provide continuous or intermittent data. Such methods and other means shall include, at a minimum, the methods and means required in this permit. If necessary, the Permittee also shall identify any other material information that must be included in the certification to comply with Section 113(c)(2) of the CAA, which prohibits knowingly making a false certification or omitting material information; (iii) The status of compliance with each term and condition of the permit for the period covered by the certification based on the method or means designated in (ii) above. The certification shall identify each deviation and take it into account in the compliance certification; (iv) Such other facts as the EPA may require to determine the compliance status of the source; and (v) Whether compliance with each permit term was continuous or intermittent. Observations: TVACCs were submitted as shown in Table 75, below. The facility reported continuous compliance with all permit conditions. Table 65: Facility-Wide Annual Compliance Certifications (TVACCs) Reporting Period 2019 2020 2021 2022 2023 Report Date 3/30/20 1/27/21 1/20/22 1/12/23 1/9/24 Notes Facility reported continuous compliance with all permit conditions. Reported that unit FS02 did not operate during calendar year. Facility reported continuous compliance with all permit conditions. Reported that unit FS02 did not operate during calendar year. Facility reported continuous compliance with all permit conditions. Reported that unit FS02 did not operate during calendar year. Facility reported continuous compliance with all permit conditions. Reported that unit FS02 did not operate during calendar year. Facility reported continuous compliance with all permit conditions. Reported that nit FS02 did not operate during calendar year. O. Off Permit Changes [40 CFR 71.6(a)(12) and 40 CFR 71.6(a)(3)(ii)] The permittee is allowed to make certain changes without a permit revision, provided that the following 27 requirements are met, and that all records required by this section are kept at the Operations Center for a period of five years. Observations: Williams noted there had been one off-permit change. See above. 28 APPENDIX A: Site Overview Fuel Gas Treater FS07 FS05 FS02 FS01 FS03 QPC Tank & Truck Loadout Figure 1: Fidlar Compressor Station Aerial View Appendix B: Photo and Video Log File Name MOV_3561 Location ESD blowdown vent lines MOV_3562 Produced liquids tanks Description Emissions from the suction and discharge open ended lines Emissions from uncontrolled tank