Document 0q2oG4DrOR0J3oRNDVrDbqrNx

Deseret Generation - Bonanza Power Plant Full Compliance Evaluation (FCE) Off-Site Clean Air Act (CAA) Inspection Inspection Date: March 22, 2023 Inspection Report Date: April 10, 2023 EPA Representatives: Michael Stovern, Colin Lecortz, Christine Tokarz Tribal Representatives: Lonnie Favel, Monaco Weidner, Mariko Blackbird, Alverna Nelson Company Representatives: Tyler Esplin Inspection Report Prepared By: Inspection Report Reviewed By: Last CAA Inspection: Michael Stovern Scott Patefield SCOTT PATEFIELD September 8, 2021 Digitally signed by SCOTT PATEFIELD Date: 2023.04.13 18:12:57 -06'00' Applicable Rules: 40 C.F.R. Part 60, Subpart Dc (NSPS Dc) 40 C.F.R. Part 60, Subpart IIII (NSPS IIII) 40 C.F.R. Part 60, Subpart Y (NSPS Y) 40 C.F.R. Part 63, Subpart ZZZZ (MACT ZZZZ) 40 C.F.R. Part 63, Subpart UUUUU (MACT UUUUU) CAA Permit History: PSD-OU-0001-2001:00 (Issued PSD permit) V-U0-000004-00.00 (Issued Title V permit) MNSR-U0-000004-2015.004 (Issued Minor NSR permit) General Source Information Parent Company name: Facility Name: Facility Location: EPA Region: County, State: Reservation: Tribe: Responsible Official: NAICS Code: ICIS-AIR ID Number: Deseret Power Electric Cooperative Bonanza Power Plant Latitude 40.086536, Longitude -109.286408 8 Uintah County, Utah Uintah Ouray Reservation Ute Tribe Eric Olsen (Plant Manager) 22111 080000004904700001 1 Overall Inspection Findings NSPS Dc violations/concerns 1. The EPA did not identify any areas of concern. NSPS IIII violations/concerns 1. The EPA did not identify any areas of concern. NSPS Y violations/concerns 1. The EPA did not identify any areas of concern. MACT ZZZZ violations/concerns 1. The EPA did not identify any areas of concern. MACT UUUUU violations/concerns 1. The EPA did not identify any areas of concern. Previous Compliance Status No compliance issues were identified during the previous onsite inspection or the following records review. Current Compliance Status No areas of concern were identified during the onsite inspection or the following records review. Emission Sources Table 1 Emission units Emission Description Unit ID 1-1 BOILER: Foster-Wheeler steam generator; heat input capacity of about 4,578 MMBtu/hr; dry bottom wall-fired on bituminous coal; uses diesel or natural gas during startup, shutdown, upsets and flame stabilization. Constructed in 1984. Exhausts through main plant stack. Control equipment low-NOx burners; baghouse (10,800 bags); wet limestone FGD scrubber (3 modules) Emission Unit ID 1-2 1-3 1-4 1-5 DC-1 Table 2 Insignificant Activities/Emitting Units Description AUXILIARY BOILER* (168 MMBtu/hr, pre-1984, fired on fuel oil or natural gas) EMERGENCY DIESEL GENERATOR (750 KW, 1,220 HP, fired on fuel oil, started up in 2013) EMERGENCY DIESEL FIRE PUMP (3.71 MMBtu/hr, 525 HP, fired on fuel oil, installed in Aug. 2014) CONSTRUCTION HEATERS* (12.81 MMBtu/hr each, fired on propane) COAL TERMINAL BUILDING Title V Applicable Permit Condition None II.A.4, II.A.5 II.A.4, II.A.5 None II.B.1.(a), II.B.2 2 DC-2 DC-3 DC-4 DC-5 LDC-1 LDC-2 None None None None None None None None (coal distribution facility connecting conveyors 1, 2 & 8; equipped with fabric filter dust collector) COAL SILO (silo for storing and handling coal; equipped with fabric filter dust collector) COAL SILO RECLAIM/TRANSFER (coal handling area; equipped with fabric filter dust collector) COAL CRUSHING BUILDING (receives coal from silo and reclaim; equipped with fabric filter dust collector) COAL BUNKERS (coal storage bunkers that feed pulverizers; equipped with fabric filter dust collector) LIMESTONE RECEIVING HOPPER (hopper to transfer limestone to the limestone conveyor; equipped with fabric filter dust collector) LIMESTONE STORAGE BUNKERS (limestone storage bunkers for feeding scrubber; equipped with fabric filter dust collector) FLY ASH SILO* (stores fly ash prior to loading on landfill conveyor; equipped with fabric filter dust collector) COAL TRACK HOPPER FOR BOTTOM-DUMP COAL (below-track coal car unloading hopper; equipped with water sprays) COAL PILE (coal storage pile, maximum 22 acres, consisting of a long-term storage area and active/reclaim area (maximum 11 acres); surfactant sealant used as needed for dust control at long-term storage area) COAL CONVEYORS 1, 2 & 8 (all covered; conveyors 1 and 8 equipped with water sprays) COAL CONVEYORS 3a, 3b, 4a & 4b (covered; coal transfer from storage to plant) LIMESTONE LONG-TERM STORAGE PILE (surfactant sealant used as needed for dust control) LIMESTONE CONVEYOR (covered; transfers limestone from storage area to scrubber) ASH/SLUDGE LANDFILL CONVEYOR* (covered conveyor from sludge building to landfill; II.B.1.(a), II.B.2 II.B.1.(a), II.B.2 II.B.1.(a), II.B.2 II.B.1.(a), II.B.2 II.B.1.(a) II.B.1.(a) None II.B.1.(b), II.B.2 II.B.1.(c), II.B.1.(f) II.B.l.(a), II.B.2 II.B.l.(a), II.B.2 II.B.1.(d), II.B.1.(f) II.B.l.(a) None 3 includes "grasshopper" conveyor system, consisting of four uncovered conveyors, at end of regular sludge conveyor system) None ASH/SLUDGE LANDFILL DISCHARGE AREA (active discharge area for ash and sludge; includes water sprays as necessary for dust control) None ASH/SLUDGE LANDFILL* (stabilized and inactive) None ACCESS/HAUL ROADS (partially paved road from boiler building to landfill and road from SFC discharge to bottom ash landfill; water sprays or chemical treatment as necessary for dust control) None PERIMETER ROAD (unpaved road around the perimeter fence; water sprays or chemical treatment as necessary for dust control) Tank #1, #2 DIESEL FUEL OIL STORAGE TANK #1* west (288,000 gallon capacity) Tank #1, #2 DIESEL FUEL OIL STORAGE TANK #2* east (288,000 gallon capacity) None ABOVE-GROUND GASOLINE STORAGE TANK* (10,000 gallon capacity) None ABOVE-GROUND DIESEL STORAGE TANK* (20,000 gallon capacity) None VEHICLE REFUELING EQUIPMENT FOR DIESEL AND GASOLINE* None TRUCK-MOUNTED VACUUM SYSTEM ("GUZZLER")* (mobile truck mounted vacuum equipped with particulate filter to clean up spilled material such as ash) None MISCELLANEOUS ABRASIVE BLASTING* (abrasive blasting of parts and equipment inside the boiler baghouse) None WATER TREATMENT AND ASSOCIATED CHEMICAL STORAGE* (areas for equipment and chemicals to treat water used on site) None BOTTOM ASH LANDFILL* *No applicable requirements. II.B.l.(e) None II.B.1.(g), II.B.1.(h) II.B.1.(g), II.B.1.(h) None None None None None None None None None 4 General Inspection Observations and Commentary On March 22, 2019, the EPA inspectors and Tribal representatives met with Deseret at the Bonanza Plant site at 2:00 PM. Representing Deseret was Tyler Esplin (Environmental compliance supervisor). We met with various other Deseret representatives during the inspection including and Eric Olsen (Plant Manager). Upon entrance to the facility initial introductions were made between the plant personnel, EPA inspectors and tribal representatives. The inspectors informed Deseret that this was a routine Full Compliance Evaluation (FCE) inspection given it had been two years since its previous FCE in 2021. The inspectors presented their inspection credentials and explained that they would be evaluating Clean Air Act compliance with all applicable regulations and permits including: PSD permit (2001), Title V permit (2014) and Minor NSR permit (2016). During the opening meeting the inspectors asked a series of questions regarding facility operations before conducting a facility walkthrough. The inspectors first ask if any equipment had been added or removed from the facility since the previous inspection in 2021 and the company representative noted that 15 MW of solar generation had been added to the facility. No equipment had been removed. The inspectors proceeded to spot check the daily CEMS and COMS calibration records for 1/3/2023, 11/14/2022, 4/9/2022 and 11/23/2021. The initial CEMS calibration failed for 1/3/2023 due to a calibration gas value issue but upon correcting the issue the follow-up calibration 20 minutes later the daily calibration passed. All other daily calibrations were passed on first attempt. The inspectors requested the following records in digital format: x Copy of the COMS data from 10/1/2021 through 3/22/2023 x Dust logs 10/1/2021 through 3/22/2023 x Fugitive dust plan x 2022 operator training records x 2022 environmental health and safety training records x 12/29/2022 daily CEMS calibration log showing COMS and CEMS operation during shutdown/startup The inspectors proceeded to request the hours of operation of the emergency generator and and fire pump engine: x Emergency generator o 2021 = 2.4 hours (readiness testing) o 2022 = 2.7 hours (readiness testing) x Fire pump engine o 2021 = 26.4 hours (readiness testing) o 2022 = 26.0 hours (readiness testing) 5 The inspectors proceeded to ask about the facility-wide annual SO2 emissions for 2021 and 2022 respectively: x 2021 = 849.2 tons x 2022 = 959.3 tons Finally, the inspectors inquired as to whether Deseret considered routing natural gas to the site to convert the main boiler from coal. The company representative said Deseret has been considering installing an additional 50 MW of power generation through stationary source engines that would be run on natural gas, if implemented. Walk Through Inspection Observations The facility walkthrough began at 3:15 pm. The following is a list and description of the facilities inspected: 1. Turbine Deck All inspection personnel began the tour in the turbine house. Mr. Esplin proceeded to describe the three stages used to power the turbine including the high pressure, intermediate pressure and low pressure steam operations. 2. Main Boiler Control Room We left the Turbine room and entered the main control room. Several people were in the control room monitoring plant operations. Mr. Esplin and plant operators proceeded to explain the purposes of the different monitors and control panels. The plant's operating conditions at the time of the inspection were: x SO2 lb/MMBTU o Duct A = 0.670 o Duct B = 0.651 o Stack = 0.027 o % removal = 96% x NOx lb/MMBTU o Stack = 0.264 x Opacity o Stack = 1.2% x 30 day rolling averages o SO2 lb/MMBTU = 0.0485 o SO2 % reduction = 94.17 o NOx lb/MMBTU = 0.27 x Generation Load o Current = 460 MW o Capacity = 458 MW 3. Boiler House 6 Upon entering the boiler house's 4th floor the inspectors observed the pulverizes and their feed rate displays. There are 5 pulverizers and all were operational at the time of the inspection. The total coal throughput of the pulverizers was 236.3 tons per hour, distributed as shown below. Coal Feed Rate (tons/hr) 52.77 52.587 36.88 41.395 52.699 236.331 Pulverizer Pulverizer 1 Pulverizer 2 Pulverizer 3 Pulverizer 4 Pulverizer 5 Total The facility representative then showed the inspectors the plant view from the roof of the boiler house. From the roof, EPA inspectors and tribal representatives viewed the evaporation ponds, north landfill, south landfill, roadways, main stack CEMS locations, and other operations. No areas with fugitive emissions were noted. The facility representative also explained the evaporation ponds are used because the facility has zero wastewater discharge. 4. Baghouse & Scrubber Building The facility representative then took the inspectors around the exterior of the baghouse prior to entering the Scrubber building. The baghouse contains 10,000 bags and has 24 total zones. Once in the scrubber building the three, half million-gallon, slurry tanks and limestone grinding mill were identified and the facility representative stated that 2 of the 3 tanks are active at any given time. The inspectors were also taken to view the slurry thickener which is the last stage of processing prior to disposal in the on-site landfill. 5. Coal and Limestone Piles and Handling While exiting the scrubber building, the inspectors viewed the loading point for fly ash recovered from the baghouse. The facility representative explained the fly ash loading operations are contracted to Salt River Materials for hauling to final consumers. Both the limestone and coal conveyors were observed. The facility walkthrough concluded at 4:55 pm. Following the site walkthrough, the inspectors returned to the plant main meeting building, and discussed the following records with Deseret representatives: x Copy of the COMS data from 10/1/2021 through 3/22/2023 x Dust logs 10/1/2021 through 3/22/2023 x Fugitive dust plan x 2022 operator training records 7 x 2022 environmental health and safety training records x 12/29/2022 daily CEMS calibration log showing COMS and CEMS operation during shutdown/startup Closing Meeting: The EPA inspectors closed the inspection by informing facility personnel that no significant issues had been identified during the on-site portion of the inspection, and that an inspection report would be sent to the facility within roughly 60 days of the inspection. 8 PSD Permit Requirements (PSD-OU-0001-2001:00) 12. The Permittee must comply with the requirements at 40 CFR 60.8, Performance tests. A. 1. Within 60 days after achieving the maximum production rate at which the affected facility will be operated, but no later than 180 days after initial startup of such facility and at such other times as may be required by EPA under section 114 of the Clean Air Act, the Permittee must conduct a performance test(s) and furnish EPA a written report of the results of such performance test(s). 2. The Permittee may satisfy Condition 12. A.1. by conducting a performance test(s) no later than 90 days after receipt of this Permit. The Permittee must conduct a performance test for the regulated pollutants in Conditions 16, 17, and 18 of this Permit, under 40 CFR 60.8(a). A written quality assured report must be provided to the EPA on the results of this Test within 30 days after completion of the Performance Test. 3. In order to demonstrate compliance with Conditions 12. A. 1 and 12. A. 2., the Permittee may submit as evidence the most recent quality assured continuous emission monitoring data for NOx and SO2 , and the most recent quality assured stack test data for particulates. Otherwise, the Permittee must comply with all the requirements in Conditions 12. A.1. or 12. A. 2. The facility has recently performed and passed RATAs (flow monitor, SO2, NOx, and CO2 monitors in October 2021 and September 2022) and particulate emissions test (October 2021 and September 2022) and have met these requirements, in compliance. B. Performance tests must be performed as specified in this Permit and data reduced in accordance with the test methods and procedures for each method, as required at 40 CFR 60.8(b). C. Performance tests must be conducted under representative conditions specified by the EPA as required at 40 CFR 60.8(c). Periods of start up, shut down, and malfunction are not representative periods. D. The EPA must be notified of 30 days prior to the performance test and be afforded an opportunity to have an observer present during the test, as required at 40 CFR 60.8(d). E. The Permittee's performance testing facilities must comply with requirements at 40 CFR 60.8(e)(1-4). 9 F. Performance tests must consist of three separate runs using the applicable method, and the arithmetic mean from the three runs must be reported as required at 40 CFR 60.8(f), unless the EPA accepts the results from two runs. The facility has recently performed and passed RATAs (flow monitor, SO2, NOx, and CO2 monitors in October 2021 and September 2022) and particulate emissions test (October 2021 and September 2022) and have met these requirements, in compliance. 13. The Permittee must comply with requirements at 40 CFR 60.11, Compliance with standards and maintenance requirements. A. Compliance with standards in this Permit, other than opacity standards, must be determined in accordance with requirements of 40 CFR 60.8, unless otherwise allowed for in this Permit. B. Compliance with opacity standards must be determined by conducting observations in accordance with Reference Method 9 in Appendix A, 40 CFR Part 60, unless an alternative EPA approved method is used as required at 40 CFR 60.11(b). C. The opacity standard in this Permit applies at all times except during periods of startup, shutdown, malfunction, or other provided in this Permit and as required at 40 CFR 60.11(c). D. The Permittee must maintain and operate the affected facility, including associated air pollution control equipment, to the extent practicable, in a manner consistent with good air pollution control practice for minimizing emissions at all times, including periods of startup, shutdown, and malfunction, in accordance with 40 CFR 60.11(d). E. The Permittee must comply with 40 CFR 60.11(e)(1-6) regarding opacity measurements, including demonstrating initial compliance, using continuous opacity monitors, and reporting and submitting data to EPA, and as allowed for in this Permit. F. Special provisions set forth under any applicable Permit condition or applicable CFR subpart shall supersede any conflicting provisions in conditions 13. A-E, as allowed at 40 CFR 60.11(f). G. For the purpose of determining compliance with this Permit, the EPA may use credible evidence or information in accordance with 40 CFR 60.11(g). EPA previously found that Deseret failed to comply with the general duty to 10 minimize particulate emissions to the extent practicable during startup and shutdown periods, as required by 40 C.F.R. Part 60, Subpart A, 60.11(d). On June 28, 2013, a final order was issued for an administrative settlement regarding startup and shutdown emissions and violations of 40 CFR Part 60. A condition of the consent decree requires Deseret to route all emissions through the baghouse during startup and shutdown periods. Deseret is currently in compliance with these requirements. 14. The Permittee must comply with requirements at 40 CFR 60.12, Circumvention. No problems were noted with this requirement. 15. The Permittee must comply with requirements at 40 CFR 60.13, Monitoring requirements. A. The Permittee must meet requirements at 40 CFR 60.13(a) for performance specifications for continuous monitoring systems under 40 CFR part 60, Appendix B and, as appropriate, Appendix F. B. The Permittee must comply with requirements at 40 CFR 60.13(b) pertaining to installation and operation of continuous monitoring systems and devices. C. The Permittee must comply with requirements at 40 CFR 60.13(c)(1-2) pertaining to submitting continuous monitoring system (COMS) data for compliance with the opacity standard in this Permit. The Permittee must conduct a performance evaluation of the COMS or continuous emission monitoring system (CEMS) during any performance test under 40 CFR 60.8 or in accordance with 40 CFR Part 60, Appendix B. As required by EPA under section 114 of the Clean Air Act as amended, the Permittee must conduct COMS or CEMS performance tests. D. The Permittee must check the span and zero drift of continuous emission monitoring systems as required at 40 CFR 60.12(d)(1-2). E. Except for system breakdowns, repairs, calibration checks, and zero and span adjustments under Condition 14. D, all continuous monitoring systems must be in continuous operation and meet minimum frequency of operation requirements as required at 40 CFR 60.13(e)(1-2). F. The Permittee must meet requirements at 40 CFR 60.13(f) to comply with requirements that all continuous monitoring systems or monitoring devices shall be installed such that representative measurements of emissions or process parameters from the affected facility are obtained. Additional procedures for location of continuous monitoring systems contained in the applicable Performance Specifications of 40 CFR Part 60, 11 Appendix B, must be used. G. The Permittee must meet requirements at 40 CFR 60.13(g) pertaining to effluents from a single affected facility or two or more affected facilities subject to the same emission standards are combined before being released to the atmosphere. H. The Permittee must comply with requirements at 40 CFR 60.13(h) related to data reduction for all continuous monitoring systems for measurement of opacity. Data recorded during periods of continuous monitoring system breakdowns, repairs, calibration checks, and zero span adjustments shall not be included in the data averages. An arithmetic or integrated average of all data may be used. All excess emissions must be converted into units of the standard as specified using applicable conversion procedures. I. The Permittee may provide the EPA with a request for alternatives to any monitoring procedures or requirements at40 CFR 60.13(i)(1-9). The EPA may approve requested alternatives to any monitoring procedures or requirements. J. The Permittee may request an alternative to the relative accuracy test specified 40 CFR Part 60 Performance Specification 2, Appendix B as allowed under 40 CFR 60.13(j)(1-2). No issues were noted with these requirements. This inspection did include a spot check for data related to daily COMS and CEMS calibration for the dates 1/3/2023, 11/14/2022, 4/9/2022, and 11/23/2021. EPA has been receiving notifications and results of stack testing, RATAs, Excess Emissions Reports (EERs) and COMS and CEMS performance evaluations. Part C New Source Performance Measures Emission Limitations and Test Procedures 16. Particulate Matter (PM) Emission Limitations A. The Permittee must comply with requirements at 40 CFR 60.42a, Standard for particulate matter B. The Permittee's Bonanza Unit No. 1 must not discharge into the atmosphere PM in excess of 0.03 lbs/MMBTU heat input from the tall stack, as required at 40 CFR 60.42a(a)(1). C. The Permittee must not discharge to the atmosphere PM in excess of one percent concentration (99 percent reduction) from the tall stack, when combusting solid fuel, as required at 40 CFR 60.42a(a)(2). 12 D. The Permittee's visible emissions from any source must not exceed 20% opacity (6-minute average), except for one 6-minute period per hour of not more than 27% opacity, from any affected facility, including the 600-foottall stack, as required at 40 CFR 60.42a(b). The PM stack test results show that Deseret is meeting these requirements. Below are the annual Compliance Particulate Emission Report results for 2021-2022: 2021 Compliance Particulate Emission Report Result = 0.003/0.005 lb/MMbtu* 2022 Compliance Particulate Emission Report Result = 0.004/0.011 lb/MMbtu* * (Method 5B rate/combined Method 5 and 202 rates) A review of COMS data from Q4 2021 through Q1 2023 showed Deseret to be in compliance with requirement D. 17. Sulfur Dioxide Emission Limitations A. The Permittee must comply with requirements at 40 CFR 60.43a, Standards for sulfur dioxide. B. The Permittee's Bonanza Unit No. 1 must not discharge SO2 in excess of 1.20 lbs/MMBTU heat input and must achieve at least 90% SO2 reduction, or 70% SO2 reduction when the emissions are less than 0.60 lbs/MMBTU, as required at 40 CFR 60.43a(a)(1)- (2). C. The Permittee must comply with the requirements 40 CFR 60.43a (a)(cf) if combusting specified fuels. D. The Permittee must demonstrate compliance with the emission limitation and the percent reduction based on a 30-day rolling average as required at 40 CFR 60.43a(g). E. The Permittee must comply with the applicable standard by use of the proration formula at 40 CFR 60.43a(h)(1). Deseret has been meeting the 1.2 lb/MMBtu requirement and the 70% reduction requirement by a large margin. In fact, every quarterly report has shown Deseret to be below 0.7 lb/MMbtu so the 70% reduction applies. The facility's SO2 emission rate and percent reductions from quarterly reports are shown below: 2022 Q4 <=0.0786 lb/MMbtu and >=93% reduction 2022 Q3 <=0.0411 lb/MMbtu and >=94% reduction 2022 Q2 <=0.0525 lb/MMbtu and >=94% reduction 2022 Q1 <=0.0607 lb/MMbtu and >=95% reduction 2021 Q4 <=0.0640 lb/MMbtu and >=95% reduction 2021 Q3 <=0.0567 lb/MMbtu and >=95% reduction 13 EPA reviews excess emissions reports quarterly and Deseret has not reported excess emissions for SO2 emissions. Deseret does exclude data during startup/shutdown for calculating the 30-day rolling averages. However, given the large degree of compliance margin, excluding any extra data points likely does not significantly effect compliance with these SO2 limits. 18. Nitrogen Oxides (NOx) Emission Limitations A. The Permittee must comply with requirements at 40 CFR 60.44a, Standard for nitrogen oxides. B. The Permittee's Bonanza Unit No. 1 must not discharge into the atmosphere NOx in excess of the emission limit of 0.50 lbs/MMBTU heat input when subbituminous coal is fired, or 0.60 lbs/MMBTU when bituminous coal is fired, based on a 30-day rolling average, as required at 40 CFR 60.44a(a)(1). When subbituminous and bituminous coal are fired simultaneously, the applicable NOx emission standard must be determined by proration using the formula at 40 CFR 60.44a(c). C. The Permittee must achieve at least a 65% N0x reduction of potential combustion concentration, as required at 40 CFR 60.44a(a)(2). According to Deseret, they have been burning exclusively bituminous coal. As such, they are subject to the 0.6 lb/MMBtu limit. After review of quarterly reports, Deseret is in compliance with this limit. The facility's NOx emission rate from the quarterly reports are listed below: 2022 Q4 <=0.27 lb/MMbtu 2022 Q3 <=0.24 lb/MMbtu 2022 Q2 <=0.23 lb/MMbtu 2022 Q1 <=0.25 lb/MMbtu 2021 Q4 <=0.26 lb/MMbtu 2021 Q3 <=0.26 lb/MMbtu Per the compliance provisions of 40 CFR 60.48Da(b), compliance with the limit in paragraph 40 CFR 60.44Da(a)(1) constitutes compliance with the percent removal requirements of 40 CFR 60.44Da(a)(2). Therefore, no evaluation was conducted on the 65% NOx reduction listed above under paragraph C. EPA reviews excess emissions reports quarterly and no excess emissions have been reported for NOx emissions since 3rd quarter 2017. Deseret does exclude data during startup/shutdown and boiler operating days with less than 18 hours of monitoring for calculating the 30-day rolling averages. However, given the large degree of compliance margin and relatively few exclusion days, likely does not significantly affect compliance with these NOx limits. 14 19. The Permittee may apply for a commercial demonstration Permit using emerging technology as allowed by 40 CFR 60.45a(a), Commercial demonstration permit. There is nothing to evaluate (it does not apply) with this general condition. 20. The Permittee must comply with the requirements at 40 CFR 60.46a(a), Compliance provisions. A. The PM emission standards under 40 CFR 60.42a and NOx standards under 40 CFR 60.44a apply at all times, except for periods of startup, shutdown, or malfunction, as required at 40 CFR 60.46a(c). B. As provided at 40 CFR 60.46a(a), compliance with the particulate matter emission limitation under 40 CFR 60.42a(a)(1) constitutes compliance with the percent reduction requirements for particulate matter at 40 CFR 60.42a(a)(2) and (3). C. As provided at 40 CFR 60.46a(b), compliance with NOx emission limitations under 40 CFR 60.44a(a) constitutes compliance with the percent reduction under 40 CFR 60.44a(a)(2). D. The SO2 emission standards under 40 CFR 60.43a(a) apply at all times, except during periods of startup, shutdown, or when emergency conditions exist and the provisions of 40 CFR 60.46a(d) are implemented. E. After the initial performance test required at 40 CFR 60.8, Performance tests, the SO2 emission limitations and percent reduction requirements and the N0x emission limitations are determined as required at 40 CFR 60. 46a (e),(f), and (g). A separate performance test is to be completed at the end of each boiler operating day and a new 30-day average emission rate is to be calculated to show compliance with the standards. F. If the Permittee has not obtained the minimum quantity of emissions data for SO2 and NOx, as required under 40 CFR 60.46a(h), compliance of the affected facility with the emission requirements for these constituents under 60.43a(a) and 60.44a(a) for the day on which the 30-day period ends may be determined by EPA by following the applicable procedures in section 7 of Method 19. 15 Due to extensive renumbering of the CFR, these conditions are now found under 60.48Da, not 60.46a. In general, no problems were noted with these requirements. Deseret is using CEMS to track compliance on a 30-day basis for SO2 and NOx, as evidenced by the submitted quarterly reports. They are meeting the minimum quantity of emissions data and have a high CEMS availability. A review of the CEMS availability for the 2021-2022 semiannual periods shows the below: 2022 July-Dec: 99.1% CEMS availability 2022 January-June: 99.5% CEMS availability 2021 July-Dec: 99.6% CEMS availability 21. The Permittee must comply with requirements at 40 CFR 60.47a, Emission monitoring. A. Opacity is measured using a properly operating continuous monitoring system as required at 40 CFR 60.47a(a). B. SO2 emissions are measured using a properly operating continuous monitoring system as required at 40 CFR 60.47a(b). C. NOx emissions are measured using a properly operating continuous monitoring system as required at 40 CFR 60.47a(c). D. Carbon Dioxide (CO2 ) must be measured at each location where SO2 and NOx are monitored using a continuous monitoring system as required at 40 CFR 60.47a(d). E. The continuous monitoring system to monitor the emission limits established in Conditions 14 and 15 must be operated during all periods of operation of the affected facility, including periods of start up, shutdown, malfunction or emergency conditions, except for continuous monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments, under 40 CFR 60.47a(e). F. If minimum data requirements for continuous emission monitoring (18 hours in at least 22 out of 30 successive boiler days) cannot be met, the Permittee must supplement continuous monitoring data as allowed under 40 CFR 60.47a(f). G. 1-hour (one hour) averages must be calculated and reported as required at 40 CFR 60.47a(g). H. When it becomes necessary to supplement continuous monitoring system data to meet minimum data requirements in Condition 18(F), under 40 CFR 60. 47a(h), Method 6 must be used to determine SO2 concentrations and Method 7 must be used to determine NOx concentrations, or an EPA 16 certified monitoring system may be used to provide continuous monitoring system data. The emissions rate correction factor, integrated bag sampling and analysis procedure of Method 3B must be used to determine oxygen (O2) and CO2. The procedures in Method 19 must be used to compute each 1-hour average concentration in lbs/MMBTU heat input. I. The Permittee's monitoring system performance evaluations and calibration checks must comply with requirements at 40 CFR 60.47(i). J. The Permittee may use the following as alternatives to the reference methods and procedures under 40 CFR 60.47a(j): for Method 6, alternative Methods 6A, 6B, or 6C; for Method 7, alternative Methods 7A, 7C, 7D, or 7E, for Method 3, alternative Methods 3A or 3B, and for Method 3B, Method 3A may be used. Due to extensive renumbering of the CFR, these conditions are now found under 60.49Da, not 60.47a. In addition, some of the paragraph numbers are now different under 60.49Da compared to 60.47a. It appears as though Deseret is in compliance with these requirements. They are meeting the emissions data requirements and have a high CEMS availability (>99.1% for each semiannual period from 2021-2022). The semiannual CEMS availability from 2021-2022 is listed above. The one-hour averages referred to above are only reported when the minimum data requirements have not been met, so Deseret has reported daily averages, as required by Da. 22. The Permittee must comply with 40 CFR 60.48a, Compliance determination procedures and methods. A. For conducting the performance tests required at 40 CFR 60.8, the Permittee must use Methods in 40 CFR Part 60, Appendix A as reference methods, required at 40 CFR 60.48a, Compliance determination procedures and methods. B. The following table summarizes the test Methods and Procedures that must be used to measure emissions rate and concentrations: Pollutant PM Opacity S02 N0x Methoda 19b 9c 19d 19e 5b 6f 7f a. Alternative Methods specified under 40 CFR 60.48a(e) may be used at the Permittee's option. b. Method 19 for emission rate; Method 5 for particulate emissions. 17 Part D 23. Part E 24. The continuous monitoring system must be used to determine concentrations of S02, C02, or 02. c. The Permittee must comply with Condition 18.A. for using a continuous monitoring system to measure the opacity of emissions discharged to the atmosphere. Method 9 may be used provided the opacity continuous monitoring system is inoperative. The Permittee must record the Method 9 data in the Permittee's operating log for the opacity continuous monitoring system. Method 9 must be done each and every hour during visible light and the data must be recorded in the opacity continuous monitoring system log. d. The formula to calculate the percent of potential SO2 emission reduction to the atmosphere under 40 CFR 60.48a(c)(1-5) or concentrations of SO2, and CO2 or O2 must be used as appropriate. e. The continuous monitoring system may be used to determine concentration requirements for NOx, CO2, or O2. f. Continuous emission monitoring system (CEMS) may be used to determine compliance with SO2 and NOx requirements. . Due to extensive renumbering of the CFR, these conditions are now found under 60.50Da, not 60.48a. Through use of the COMS, SO2 and NOx CEMS, and annual Method 5 testing for mass PM, Deseret is in compliance with this condition. Prevention of Significant Deterioration of Air Quality 40 CFR 52.21 Definitions of terms, abbreviations, and references used in this PSD Permit conform to those used in the Prevention of Significant Deterioration of Air Quality, 40 CFR 52.21(b), Definitions. These terms, definitions, abbreviations, and references take precedence over those in this PSD Permit. There is nothing to evaluate with this general condition. PSD Emission Limitations and Test Procedures Particulate Matter (PM) and PM10 Emission Limitations A. The Permittee's Bonanza Unit No. 1 must not discharge to the atmosphere PM at a rate exceeding 0.0297 lbs/MMBTU heat input as determined by test methods in 40 CFR 60, Appendix A, Methods 1-5-5e and 19 or other EPA approved test methods. 18 Per the annual Compliance Particulate Emissions Reports, Deseret is in compliance with this requirement. A list of the test results is listed below: 2022 = 0.004 lb/MMBtu (Method 5) and 0.011 lb/MMBtu (Method 5 and 202) 2021 = 0.003 lb/MMBtu (Method 5) and 0.005 lb/MMBtu (Method 5 and 202) B. The Permittee's Bonanza Unit No. 1 must not discharge to the atmosphere PM10 particulate matter at a rate exceeding 0.0286 lbs/MMBTU heat input as determined by 40 CFR 51, Appendix M, Method 201, Determination of PM10 Emissions or Method 201 A, Determination of PM10 Emissions (Constant Sampling Rate Procedure). Per the annual Compliance Particulate Emissions Reports, Deseret is in compliance with this requirement. While Deseret did not conduct a Method 201 test, the Method 5B test showed filterable total particulate (PM) to be well below the above PM10 limit (0.004 lb/MMBtu in 2022). In addition, adding in the condensable PM emissions measured via Method 202 during the same stack test, total PM (which would be greater than PM10) is still less (0.011 lb/MMBtu) than the PM10 limit above. A list of the test results is listed below: 2022 = 0.004 lb/MMBtu (Method 5) and 0.011 lb/MMBtu (Method 5 and 202) 2021 = 0.003 lb/MMBtu (Method 5) and 0.005 lb/MMBtu (Method 5 and 202) C. The Permittee may use the PM10 particulate matter test results as allowed in Condition 24. B. that are less than 0.0286 lbs/MMBTU heat input to demonstrate compliance with Conditions 24. A. and B. While it appears that Deseret is in compliance with this requirement even though they have not been conducting Method 201 stack tests to demonstrate compliance with the PM and PM10 limits in Condition 24.B., Deseret has been using Method 5 results to demonstrate compliance with these emission limits. In a previous inspection report Hans Beunning stated that "While the permit actually says that a Method 201 would be used for this purpose, a Method 5 test should be more conservative than a Method 201, since it measures both PM and PM10. The permit writer's intention with this condition was probably to say that if the results of the Method 201 testing under 24.A. demonstrates an emission level lower than both the PM and PM10 BACT limits, there is no need to do a Method 5 test because the PM emissions from a baghouse would be made up of mostly PM10. This of Region has been verified with Mike Owens 8 Air Program. While not specifically described in the permit, ECAD does not believe it is necessary to conduct a Method 201 test if the Method 5 testing shows compliance with both the PM and PM10 filterable limits, especially in light of the large margin of compliance Deseret's test results show. In addition, Ron Myers, OAPQS Monitoring Policy Group, confirmed requiring a Method 201 test would be unnecessary in this situation, per an August 10, 2007 email." As such the EPA considers Deseret in compliance with this condition. 19 D. The Permittee's visible emissions from the affected facility must not exceed 20% opacity, as determined by continuous monitoring system (6minute average), except for one six-minute period per hour of not more than 27% opacity, as determined by the continuous monitoring system, as required at 40 CFR 60.47(a)(a). The Permittee may use EPA Method 9 when the opacity continuous monitoring or back up system is not operating. Following an evaluation of the quarterly opacity reports from 2021-2022, no exceedances occurred in the reporting periods. 25. Sulfur Dioxide Emission Control A. The Permittee's Bonanza Unit No. 1 must not discharge to the atmosphere SO2 at a rate exceeding 0.0976 lbs/MMBTU heat input over a rolling 12month average. Compliance must be determined by calculating the rolling 12-month average, based on CEM data and fuel heat input. On the first day of each month, a new 12-month average must be calculated using data from the previous 12 months. A review of semiannual SO2 summary reports showed no 12-month rolling average periods in excess of 0.0976 lbs/MMBTU. B. The Permittee's Bonanza Unit No. 1 must not discharge SO2 to the atmosphere at a rate exceeding 0.15 lbs/MMBTU heat input using a rolling average over 30 successive boiler operating days. Compliance must be determined by the same methods used to determine compliance with the SO2 emission limitation in Condition 17. D. C. The Permittee must achieve at least 90% SO2 removal efficiency based on a 30-day rolling average. D. The Permittee may use scrubber slurry additives, such as adipic acid, lime, etc., to increase the dissolved alkalinity of the slurry reagent used in the fluid gas desulfurization (FGD) scrubber. E. The Permittee's compliance with the SO2 removal requirements must be based on data from the outlet SO2 CEM and either inlet SO2 data from the CEM or coal analysis data, over a 30-day rolling average. The total percent removal must be computed using the total available sulfur from the coal analysis and overall sulfur removal. Compliance must be determined by calculating the arithmetic average for all valid hourly emission rates for SO2 for the 30-successive boiler operating days. F. The Permittee may suggest for EPA approval a method for sulfur analysis 20 in the coal for compliance with Condition 25. E. The method must be an EPA approved Method for sulfur analysis in coal, or be an acceptable industrial analytical procedure for determining sulfur in coal. Based on review of recent quarterly reports, Deseret's 30-day rolling lb/MMBtu and % removal meet these limits. 26. The Permittee must conduct continuous emission monitoring system (CEMS) testing for NOx and SO2 in the tall stack as required by 40 CFR Part 60, Appendix F, Quality Assurance Procedures. The Permittee must perform calibration drift (CD), relative accuracy (RA), cylinder gas audit (CGA), reference methods analysis (RMs), relative accuracy test audit (RATA), and relative accuracy audit (RAA) determinations at 40 CFR Part 60, Appendix F. The testing frequency can be no less than that specified in Appendix F and applies to Part E of this Permit. The Permittee must provide EPA with information required by the Data Assessment Report (DAR) for each quarterly audit with the report of emissions required by Appendix F. The facility has recently performed and passed RATAs (flow monitor, SO2, NOx, and CO2 monitors in October 2021 and September 2022) and particulate emissions test (October 2021 and September 2022). The daily Continuous Emissions Monitoring Daily Report Review that we received for 1/3/2023, 11/14/2022, 4/9/2022 and 11/23/2021 from the facility representative shows the data for the daily calibration that was conducted for these days. 27. Nitrogen Oxides Emission Control The Permittee's Bonanza Unit No. 1 must not discharge into the atmosphere NOx in excess of 0.50 lbs/MMBTU heat input when subbituminous coals is fired, or 0.55 lbs/MMBTU heat input when bituminous coal is fired, based on a 30-day rolling average. If subbituminous and bituminous coal are fired simultaneously, the applicable NOx emission standard must be determined by proration using the formula in 40 CFR 60.44a(c), but must not have NOx emissions in excess of 0.55 lbs/MMBTU heat input, based on a 30-day rolling average. Compliance must be determined by calculating the arithmetic average of all valid hourly emission rates (at least two values each hour are required) for NOx for 30 successive boiler operating days, based on continuous emission monitoring data and fuel heat input. The facility fires bituminous coal, as such they are subject to 0.55 lb/MMbtu emission limit. Based on review of recent quarterly reports, Deseret's 30-day rolling lb/MMBtu emissions are below this limit. BACT for Roads and Fugitive Emissions 21 28. The Permittee must enclose the coal and limestone conveyors and all drop points must be vented to fabric dust collectors. Based on visual observations during the onsite inspection, Deseret is in compliance with this requirement. 29. The Permittee must ensure that the track hopper for bottom dump coal shall have water sprays in place. The water spray must be used during dumping when conditions warrant. Conditions which warrant operation of the sprays are defined as any time the 20% opacity level is in jeopardy of being exceeded. To ensure that the sprays are always operative, the equipment must be tested at least once per month, except when weather conditions prohibit. A log of testing and operation must be kept. The log must include: A Times of testing and results B. Times of coal deliveries C. Times of spray operation D. Weather conditions at time of coal deliveries E. Coal conditions (washed, unwashed, dry, moist, etc.) Due to changes in operation at Deseret's coal mine, the coal is brought to the plant with sufficient moisture such that water sprays are not typically needed. According to Deseret Dust Logs, no water sprays were used only several times at the coal dump station from September 2021 through March 2023. The facility representative provided the "Dust Suppression System Test Log" for October 2021 through March 2023. It appears that the system is tested only during the late spring to early fall months. The logs say the system is "Winterized" from about November through April. The permit condition allows for some discretion to be used by Deseret to not conduct testing when weather conditions prohibit. Previous reports stated that the reason for the draining was to avoid freezing in the pipes during the cold part of the year. 30. The Permittee's coal pile shall not exceed 22 acres in total area. The active reclaim area must not acres exceed 11 at any one time. The reclaim area may be moved to any location on the coal pile. The remainder of the coal pile must be the long-term storage area. Emissions of particulate from the long-term storage area must be controlled by compaction of the coal pile surface and sealing with a surfactant initially and by subsequent application of sealing agent as warranted. A surfactant and spray mechanism to apply it must be available and operative at all times. Conditions which warrant application of the surfactant are defined as any time the 20% opacity level might be exceeded. A log of operation must be kept. The log must include: A. Times of spray operation 22 B. Compaction operation C. Weather conditions D. Surface conditions (dry, crumbled, moist, etc.) Based on satellite imagery the total extent of size of the coal pile is 20.2 acres. During the on-site inspection, visual observations of the coal pile did not indicate insufficient compaction and/or application of sealing agent as no visible emissions were observed. The facility representative provided copies of the "Dust Logs." These logs are for what appears to be four vehicles that compact and/or water/add surfactant to the coal piles. Based on a review of these logs, it appears there is some compaction and watering/adding surfactant of the coal pile (mostly by the 988, Old 844 and New 844). The logs contained the information listed in a-d above. 31. The Permittee's limestone storage must be sealed with a surfactant as dry conditions warrant or as determined necessary by the EPA. During the on-site inspection, there were no fugitive dust problems noted with the limestone storage pile. 32. The Permittee must manage the fly ash/FGD sludge mixture at the end of the conveyor and prior to being completely covered in accordance with landfill procedures. The Permittee must add sprayed water to minimize fugitive emissions as conditions warrant, in accordance with the facility's fugitive dust control plan. During the on-site inspection, the inspectors observed the fly ash/sludge mixture landfill upon entry to the site and did not see any visible emissions from this area. The inspectors also visual verified the implementation of water spray lances. An evaluation of the fugitive dust log showed periodic watering of the exposed landfill area. 33. The Permittee must maintain a record/log of stabilization work done which includes dates, type of stabilizing agent, amount applied, and area of application. We received copies of the October 2021 through March 2023 records for the "EPA Dust Logs". The above information has been tracked. The amount applied is tracked by number of truck loads and the gallons per load is labeled in the excel spreadsheet. 23 34. The Permittee must water spray and/or chemically treat all unpaved roads and other unpaved operational areas that are used by mobile equipment to control fugitive dust. The application of water or chemical treatment must be used. Treatment must be of sufficient frequency and quantity to maintain the surface material in a damp/moist condition. The opacity must not exceed 20% during all times the areas are in use or the outside temperature is below freezing. If chemical treatment is to be used, the plan must be approved by the EPA. The Permittee must maintain records of water treatment for all periods when the plant is in operation. The records must include the following items: A. Date B. Number of treatments made, dilution ratio, and quantity C. Rainfall received, if any, and approximate amount D. Time of day treatments were made Records of treatment must be made available to the EPA upon request and must include a period of two years ending with the date of the request. The unpaved haul roads were being watered according to the "EPA Dust Logs" and no visible emissions from the haul roads were noted upon visible inspection. It appears as though Deseret is meeting this requirement for the water trucks. 35. The Permittee must control visible emissions from haul-road traffic and mobile equipment in operational areas by implementing procedures in its dust control plan. During the onsite inspection, no problems with fugitive emissions from haul roads were observed. 36. The Permittee must develop a Fugitive Emissions Dust Control Plan and provide EPA with a copy of this Plan 90 days after the effective date of this Permit. This Plan must address all applicable Conditions in this Permit. The Permittee must review this Plan annually, by the anniversary date of this Permit, and, if necessary, update or change the Plan to ensure that fugitive emissions are minimized from the facility. The Permittee must provide EPA with the most current copy of the Fugitive Emissions Dust Control Plan within 90 days after revisions are made to it. A copy of the most recent Fugitive Dust Control Plan was provided with the Title V permit (2014). According to Deseret officials, no modifications to the plan have been made; therefore, no review of the plan was performed during this inspection. Part F PSD Monitoring Requirements Table 24 37. The Permittee must perform stack testing to show accuracy of continuous emission monitoring systems with the emission limitations stated in the above conditions, and as specified below: A. Emission Point Pollutant Testing Status Test Frequency Unit No. 1 600 foot tall stack PM * *** PM10 * *** SO2 ** *** NOx ** *** B. Testing Status (to be applied above) * Compliance testing is required. EPA may require testing at any time in accordance with 40 CFR 60.8, Performance tests. The Permittee may elect to use any approved EPA method cited in this Permit. The Permittee may request that alternative EPA approved methods be used instead of those cited in this Permit. The stack testing is to done to test the accuracy of the continuous opacity monitoring system. **Stack testing is done to verify the accuracy of the continuous emission monitoring systems. *** Test every year unless a lesser testing frequency is requested by the Permittee and is approved by EPA. C. PM and PM10 1. The Permittee must note if liquid drops are present in the 600 foot stack and take methods to eliminate the liquid drops. If the Permittee finds no reasonable method to eliminate the drops, then the Permittee must use methods: 40 CFR Part 60, Appendix A, Method 5, 5A, 5B, 5D, 5E, 5G, or 5H as appropriate. The Permittee must test the back half condensibles, using the method specified by EPA. The portion of the front half of the catch and the impinger catch must be combined and be considered PM10 and must be based on information in AP-42, Appendix C, latest edition, Compilation of Air Pollutant Emission Factors, or other acceptable data to EPA. 2. The sample location must be as specified in 40 CFR Part 60, Appendix A, Method 1. 3. The volumetric flow rate must be determined as specified in 40 CFR 25 Part 60, Appendix A, Method 2, Determination of Stack Gas Velocity and Volumetric Flow Rate (Type S Pitot Tube) or Methods 2E, 2F, 2G, and 3D or an alternative method that has EPA's approval. 4. The Permittee's compliance with Condition 21. D. fulfills the requirements in Condition 37. C. D. Sulfur Dioxide (SO2) 40 CFR Part 60, Appendix A, Method 6, Determination of Sulfur Dioxide Emissions from Stationary Sources or Method 6A, 6B, or 6C or an approved EPA Method. E. Nitrogen Oxides (NOX) 40 CFR Part 60, Appendix A, Method 7, Determination of Nitrogen Oxide Emissions From Stationary Sources, or Methods 7A-7E or an approved EPA method. F. The Permittee must report emission rates and removal efficiency under 40 CFR Part 60, Appendix A, Method 19, Determination of Sulfur Dioxide Removal Efficiency and Particulate Matter, Sulfur Dioxide, and Nitrogen Oxides Emission Rates. Deseret is doing annual compliance particulate emission report testing for PM and PM10 (Method 5B and 202) and annual RATAs for the SO2 and NOx CEMS. They use the designated test methods outlined in this section, in compliance. Part G 38. Air Pollution Equipment Operation and Operator Training A. The Permittee must adequately and properly maintain all installations and facilities authorized by this PSD Permit. Instructions from the vendor or established maintenance practices that maximize pollution control must be used. All necessary equipment control and operating devices, such as electronic monitoring displays, pressure gauges, amperes and voltage measurements, flow rate indicators, temperature gauges, CEMs, etc., must be installed and operated properly and easily accessible to compliance inspectors. B. A copy of all manufacturers' operating instruction for pollution control equipment and pollution emitting equipment must be kept on site. These instructions must be available to all employees and personnel who operate the equipment and must be made available to compliance inspectors upon their request. 26 C. The Permittee may have written dated guidance available to ensure the proper operation and maintenance of pollution control equipment that supplements or complements manufacturer's instructions. This guidance may be prepared based on the Permittee's experience with operating pollution control equipment. These instructions must be available to all employees and personnel who operate the equipment and must be made available to compliance inspectors upon their request. During the inspection, EPA inspectors asked about the operating instructions for control equipment, to which the facility representative responded that there are approximately 66 logs for the whole plant, and they are kept in the control room. During that inspection of the control room the inspectors did a spot check of the baghouse operation manual. 39. The Permittee must provide adequate training and periodic re-training to all employees or personnel who operate air pollution control equipment. The facility conducts annual environmental training for every operator. The inspectors observed the training list from the 2021 and 2022 environmental training. 40. Records of operator training must be made available to EPA upon verbal or written request. This PSD Permit must be made available to all employees or personnel by the Permittee who operate the equipment in this PSD Permit. EPA requested and confirmed records of operator training. 41. The Permittee must meet requirements at 40 CFR 60.7 and 11, Notification and record keeping, and Compliance with standards and maintenance requirements, respectively. These rules address start up, shutdown, or malfunction reporting requirements. Deseret has submitted all required notifications for performance tests conducted since August 2019. Deseret also provided all documents requested by the EPA. 42. The Permittee must calculate/estimate the excess emissions whenever a breakdown occurs. The total of excess emissions must be reported semiannually to EPA as required at 40 CFR 60.7(c)-(g) unless more frequent reporting is requested by EPA. Deseret submits quarterly excess emissions reports as required by 40 CFR Part 60, Subpart Da. 43. All records referenced in this PSD Permit or in applicable NSPS requirements, 27 44. Part H 45. 46 47. Part I 48. Part J 49. which are required to be kept by the Permittee, must be made available by the Permittee to EPA upon verbal or written request. Deseret has provided the records requested by EPA during the inspection. The Permittee must keep records for a period of five years, unless EPA requires that the records be maintained for a longer period of time. This condition was not specifically evaluated by EPA during this inspection. No problems were noted during the inspection of records not being kept for a sufficient length of time. Modification and Reconstruction The Permittee must request approval of any future modifications to the equipment or conditions in this PSD Permit related to New Source Performance Standards in accordance with requirements at 40 CFR 60.14, Modification. EPA is not aware of any modifications that would have triggered NSPS since the last inspection. The Permittee must comply with BACT requirements at 40 CFR 52.21(j), Control technology review, for major modifications or phased construction projects. EPA is not aware of any modifications that would have triggered PSD or BACT requirements since the last inspection. The Permittee must comply with requirements at 40 CFR 60.15, Reconstruction. EPA is not aware of any modifications that would have triggered NSPS reconstruction since the last inspection. Sale or Name Change The Permittee must notify EPA in writing if the company is sold or changes its name. The notification must be submitted within 30 days of such proposed action. This condition has not been applicable, since no sale of the company has taken place. Compliance with Environmental Laws This PSD Permit does not release the Permittee from any liability for compliance with other applicable federal and Tribal environmental law and regulations, 28 Part K 50. 51. including the Clean Air Act. There is nothing to evaluate with this general condition. Inspections and Notifications The Permittee must allow EPA or its authorized representatives to inspect the source during normal business hours for purposes of ascertaining compliance with all the conditions of this PSD Permit in accordance with requirements at Part 113, Federal enforcement, and Part 114, Record keeping, inspections, monitoring, and entry of the Clean Air Act as amended. There is nothing to evaluate with this general condition. The Permittee must provide notification of the test date to EPA at least 30 days before the test for each of the above pollutants. A pretest conference must be held, if requested by EPA. The conference must be held at least 30 days before the test between the Permittee, the tester, and EPA. The emission point must be designed to conform to the requirements of 40 CFR 60, Appendix A, Method 1, and approvable access must be provided to the test location by Permittee. Deseret has provided required notifications to EPA prior to stack testing. 29 Title V Permit Requirements (V-U0-000004-00.00) (a) Requirements for Specific Units A. Main Boiler (Unit 1-1) and Emergency Engines Standards of Performance for New Stationary Sources - General Provisions [40 CFR Part 60, Subpart A] Same as PSD permit above (Parts 10-15, 37 and 41-42) Standards of Performance for Electric Utility Steam Generating Units for Which Construction, Modification or Reconstruction Commenced After September 18, 1978 [40 CPR Part 60, Subpart Da] Same as PSD permit above (Part 16-22) National Emission Standards for Hazardous Air Pollutants From Coal and Oil Fired Electric Utility Steam Generating Units. [40 CFR Part 63, Subpart [UUUUU] (a) General Compliance Requirements. [ 40 CFR 63.1 0000 through 63.10001] Effective April 16, 2015, the permittee shall comply with the following requirements for each affected emission unit: (i) The permittee must meet the notification requirements in 63.10030 according to the schedule in 63.10030 and in Subpart A of Part 63. Some of the notifications must be submitted before the permittee is required to comply with the emission limits and work practice standards in Subpart UUUUU. [40 CFR 63.9984(c)] Deseret has submitted the required notifications to their RATAs, performance tests and Particulate emission testing. They have also have submitted the required reports, in compliance. (ii) The permittee must demonstrate that compliance has been achieved, by conducting the required performance tests and other activities no later than 180 days after the applicable date of April 16, 2015 for existing EGUs. [40 CFR 63.9984(f)] Following a review of the submitted performance tests, Deseret has met the requirements for existing EGUs. A 2021 MATS performance test for mercury showed of 0.0351 lb/TBtu (limit: 1.2 lb/TBtu) and the 12 month and 30 day SO2 rolling averages included in the quarterly reports were well below the limits. 30 (iii) At all times, the permittee must meet each emission limit and work practice standard in Tables 2 and 3 of Subpart UUUUU that applies to the EGU at Bonanza plant. [40 CFR 63.9991(a)(l)] [Explanatory note: Table 1 of Subpart UUUUU is not applicable to the EGU at Bonanza plant, because it is not a new or reconstructed EGU, as defined in Subpart UUUUU] A review of Deseret's 2021 mercury testing and SO2 emission reports does not show any noncompliance with the emission limits. The work practice standard requires a tune-up every 48 months because the site has an over-fire air management system. The previous tune-up completed on July 22, 2020 and the next tune up will be required by July 2024. (iv) At all times, the permittee must meet each operating limit in Table 4 of Subpart UUUUU that applies to the EGU at Bonanza plant. [40 CFR 63.9991(a)(2)] Deseret does not operate a PM CPMS and is not subject to table 4. (v) The permittee may use the alternate S02 emission limit in Table 2 of Subpart UUUUU, but only if the EGU has a system using wet or dry FGD technology and S02 CEMS installed on the unit; and at all times, the permittee operates the wet or dry FGD technology installed on the unit consistent with 63.10000(b). [40 CFR 63.9991(c)] Deseret has a wet scrubber installed and uses it at all times, thus they have the option of using the alternate emission limit in table 2. A review of CEMS reports and EERs indicates that they are in compliance with the limit. (vi) The emission limits and operating limits in Subpart UUUUU apply at all times except during periods of startup and shutdown; however, the work practice requirements in Table 3 of Subpart UUUUU must be met during periods of startup or shutdown. [40 CFR 63.10000(a)] The work practice standard requires a tune-up every 48 months because the site has an over-fire air management system. The first tune-up was completed in October 2016 and the following tune-up completed on July 22, 2020 and the next tune-up will be required by July 2024. Deseret also operates their CEMS during periods of startup and shutdown and the inspectors spot checked the CEMS data during a shutdown/start-up period and verified that the CEMS and COMS were operational. It appears Deseret is meeting the startup and shutdown requirements outlined in table 3, in compliance. 31 At all times, the permittee must operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. Determination of whether such operation and maintenance procedures are being used will be based on information available to the EPA Administrator, which may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source. [40 CFR 63.10000(b)] Following a review of performance tests and maintenance records the EPA has determined that Deseret is in compliance with this section. (vii) Initial performance testing is required for all units, to demonstrate compliance with the applicable emission limits. [40 CFR 63.10000(c)(1)] Following a review of the initial performance testing Deseret was shown to be in compliance with the mercury and particulate matter emission limits. The 30day mercury test conducted Aug 12-Sept 11, 2014 resulted in emissions less than 3% of the LEE limit causing Deseret to obtain LEE status. As of September 2017 Deseret has completed all 12 LEE compliance demonstrations to obtain LEE particulate status. (viii) The permittee may conduct the initial performance testing in accordance with 63.10005(h), to determine whether the unit qualifies as a Low Emitting EGU (LEE) for one or more applicable emissions limits, except that the permittee may not pursue the LEE option if the EGU is equipped with an acid gas scrubber and bypass stack exhaust configuration. [40 CFR 63.10000(c)(1)(i)] Deseret is designated as a LEE for mercury and has recently completed its testing to achieve LEE status for particulates. Initial performance testing were based on stack tests and SO2 CEMS measurements conducted in 2014. A list of the performance tests demonstrating LEE status are listed below: Mercury LEE performance demonstrations (Limit = 1.2 lb/Tbtu) 2014 - 0.02 lb/Tbtu 2015 - 0.02 lb/Tbtu 2016 - 0.023 lb/Tbtu 2017 - 0.093 lb/Tbtu 2018 - 0.019 lb/Tbtu 2019 - 0.073 lb/Tbtu 2020 - 0.013 lb/Tbtu 2021 - 0.035 lb/Tbtu 2022 - 0.01 lb/Tbtu PM LEE performance demonstrations (Limit = 0.015 lb/MMbtu) Q4 2014 - 0.006 lb/MMbtu 32 Q1 2015 - 0.005 lb/MMbtu Q2 2015 - 0.003 lb/MMbtu Q3 2015 - 0.006 lb/MMbtu Q4 2015 - 0.006 lb/MMbtu Q1 2016 - 0.005 lb/MMbtu Q2 2016 - 0.003 lb/MMbtu Q3 2016 - 0.004 lb/MMbtu Q4 2016 - 0.003 lb/MMbtu Q1 2017 - 0.006 lb/MMbtu Q2 2017 - 0.006 lb/MMbtu Q3 2017 - 0.005 lb/MMbtu Q3 2018 - 0.008 lb/MMbtu Q3 2020 - 0.008 lb/MMbtu (ix) For a qualifying LEE for Hg emissions limits, the permittee must conduct a 30day performance test using Method 30B at least once every 12 calendar months to demonstrate continued LEE status. [40 CFR 63.10000(c)(1)(ii)] Following a records review of the 2021 and 2022 30-day mercury performance tests, Deseret demonstrated continued LEE status. (x) For a qualifying LEE of any other applicable emissions limits, the permittee must conduct a performance test at least once every 36 calendar months to demonstrate continued LEE status. [40 CFR 63.10000(c)(1)(iii)] Deseret has conducted performance tests to demonstrate particulate LEE status. (xi) If the EGU does not qualify under 63.10000(c)(l)(i) as a LEE for total nonmercury HAP metals, individual non-mercury HAP metals, or filterable PM, the permittee must demonstrate compliance through an initial performance test and must monitor continuous performance through either use of a PM continuous parametric monitoring system (PM CPMS), a PM CEMS, or compliance performance testing repeated quarterly. If the permittee elects to use a PM CPMS, the permittee must establish a site-specific operating limit corresponding to the results of the performance test demonstrating compliance with the pollutant with which the permittee chooses to comply: total nonmercury HAP metals, individual non-mercury HAP metals, or filterable PM. The permittee will use the PM CPMS to demonstrate continuous compliance with this operating limit. The performance test must be repeated annually and the site-specific operating limit reassessed and adjusted in accordance with the results of the performance test. Alternatively, the permittee may opt to install and operate a PM CEMS, certified in accordance with Performance Specification 11 and Procedure 2 of 40 CFR Part 60, Appendices B and F, respectively, in accordance with 63.10010(i). [ 40 CFR 63.10000(c)(1)(iv)] 33 Deseret qualifies as a LEE unit for filterable PM and is not subject to this section. (xii) If the EGU does not qualify as a LEE for hydrogen chloride (HCl), the permittee may demonstrate initial and continuous compliance through use of an HCl CEMS, installed and operated in accordance with Appendix B to Subpart UUUUU. Alternatively, the permittee may demonstrate initial and continuous compliance by conducting initial and quarterly performance stack tests for HCL If the EGU uses wet or dry FGD technology, the permittee may alternatively install and operate a S02 CEMS in accordance with 40 CFR Part 75 to demonstrate compliance with the applicable so2 emission limit. [ 40 CPR 63.10000(c)(1)(v)] Deseret operates a SO2 CEMS in accordance with 40 CFR part 75. As such they are in compliance. (xiii) If the EGU does not qualify as a LEE for mercury (Hg), the permittee must demonstrate initial and continuous compliance through use of a Hg CEMS or a sorbent trap monitoring system, in accordance with Appendix A to Subpart UUUUU. [40 CFR 63.1 0000( c )(1 )(vi)] Deseret qualifies as a LEE unit for mercury and is not subject to this section. (xiv) If the permittee demonstrates compliance with any applicable emissions limit through use of a CMS that includes a CPMS as well as a CEMS, the permittee must develop a site-specific monitoring plan and submit this plan, if requested, at least 60 days before the initial performance evaluation (where applicable) of the CMS. The monitoring plan must address the provisions of 63.10000(d)(1) through (5). This requirement does not apply to affected sources with existing monitoring plans that apply to CEMS and CPMS prepared under Appendix B to 40 CPR Part 60 or 40 CFR Part 75, and that meet the requirements of 63.10010. [40 CPR 63.10000(d)] Deseret has developed as site-specific monitoring plan and provided the EPA with a copy during the previous inspection. (xv) As part of the demonstration of continuous compliance, the permittee must perform periodic tune-ups of the EGU, according to 63.10021(e). [40 CFR 63.10000(e)] This source utilizes a neural network and is required to conduct tune-ups every 48 months. Deseret completed their first tune-up in October 2016. Their second tune-up was conducted on July 22, 2020 and the next one is due in July 2024. 34 (xvi) Affirmative defense for exceedance of emission limit during malfunction. In response to an action to enforce the standard set forth in 63.9991, the permittee may assert an affirmative defense to a claim for civil penalties for exceedances of such standards that are caused by malfunction, as defined in 40 CFR 63.2. Appropriate penalties may be assessed, however, if the permittee fails to meet its burden of proving all of the requirements in the affirmative defense. The affirmative defense shall not be available for claims for injunctive relief. Specific provisions on affirmative defense are in 63.10001(a) and (b). [40 CPR 63.10001] There is nothing to evaluate with this general condition. (b) Testing and Initial Compliance Requirements. [ 40 CFR 63.10005 through 63.10011] (i) General requirements. The permittee must demonstrate initial compliance with applicable emission limits in Tables 2 of Subpart UUUUU through performance testing, which may require collection of hourly electrical load data, establishment of operating limits, and CMS performance evaluations. Initial compliance must also be demonstrated for tune-up work practices, as well as for other requirements for existing EGUs in 63.9984. The permittee shall comply with any additional applicable provisions on demonstrating initial compliance at 63.10005(a)(1) and (2). [40 CFR 63.10005(a)] Deseret demonstrates compliance with emission limits by conducting quarterly particulate stack testing, annual 30-day mercury testing and operation and reporting of a SO2 CEMS. A review of the initial performance tests has shown Deseret to be in compliance with this section. (ii) Performance testing requirements. Performance tests must be conducted according to 63.10007 and Table 5 to Subpart UUUUU. The permittee shall comply with all additional applicable provisions on performance testing at 63.10005(b)(1) through (5). [40 CFR 63.10005(b)] A review of performance testing has shown Deseret to be in compliance with the testing requirements in 63.10007 and Table 5. (iii) Operating limits. In accordance with 63.10010 and Table 4 to Subpart UUUUU, the permittee may be required to establish operating limits using PM CPMS as part of the initial compliance demonstration. [40 CFR 63.10005(c)] Deseret operates a SO2 CEMS and maintains it according to 40 CFR part 75. Deseret does not utilize a PM CPMS, as such Table 4 does not apply. 35 (iv) CMS requirements. If, for a particular emission or operating limit, the permittee is required to (or elects to) demonstrate initial compliance using a CMS, the CMS must pass a performance evaluation prior to the initial compliance demonstration. The permittee shall comply with all additional applicable CMS provisions at 63.10005(d)(1) through (3). [40. CFR 63.10005(d)] Deseret demonstrated initial compliance using a SO2 CEMS. The CEMS passed a performance evaluation prior to the initial compliance and meets ongoing quality assurance requirements and daily calibrations of the CEMS. (v) Tune-ups. All affected EGUs are subject to the work practice standards in Table 3 of Subpart UUUUU. As part of the initial compliance demonstration, the permittee must conduct a performance tune-up of the EGU according to 63.10021 (e). [40 CFR 63.10005(e)] For existing affected sources, a tune-up may occur prior to April 16, 2012, so that existing sources without neural networks have up to 42 calendar months (3 years from promulgation plus 180 days) or, in the case of units employing neural network combustion controls, up to 54 calendar months ( 48 months from promulgation plus 180 days) after the date that is specified for your source in 63.9984 and according to the applicable provisions of 63.7(a)(2) as cited in Table 9 to Subpart UUUUU, to demonstrate compliance with this requirement. If a tune-up occurs prior to such date, the source must maintain adequate records to show that the tune-up met the requirements of this standard. [40 CRR 63.10005()] This source utilizes a neural network and is required to conduct tune-ups every 48 months. Deseret completed their first tune-up in October 2016. Their second tune-up was conducted on July 22, 2020 and their next tune-up is required by July 2024. (vi) Low-emitting EGU (LEE). An EGU may qualify for LEE status for Hg, HCl, HF, filterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals, if performance test data are collected that meet the requirements of 63.10005(h), and if those data demonstrate that emissions are below the levels specified in 63.10005(h)(1). For all pollutants except Hg, all required performance tests described in 63.10007 must be conducted to demonstrate that a unit qualifies for LEE status. For Hg, the procedures described in 63.10005(h)(3) must be used to determine whether a unit qualifies for LEE status. [40 CFR 63.10005(h)] Deseret is designated as a LEE for mercury and has recently completed its performance testing to achieve LEE status for particulates. A list of the performance tests demonstrating LEE status are listed below: Mercury LEE performance demonstrations (Limit = 1.2 lb/Tbtu) 2014 - 0.02 lb/Tbtu 36 2015 - 0.02 lb/Tbtu 2016 - 0.023 lb/Tbtu 2017 - 0.093 lb/Tbtu 2018 - 0.019 lb/Tbtu 2019 - 0.073 lb/Tbtu 2020 - 0.013 lb/Tbtu 2021 - 0.035 lb/Tbtu 2022 - 0.01 lb/Tbtu PM LEE performance demonstrations (Limit = 0.015 lb/MMbtu) Q4 2014 - 0.006 lb/MMbtu Q1 2015 - 0.005 lb/MMbtu Q2 2015 - 0.003 lb/MMbtu Q3 2015 - 0.006 lb/MMbtu Q4 2015 - 0.006 lb/MMbtu Q1 2016 - 0.005 lb/MMbtu Q2 2016 - 0.003 lb/MMbtu Q3 2016 - 0.004 lb/MMbtu Q4 2016 - 0.003 lb/MMbtu Q1 2017 - 0.006 lb/MMbtu Q2 2017 - 0.006 lb/MMbtu Q3 2017 - 0.005 lb/MMbtu Q3 2018 - 0.008 lb/MMbtu Q3 2020 - 0.008 lb/MMbtu (vii) Startup and shutdown. The permittee must follow the requirements given in Table 3 to Subpart UUUUU. [40 CFR 63.100050)] Deseret has completed its initial tune-up in October 2016 and the second tuneup on July 22, 2020. The inspectors confirmed that Deseret operates their CEMS during periods of startup and shutdown. The inspectors spot checked the CEMS data during a shutdown/start-up period and verified that the CEMS and COMS were operational. It appears Deseret is meeting the startup and shutdown requirements outlined in table 3, in compliance. (viii) Notification of compliance status. The permittee must submit a Notification of Compliance Status, summarizing the results of the initial compliance demonstration, as provided in 63.10030. [40 CFR 63.10005(k)] A review of records has shown Deseret to be in compliance with required notifications and result summaries of the initial compliance demonstration. (ix) Subsequent performance tests and tune-ups. [ 40 CFR 63.10006] 37 For EGUs using PM CPMS to monitor continuous performance with an applicable emission limit as provided for under 63.10000(c), the permittee must conduct all applicable performance tests according to Table 5 to Subpart UUUUU and 63.10007 at least every year. [40 CFR 63.10006(a)] For affected units meeting the LEE requirements of 63.10005(h), the permittee must repeat the performance test once every 3 years (once every year for Hg) according to Table 5 and 63.10007. Should subsequent emissions testing results show the unit does not meet the LEE eligibility requirements, LEE status is lost. If this should occur, subsequent testing must be conducted as specified in 63.10006(b). [40 CFR 63.10006(b)] Except where 63.10006(b) applies, coal-fired EGUs that do not use either an HCl CEMS to monitor compliance with the HCl limit or an S02 CEMS to monitor compliance with the alternate equivalent SO2 emission limit, the permittee must conduct all applicable periodic HCl emissions tests according to Table 5 to Subpart UUUUU and 63.10007 at least quarterly, except as otherwise provided in 63.10021(d)(1). [40 CFR 63.10006(d)] Unless the permittee follows the requirements listed in 63.10006(g) and (h), performance tests required at least every 3 calendar years must be completed within 35 to 37 calendar months after the previous performance test; performance tests required at least every year must be completed within 11 to 13 calendar months after the previous performance test; and performance tests required at least quarterly must be completed within 80 to 100 calendar days after the previous performance test, except as otherwise provided in 63.10021 (d)(1). [40 CFR 63.10006()] If a performance test on a non-mercury LEE shows emissions in excess of 50 percent of the emission limit and the permittee chooses to reapply for LEE status, the permittee must conduct performance tests at the appropriate frequency given in 63.10006(c) through (e) for that pollutant, until all performance tests over a consecutive 3-year period show compliance with the LEE criteria. [40 CFR 63.10006(h)] If the permittee is required to meet an applicable tune-up work practice standard, the permittee must conduct a performance tune-up according to 63.10021 (e). [40 CFR 63.10006(i)] The permittee must report the results of performance tests and performance tuneups within 60 days after completion of the test or tune-up. The reports for all subsequent performance tests must include all applicable information required in 63.1 0031. [40 CFR 63.100060)] 38 Deseret has met the performance test schedule for PM, Mercury and SO2 CEMS. Deseret has completed its initial tune-up in October 2016 and the second tune-up on July 22, 2020. The next tune-up is required by July 2024. (x) Methods and other procedures that must be used for performance tests. [40 CFR 63.10007] Except as otherwise provided in 63.10007, the permittee must conduct all required performance tests according to 63.7(d), (e), (f), and (h). The permittee must also develop a site-specific test plan according to the requirements in 63.7(c). If the permittee uses CEMS (Hg, HCl, S02, or other) to determine compliance with a 30-boiler operating day rolling average emission limit, the permittee must collect data for all nonexempt unit operating conditions (see 63.10011(g) and Table 3 to Subpart UUUUU). If the permittee conducts performance testing with test methods in lieu of continuous monitoring, the permittee must operate the unit at maximum normal operating load conditions during each periodic (e.g., quarterly) performance test. Maximum normal operating load will be generally between 90 and 100 percent of design capacity but should be representative of site specific normal operations during each test run. [40 CFR 63.10007(a)] The permittee must conduct each performance test according to the requirements in Table 5 to Subpart UUUUU. This includes traditional 3-run stack tests, 30boiler operating day tests based on CEMS data (or sorbent trap monitoring system data), and 30-boiler operating day Hg emission tests for LEE qualification. [40 CFR 63.10007(b)] If the permittee chooses to comply with the filterable PM emission limit and demonstrate continuous performance using a PM CPMS for an applicable emission limit as provided for in 63.10000(c), the permittee must also establish an operating limit according to 63.10011(b) and Tables 4 and 6 to Subpart UUUUU. Should the permittee desire to have operating limits that correspond to loads other than maximum normal operating load, the permittee must conduct testing at those other loads to determine the additional operating limits. [40 CFR 63.10007(c)] 39 Except for a 30-boiler operating day performance test based on CEMS (or sorbent trap monitoring system) data, where the concept of test runs does not apply, the permittee must conduct a minimum of three separate test runs for each performance test, as specified in 63.7(e)(3). Each test run must comply with the minimum applicable sampling time or volume specified in Table 2 to Subpart UUUUU. Section 63.10005(d) and (h), respectively, provide special instructions for conducting performance tests based on CEMS or sorbent trap monitoring systems, and for conducting emission tests for LEE qualification. [40 CFR 63.10007(d)] To use the results of performance testing to determine compliance with the applicable emissions limits in Table 2 to Subpart UUUUU, proceed as specified in 63.10007(e)(1) through (3). [40 CFR 63.10007(e)] Upon request, the permittee shall make available to the EPA Administrator such records as may be necessary to determine whether the performance tests have been done according to the requirements of 63.10007. [40 CFR 63.1 0007(f)] [Explanatory note: 63.10009 pertains to emissions averaging across multiple EGUs. Since Deseret Power owns and operates only one EGU, 63.10009 is not applicable to Deseret Power. The provisions of 63.10009 are therefore not included in this permit.] During the previous inspection Deseret provided us with a copy of the sitespecific test plan (dated 5/12/14). A review of requested CEMS data appear to show Deseret collecting all required CEMS data. A records review of quarterly (MATS PM performance tests), semi-annually (CEMS compliance reports) and annual (Mercury performance tests) showed Deseret appeared to follow all requirements. Deseret also provided EPA with all requested documents regarding performance tests. In compliance. (xi) Monitoring, installation, operation and maintenance requirements. [40 CFR 63.10010] For the CEMS, PM CPMS, and sorbent trap monitoring systems used to provide data under Subpart UUUUU, the continuous monitoring system installation requirements are as follows, for the single-unit, single-stack configuration applicable to Bonanza plant: For an affected unit that exhausts to the atmosphere through a single, dedicated stack, the permittee shall either install the required CEMS, PM CPMS, and sorbent trap monitoring systems in the stack or at a location in the ductwork downstream of all emissions control devices, where the pollutant and diluents concentrations are representative of the emissions that exit to the atmosphere. [40 CFR 63.10010(a)(1)] [Explanatory note: Deseret Power's Bonanza plant has a single unit, single-stack configuration, therefore 63.10010(a)(l) is applicable to Bonanza plant.] 40 If the permittee uses an 02 or C02 CEMS to convert measured pollutant concentrations to the units of the applicable emissions limit, the 02 or C02 concentrations shall be monitored at a location that represents emissions to the atmosphere, i.e., at the outlet of the EGU, downstream of all emission control devices. The CEMS must be installed, certified, maintained and operated according to 40 CFR Part 75. Only quality-assured 02 or C02 data may be used in the emissions calculations. Part 75 substitute data values may not be used. [40 CFR 63.10010(b)] If the permittee is required to use a stack gas flow rate monitor, either for routine operation of a sorbent trap monitoring system or to convert pollutant concentrations to units of an electrical output based emission standard in Table 2 to Subpart UUUUU, the permittee must install, certify, operate and maintain the monitoring system and conduct ongoing quality-assurance testing of the system according to Part 75. Only unadjusted, quality-assured flow rate data may be used in the emissions calculations. Bias adjustment factors may not be applied to the flow rate data and substitute flow rate data may not be used in the calculations. [40 CFR 63.10010(c)] If the permittee is required to make corrections for stack gas moisture content when converting pollutant concentrations to the units of an emission standard in Table 2 to Subpart UUUUU, the permittee must install, certify, operate, and maintain a moisture monitoring system in accordance with Part 75. Alternatively, for coal-fired units, appropriate fuel-specific default moisture values from 7 5.11 (b) may be used to estimate the moisture content of the stack gas. If a moisture monitoring system is installed and operated, substitute moisture data may not be used in the emissions calculations. [40 CFR 63.10010(d)] If the permittee uses an HCl and/or HF CEMS, the permittee must install, certify, operate, maintain, and quality-assure the data from the monitoring system in accordance with Appendix B to Subpart UUUUU. The permittee must calculate and record a 30-boiler operating day rolling average HCl or HF emission rate in the units of the standard, updated after each new boiler operating day. Each 30boiler operating day rolling average emission rate is the average of all the valid hourly HCl or HF emission rates in the preceding 30 boiler operating days (see section 9.4 to Appendix B to Subpart UUUUU). [40 CFR 63.10010(e)] If the permittee uses an S02 CEMS, the permittee must install the monitor at the outlet of the EGU, downstream of all emission control devices, and must certify, operate and maintain the CEMS according to Part 75. The S02 CEMS shall be operated and emissions calculated in accordance with 63 .1 001 0(f)(2) through (4). [40 CFR 63.10010(f)] 41 If the permittee uses a Hg CEMS or a sorbent trap monitoring system, the permittee must install, certify, operate, maintain and quality-assure the data from the monitoring system in accordance with Appendix A to Subpart UUUUU. Emissions shall be calculated in accordance with the procedures in 63 .1 001 O(g). [40 CFR 63.10010(g)] If the permittee uses a PM CPMS to demonstrate continuous compliance with an operating limit, the permittee must install, calibrate, maintain, and operate the PM CPMS and record the output of the system as specified in 63 .1 001 O(h)( 1) through ( 5). All the data collected during all boiler operating hours must be used in assessing compliance with the operating limit, with the exception of data described in 63.1 001 O(h)(6)(i) through (iii). The permittee must record and make available upon request results of PM CPMS system performance audits, as well as the dates and duration of periods from when the PM CPMS is out of control until completion of the corrective actions necessary to return the PM CPMS to operation consistent with the permittee's site-specific monitoring plan. [40 CFR 63.10010(h)] If the permittee chooses to comply with the PM filterable emissions limit in lieu of metal HAP limits, the permittee may choose to install, certify, operate, and maintain a PM CEMS and record the output of the PM CEMS as specified in 63.10010(i)(1) through (5). The compliance limit will be expressed as a 30boiler operating day rolling average of the numerical emissions limit value applicable to the unit in Table 2 of Subpart UUUUU. [40 CFR 63.10010(i)] The permittee may choose to comply with the metal HAP emissions limits using CEMS approved in accordance with 63.7(f), as an alternative to the performance test method specified in this rule. Specific requirements pertaining to this alternative are in 63.100100). [40 CFR 63.100100)] During the previous on-site inspection, the EPA did visibly identify the stack test port locations on the main stack used for testing. The inspectors did not visibly check the CEMS sampling locations during the inspection. (xii) Demonstrating initial compliance with emission limits and work practice standards. [ 40 CFR 63.10011] The permittee must demonstrate initial compliance with each emissions limit that applies to Bonanza plant by conducting performance testing. 42 If the permittee is subject to an operating limit in Table 4 to Subpart UUUUU, the permittee demonstrates initial compliance with HAP metals or filterable PM emission limit(s) through performance stack tests. If the permittee elects to use a PM CPMS to demonstrate continuous performance, the permittee must also establish a site-specific operating limit, in accordance with Table 4 of Subpart UUUUU, 63.10007, and Table 6 to Subpart UUUUU. The permittee may use only the parametric data recorded during successful performance tests (i.e., tests that demonstrate compliance with the applicable emissions limits) to establish an operating limit. [40 CFR 63.1001l(b)] If the permittee uses a CEMS or sorbent trap monitoring systems to measure a HAP (e.g., Hg or HCl) directly, the first 30-boiler operating day (or, if alternate emissions averaging is used for Hg, the 90-boiler operating day) rolling average emission rate obtained with a certified CEMS after the applicable date in 63.9984 (or, if applicable, prior to that date, as described in 63 .1 0005(b )(2) ), expressed in units of the standard, is the initial performance test. Initial compliance is demonstrated if the results of the performance test meet the applicable emission limit in Table 2 to Subpart uuuuu. [40 CFR 63.10011(c)(1)] For a unit that uses a CEMS to measure S02 or PM emissions for initial compliance, the first 30-boiler operating day average emission rate obtained with a certified CEMS after the applicable date in 63.9984 (or, if applicable, prior to that date, as described in 63.10005(b)(2)), expressed in units of the standard, is the initial performance test. Initial compliance is demonstrated of the results of the performance test meet the applicable so2 or filterable PM emission limit in Table 2 to Subpart UUUUU. [40 CPR 63.100ll(c)(2)] For candidate LEE units, use the results of the performance testing described in 63 .1 0005(h) to determine initial compliance with the applicable emission limits(s) in Table 2 to this subpart and to determine whether the unit qualifies for LEE status. [40 CFR 63.10011(d)] The permittee must submit a Notification of Compliance Status containing the results of the initial compliance demonstration, according to 63.10030(e). [40 CFR 63.10011(e)] The permittee must follow the startup or shutdown requirements given in Table 3 of Subpart UUUUU for each coal-fired EGU. [40 CFR 63.10011(g)] Deseret has conducted initial compliance performance testing for mercury and PM. They have qualified for LEE status for mercury and PM. They have submitted the required notifications of testing and compliance status. (c) Continuous Compliance Requirements. [ 40 CFR 63.10020 through 63.1 0023] 43 (i) Monitoring and collecting data to demonstrate continuous compliance. [40 CFR 63.1 0020] The permittee must monitor and collect data according to 63 .1 0020 and the site-specific monitoring plan required by 63.10000(d). [40 CFR 63.10020(a)] The permittee must operate the monitoring system and collect data at all required intervals at all times that the affected EGU is operating, except for periods of monitoring system malfunctions or out-of-control periods (see 63.8(c)(7)), and required monitoring system quality assurance or quality control activities, including, as applicable, calibration checks and required zero and span adjustments. The permittee is required to conduct monitoring system repairs in response to monitoring system malfunctions and to return the monitoring system to operation as expeditiously as practicable. [40 CFR 63.10020(b)] The permittee may not use data recorded during EGU startup or shutdown or monitoring system malfunctions or monitoring system out-of-control periods, repairs associated with monitoring system malfunctions or monitoring system outof-control periods, or required monitoring system quality assurance or control activities, in calculations used to report emissions or operating levels. The permittee must use all the data collected during all other periods in assessing the operation of the control device and associated control system. [40 CFR 63.10020(c)] Except for periods of monitoring system malfunctions or monitoring system outof-control periods, repairs associated with monitoring system malfunctions or monitoring system out-of control periods, and required monitoring system quality assurance or quality control activities including, as applicable, calibration checks and required zero and span adjustments, failure to collect required data is a deviation from the monitoring requirements. [40 CFR 63.10020(d)] Deseret operates a SO2 CEMS and a COMS during EGU operating periods and calibrate the CEMS according to the regulation. (ii) Demonstrating continuous compliance with emission limitations, operating limits and work practice standards. [63.1 0021] The permittee must demonstrate continuous compliance with each emissions limit, operating limit, and work practice standard in Tables 2 through 4 of Subpart UUUUU that applies to the EGU at Bonanza plant, according to the monitoring specified in Table 6 and 7 to Subpart UUUUU and 63.10021 (b) through (g). [40 CFR 63.10021(a)] 44 Except as otherwise provided in 63.10020( c), if the permittee uses a CEMS to measure S02, PM, HCl, HF, or Hg emissions, or uses a sorbent trap monitoring system to measure Hg emissions, the permittee must demonstrate continuous compliance by using all quality-assured hourly data recorded by the CEMS (or sorbent trap monitoring system) and the other required monitoring systems (e.g., flow rate, C02, 02, or moisture systems) to calculate the arithmetic average emission rate in units of the standard on a continuous 30-boiler operating day (or, if alternate emissions averaging is used for Hg, 90-boiler operating day) rolling average basis, updated at the end of each new boiler operating day. Use Equation 8 in 63.10021(b) to determine the 30- (or, if applicable, 90-) boiler operating day rolling average. [40 CFR 63.10021(b)] If the permittee uses PM CPMS data to measure compliance with an operating limit in Table 4 to Subpart UUUUU, the permittee must record the PM CPMS output data for all periods when the process is operating and the PM CPMS is not out-of-control. The permittee must demonstrate continuous compliance by using all quality-assured hourly average data collected by the PM CPMS for 50 all operating hours to calculate the arithmetic average operating parameter in units of the operating limit (e.g., milliamps, PM concentration, raw data signal) on a 30boiler operating day rolling average basis, updated at the end of each new boiler operating day. Use Equation 9 in 63.1002l(c) to determine the 30-boiler operating day average. [40 CFR 63.10021(c)] If the permittee uses quarterly performance testing to demonstrate compliance with one or more applicable emissions limits in Table 2 to Subpart UUUUU, the permittee must conduct the performance test as defined in Table 5 to Subpart UUUUU, and calculate the results of the testing in units of the applicable standard. The permittee may skip performance testing in those quarters during which less than 168 boiler operating hours occur, except that a performance test must be conducted at least once every calendar year. [40 CFR 63.10021(d)] If the permittee must conduct periodic performance tune-ups of the EGU, as specified in 63.10021(e)(l) through (9), the permittee must perform the first tune-up as part of the initial compliance demonstration. Notwithstanding this requirement, the permittee may delay the first burner inspection until the next scheduled unit outage, provided the permittee meets the requirements of 63.10005. Subsequently, the permittee must perform an inspection of the burner at least once every 36 calendar months, unless the EGU employs neural network combustion optimization during normal operations, in which case an inspection of the burner and combustion controls must be performed at least once every 48 calendar months. [40 CFR 63.1002l(e)] 45 The permittee must submit the reports required under 63 .1 0031 and, if applicable, the reports required under appendices A and B to Subpart UUUUU. The electronic reports required by appendices A and B to Subpart UUUUU must be sent to the Administrator electronically in a format prescribed by the Administrator, as provided in 63 .1 0031. CEMS data (except for PM CEMS and any approved alternative monitoring using a HAP metals CEMS) shall be submitted using EPA's Emissions Collection and Monitoring Plan System (ECMPS) Client Tool. Other data, including PM CEMS data, HAP metals CEMS data, and CEMS performance test detail reports, shall be submitted in the file format generated through use of EPA's Electronic Reporting Tool, the Compliance and Emissions Data Reporting Interface, or alternate electronic file format, all as provided for under 63 .1 0031. [40 CFR 63 .1 0021 (f)] The permittee must report each instance in which the permittee did not meet an applicable emissions limit or operating limit in Tables 2 through 4 to Subpart UUUUU or failed to conduct a required tune-up. These instances are deviations from the requirements of Subpart UUUUU. These deviations must be reported according to 63.10031. [40 CFR 63.10021(g)] The permittee must keep records as specified in 63 .1 0032 during periods of startup and shutdown. [40 CFR 63.10021(h)] The permittee must provide reports as specified in 63 .1 0031, concerning activities and periods of startup and shutdown. [40 CFR 63.10021(i)] [Explanatory note: 63.1 0022 pertains to emissions averaging across multiple EGUs. Since Deseret Power owns and operates only one EGU, 63.1 0022 is not applicable to Deseret Power. The provisions of 63.1 0022 are therefore not included in this permit.] Deseret uses a CEMS to measure hourly SO2 emissions and calculate the appropriate 30 day rolling average. Deseret conducted quarterly PM performance tests until Q3 2017 to demonstrate compliance with the PM emission limits, and now conducts annual testing to demonstrate compliance with the mercury emission limits and 36 month testing to demonstrate compliance with the PM emission limits. They have submitted the required reports and appear in compliance. (iii) Establishing a PM CPMS operating limit and determining compliance with it. [40 CFR 63.10023] 46 During the initial performance test or any such subsequent performance test that demonstrates compliance with the filterable PM individual non-mercury HAP metals, or total non-mercury HAP metals limit in Table 2, record all hourly average output values (e.g., milliamps, stack concentration, or other raw data signal) from the PM CPMS for the periods corresponding to the test runs (e.g., nine 1-hour average PM CPMS output values for three 3-hour test runs). [40 CFR 63.10023(a)] Determine the operating limit as the highest 1-hour average PM CPMS output value recorded during the performance test. The permittee must verify an existing or establish a new operating limit after each repeated performance test. [40 CFR 63.10023(b)] The permittee must operate and maintain the process and control equipment such that the 30 operating day average PM CPMS output does not exceed the operating limit determined in 63.10023(a) and (b). [40 CFR 63.10023(c)] Deseret operates a COMS system and conducts annual PM performance tests to demonstrate compliance with the PM emission limits. (d) Notification, Reports and Records. [40 CFR 63.10030 through 63.10033] (i) Notifications. [40 CFR 63.10030] The permittee must submit all of the notifications in 63.7(b) and (c), 63.8(e), (f)(4) and (6), and 63.9(b) through (h) that apply to the permittee, by the dates specified. [40 CFR 63.10030(a)] As specified in 63 .9(b )(2), if the permittee started up the affected source before April 16, 2012, the permittee must submit an Initial Notification not later than 120 days after April16, 2012. [40 CFR 63.10030(b)] [Explanatory note: Initial notification under 40 CFR 63 subpart UUUUU was provided by Deseret Power on April 3, 2012, via submittal of an updated title V permit application.] When the permittee is required to conduct a performance test, the permittee must submit a Notification of Intent to conduct a performance test at least 30 days before the performance test is scheduled to begin. [40 CFR 63.10030(d)] When the permittee is required to conduct an initial compliance demonstration as specified in 63 .1 0011 (a), the permittee must submit a Notification of Compliance status according to 63.9(h)(2)(ii). The Notification of Compliance Status report must contain all the information specified in 63.10030(e)(1) through (7), as applicable. [40 CFR 63.10030(e)] 47 The EPA has received the required notifications prior to performance tests, in compliance. (ii) Reports. [40 CFR 63.10031] The permittee must submit each report in Table 8 to Subpart UUUUU that applies to the permittee. If the permittee is required to (or elects to) continuously monitor Hg and/or HCl and/or HF emissions, the permittee must also submit the electronic reports required under Appendix A and/or Appendix B to Subpart UUUUU, at the specified frequency. [40 CFR 63.10031(a)] Unless the Administrator has approved a different schedule for submission of reports under 63.10(a), the permittee must submit each report by the date in Table 8 to Subpart UUUUU and according to the requirements in 63.10031(b)(1) through (5). [40 CFR 63.10031 (b)] The compliance report must contain the information required in 63.10031(c)(l) through (4). [40 CFR 63.10031(c)] For each excess emissions occurring at an affected source where a CMS is being used to comply with that emission limit or operating limit, the permittee must include the information required in 63.10(e)(3)(v) in the compliance report specified in 63.10031(c). [40 CFR 63.1 0031 (d)] Each affected source that has obtained a Title V operating permit pursuant to Part 70 or Part 71 must report all deviations as defined in Subpart UUUUU in the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A). If an affected source submits a compliance report pursuant to Table 8 to Subpart UUUUU along with, or as part of, the semiannual monitoring required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all required information concerning deviations from any emission limit, operating limit, or work practice requirement in Subpart UUUUU, submission of the compliance report satisfies any obligation to report the same deviations in the semiannual monitoring report. Submission of a compliance report does not otherwise affect any obligation the affected source may have to report deviations from permit requirements to the permit authority. [40 CFR 63.10031(e)] As of January 1, 2012, and within 60 days after the date of completing each performance test, the permittee must submit the results of the performance tests required by Subpart UUUUU to EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). Performance test data must be submitted in the file format generated through use of EPA's Electronic Reporting Tool (ERT) (see http://www. epa.gov/ttnlchief/ert/index. html). Only data collected using those test methods on the ERT website are subject to this requirement for submitting reports electronically to WebFIRE. 48 Owners or operators who claim that some of the information being submitted for performance tests is confidential business information (CBI) must submit a complete ERT file including information claimed to be CBI on a compact disk or other commonly used electronic storage media (including, but not limited to, flash drives) to EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to EPA via CDX as described above. At the discretion of the delegated authority, the permittee must also submit these reports, including the CBI, to the delegated authority in the format specified by the delegated authority. The permittee shall also comply with reporting requirements in 63.10031 (f)(l) through (5), pertaining to reports of CEMS performance evaluations; quarterly compliance and emissions data reporting for PM CEMS, PM CPMS and approved alternative monitoring using a HAP metals CEMS; and reports for S02 CEMS, Hg CEMS or sorbent trap monitoring system, an HCl or HF CEMS, and any supporting monitors for such systems (such as a diluent or moisture monitor). [40 CFR 63.10031(f)] If the permittee had a malfunction during the reporting period, the compliance report must include the number, duration, and a brief description for each type of malfunction which occurred during the reporting period and which caused, or may have caused, any applicable emission limitation to be exceeded. [40 CFR 63.10031(g)] After a review of hard copies of the performance test reports it appears that Deseret has met the reporting requirements. (iii) Records. [40 CFR 63.10032, 63.10033] The permittee must keep records according to 63.10032(a)(l) and (2). For each CEMS and CPMS, the permittee must keep records according to 63.10032(b)(l) through (4). The permittee must keep the records required in Table 7 to Subpart UUUUU, including records of all monitoring data and calculated averages for applicable PM CPMS operating limits to show continuous compliance with each emission limit and operating limit that applies to the permittee. For each EGU subject to an emission limit, the permittee must also keep the records in 63.10032(d)(l) through (3). The permittee must keep records of the occurrence and duration of each startup and/ or shutdown. 49 The permittee must keep records of the occurrence and duration of each malfunction of an operation (i.e., process equipment) or the air pollution control and monitoring equipment. The permittee must keep records of actions taken during periods of malfunction to minimize emissions in accordance with 63 .1 OOOO(b), including corrective actions to restore malfunctioning process and air pollution control and monitoring equipment to its normal or usual manner of operation. The permittee must keep records of the type(s) and amount(s) of fuel used during each startup and shutdown. [40 CFR 63.10032] Records must be in a form suitable and readily available for expeditious review, according to 63.10(b)(l). As specified in 63 .1 O(b )( 1 ), each record must be kept for 5 years following the date of each occurrence, measurement, maintenance, corrective action, report or record. Each record must be kept on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to 63 .1 O(b )( 1 ). Records can be kept off site for the remaining 3 years. [40 CFR 63.10033] Deseret provided all requested documents during this on-site inspection. (e) Other Requirements and Information. [40 CFR 63.1 0040] The permittee shall comply with all applicable General Provisions in 40 CFR 63.1 through 63.15, as shown in Table 9 to Subpart UUUUU. [40 CFR 63.1 0040] 50 (a) National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines [40 CFR Part 63, Subpart ZZZZ] a) New emergency diesel generator (1,220 HP, started up on January 8, 2013) and new emergency diesel fire pump engine (525 HP, started up at end of August 2014). If the permittee starts up a new or reconstructed stationary Reciprocating Internal Combustion Engines (RICE) with a site rating of more than 500 brake HP located at a major source of HAP emissions on or after August 16, 2004, the stationary RICE does not have to meet the requirements of Subparts A and ZZZZ of 40 CFR Part 63, except for the initial notification requirements of 63.6645(f). The permittee shall submit an Initial Notification not later than 120 days after the engine becomes subject to Subpart ZZZZ. The Notification should include the information in 63.9(b)(2)(i) through (v), a statement that the stationary RICE has no additional requirements, and explain the basis for the exclusion (for example, that it operates exclusively as an emergency stationary RICE if it has a site rating of more than 500 brake HP located at a major source of HAP emissions). [40 CFR 63.6590(b)(1)(i), 63.6600(c), 63.6645(c) and (f)] Deseret has not equipped any new engines since the previous inspection. Deseret Power submitted the required notification to EPA for the new emergency diesel generator on April 4, 2013. The required notification for the new emergency diesel fire pump engine was submitted on August 14, 2014 and thus Deseret is in compliance. (b) Standards of Performance for Stationary Compression Ignition Internal Combustion Engines [40 CFR Part 60, Subpart IIII] These requirements apply to the 1,220-horsepower emergency diesel generator which started up on January 8, 2013, and to the 525-horsepower emergency diesel fire pump engine that was installed in August of 2014. (a) Emission standards. The permittee shall comply with the emission standards for new non-road CI engines in 40 CFR 60.4202, for all pollutants, for the same model year and maximum engine power for their 2007 model year and later emergency stationary CI ICE. The permittee shall operate and maintain stationary CI ICE that achieve the emission standards as required in 40 CFR 60.4205 over the entire life of the engine. [40 CFR 60.4205(b), 60.4205(c), 60.4206] The emergency generator and fire pump engines are maintained according to manufacturer's instructions and are in compliance. (b) Compliance requirements. The permittee shall: 51 (i) Operate and maintain the engine and control device according to the manufacturer's emission-related written instructions; (ii) Change only those emission-related settings that are permitted by the manufacturer; and (iii) Meet the requirements of 40 CFR parts 89, 94, and/or 1068, as they apply to the engine. [40 CFR 60.4211(a)] Emergency stationary ICE may be operated for the purpose of maintenance checks and readiness testing, provided that the tests are recommended by Federal, State or local government, the manufacturer, the vendor, or the insurance company associated with the engine. Maintenance checks and readiness testing of such units is limited to 100 hours per year. There is no time limit on the use of emergency stationary ICE in emergency situations. Emergency stationary ICE may operate up to 50 hours per year in nonemergency situations, but those 50 hours are counted towards the 100 hours per year provided for maintenance and testing. Any operation other than emergency operation, maintenance and testing, and operation in non-emergency situations for 50 hours per year is prohibited. [40 CFR 60.4211 (f)] If the permittee does not install, configure, operate and maintain the engine according to the manufacturer's emission-related written instructions, or changes the emission-related settings in a way that is not permitted by the manufacturer, the permit shall demonstrate compliance in accordance with 40 CFR 60.4211(g)(3) for the emergency diesel generator and 40 CFR 60.4211 (g)(2) for the emergency diesel fire pump engine. [40 CFR 60.4211 (g)] The emergency generator was shown to be operational for a total of 2.4 and 2.7 hours for 2021 and 2022 respectively. The fire pump engine was shown to be operational for a total of 26.4 and 26.0 hours for 2021 and 2022 respectively. The facility representative stated that both of the engines are maintained under manufacturer's instructions. Thus the engines meet these permit conditions and are in compliance. (c) Fuel requirements. Beginning October 1, 2010, the permittee shall purchase only diesel fuel that meets the requirements of 40 CFR 80.510(b) for nonroad diesel fuel. [40 CFR 60.4207(b)] This condition was not specifically evaluated by EPA during the inspection. (d) Testing requirements. Performance tests conducted pursuant to Subpart IIII, if required by 40 CFR 60.4211 (g), shall be done in accordance with 60.4212(a) through (e). [40 CFR 60.4212] Both the fire pump engine and emergency generator engines are emergency engines 52 manufactured after 2007 and are maintained according to manufacturer's instructions. Thus they have no testing requirements and are in compliance. (e) Notifications, reports and records. If the stationary CI internal combustion engine is an emergency stationary internal combustion engine, the owner or operator is not required to submit an initial notification. Starting with the model years in Table 5 of NSPS Subpart IIII, if the emergency engine does not meet the standards applicable to non-emergency engines in the applicable model year, the permittee shall keep records of the operation of the engine in emergency and nonemergency service that are recorded through the non-resettable hour meter. The permittee shall record the time of operation of the engine and the reason the engine was in operation during that time. [40 CFR 60.4214(b)] Deseret Power submitted the required notification to EPA for the new emergency diesel generator on April 4, 2013. The required notification for the new emergency diesel fire pump engine was submitted on August 14, 2014. The emergency generator was shown to be operational for a total of 2.4 and 2.7 hours for 2021 and 2022 respectively. The fire pump engine was shown to be operational for a total of 26.4 and 26.0 hours for 2021 and 2022 respectively. The facility representative stated that both of the engines are maintained under manufacturer's instructions. Thus the engines meet these permit conditions and are in compliance. 6. Federal PSD Permit Issued February 2, 2001. [40 CFR 52.21 and Federal PSD permit issued February 2, 2001] Same as PSD permit above (parts 23-27) 7. Compliance Assurance. [40 CFR 71.6(c)(l)] Requirements in this section have been developed under authority of 40 CFR 71.6(c)(1), to provide for reasonable assurance of compliance with this permit, and do not constitute a CAM plan under the Compliance Assurance Monitoring Rule (40 CFR Part 64). These requirements are in addition to requirements of 40 CFR Part 64. (a) Particulate/PM10. For purposes of conducting the annual particulate and PM10 stack emission tests required under section II.A.6.(a) of this permit, in addition to meeting the stack emission testing requirements of 40 CFR Part 60 (sections II.A.1 and II.A.2 of this permit) and of the Federal PSD permit dated February 2, 2001 (section II.A.6 of this permit), the permittee shall comply with the following test-related requirements for assuring compliance under 40 CFR 71.6(c)(1). (i) Stack emission test plan. A stack test plan for particulate/PM10 shall be submitted to the EPA Regional Office, at least 45 days prior to each annual particulate/PM10 test. The only exception shall be that if an annual test is scheduled to occur less than 53 three months after issuance of this initial Part 71 operating permit, a stack test plan shall not be required until 45 days prior to the next annual test. The test plan shall include and address the following elements: (A) Schedule/dates for test (B) Pollutant(s) to be tested (particulate and/or PM10) (C) Expected operating rate(s) during test (D) Related emission control device parameters or other plant parameters to be monitored during emission test (E) Sampling and analysis procedures (1) Sampling locations (2) Test method(s) (3) Analysis procedures and laboratory identification (F) Quality assurance plan (1) Calibration procedures and frequency (2) Sample recovery and field documentation (3) Chain-of-custody procedures (G) Data processing and reporting (1) Description of data handling and quality control procedures (2) Report content operating If a stack test plan for an annual particulate/PM10 test has been submitted that addresses all of the above elements, the stack test plans for subsequent annual tests must contain only elements (A) and (B) above, along with any other elements listed above that have changed from the test plan previously submitted. The EPA did not assess compliance with these provisions during the inspection. (ii) Operating rate during stack emission tests. All particulate and PM10 tests shall be performed at maximum operating rate (90% to 110% of boiler heat input design capacity). (iii) Adjustments. Only regular operating staff may adjust the emission control device settings or related process or operational parameters immediately prior to or during the test. Any such adjustments that are a result of consultation during the tests with testing personnel, equipment vendors, or consultants, may result in a determination by EPA that the test is invalid. (iv) Data to be collected. During each test run, data shall be collected on all parameters necessary to document how emissions were measured or calculated (such as test run length, minimum sample volume, volumetric flow rate, pollutant concentration, moisture and diluent corrections). (v) Number of test runs. Each test shall consist of at least three (3) valid test runs. Emission results shall be reported as the arithmetic average of all valid test runs and shall be in terms of the permit emission limit. (vi) Test report. A test report shall be submitted to the EPA Regional Office within 60 days after completing the annual particulate/PM10 tests. 54 After a review of the 2021 and 2022 Compliance Particulate Emissions Reports, Deseret was shown to be in compliance with these permit conditions. (b) Sulfur dioxide and nitrogen oxide. For purposes of reporting on compliance with the rolling 30-day and rolling 12-month SO2 emission limitations in section II.A.5.(b) of this permit, and for reporting on compliance with the rolling 30-day NOx emission limitation in section II.A.5.(c) of this permit, the permittee shall follow the reporting requirements of 40 CFR 60.7 and the additional reporting requirements of 40 CFR 60.51Da. Upon evaluation of the quarterly reports, semiannual EERs and annual RATA testing, Deseret appears to have met the permit reporting requirements for SO2 and NOx emissions. 8. Federal Phase II Acid Rain Program. [40 CFR Parts 72 through 78] [Explanatory note: Applicable requirements from 40 CFR 71.6(a)(4) pertaining to acid rain program may be found in section III H of this permit.] Bonanza Unit 1-1 is an affected unit under the Acid Rain Program, as defined in 40 CFR 72.2 and 72.6. This section II.A.8 incorporates applicable Acid Rain Program provisions from 40 CFR Parts 72 through 78. (a) Permitting. [40 CFR Part 72] (i) The designated representative for Bonanza Unit 1-1 shall: (A) Submit a complete Acid Rain permit application (including a compliance plan) under 40 CFR Part 72, in accordance with the applicable deadlines specified in 40 CFR 72.30 (for Acid Rain permit renewal, the deadline is 6 months prior to expiration of the existing Acid Rain permit); and [40 CFR 72.9(a)(l)(i) and 72.30(c)] (B) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review an Acid Rain permit application and issue or deny an Acid Rain permit. [40 CFR 72.9(a)(1)(iii)] Deseret has submitted a complete Acid Rain permit application in 2002 and is in compliance with this condition. (ii) The owners and operators of Bonanza Unit 1-1 shall: (A) Operate the Unit in compliance with a complete Acid Rain permit application or a superseding Acid Rain permit issued by the permitting authority; and (B) Have an Acid Rain permit. [40 CFR 72.9(a)(2)] 55 Deseret has an Acid Rain permit and to our knowledge is operating unit 1-1 within compliance. (b) Monitoring. [ 40 CFR Parts 72, 73 and 75] (i) The owners and operators and, to the extent applicable, the designated representative for Bonanza Unit 1-1, shall comply with the monitoring requirements as provided in 40 CFR Part 75. [40 CFR 72.9(b)(1)] (ii) The emissions measurements recorded and reported in accordance with 40 CFR Part 75 shall be used to determine compliance by Bonanza Unit 1-1 with the Acid Rain emissions limitations and emissions reduction requirements for S02 and NOx under the Acid Rain Program. [40 CFR 72.9(b)(2)] (iii) The requirements of 40 CFR Part 75 shall not affect the responsibility of the owners and operators to monitor emissions of other pollutants or other emissions characteristics at Bonanza Unit 1-1 under other applicable requirements of the Clean Air Act and other provisions of this Part 71 operating permit for the Bonanza plant. [40 CFR 72.9(b )(3)] Deseret is meeting the CEMS requirements for SO2, NOx and PM emissions. (c) Sulfur dioxide. [40 CFR Parts 72 and 73] (i) The Acid Rain Program Phase II allowance allocation for Bonanza Unit 1-1, as listed in Table 2 of 40 CFR 73.10, is: (A) 10,782 tons for each of calendar years 2000 through 2009; and (B) 8,818 tons for years 2010 and beyond. Annual SO2 emissions total approximately ~1000 tons at the Deseret plant; therefore, the site is well below the Acid Rain Program allowance (8,818 tons per year). (ii) The number of allowances actually held by an affected source in a unit account may differ from the number allocated by the EPA in Table 2 of 73.1 0. Under 40 CFR 72.84, changes in a unit account do not necessitate a revision to the unit's S02 allowance allocations identified in this permit. [40 CFR 73.10 and 72.84] There is nothing to evaluate with this general condition. (iii) The owners and operators of Bonanza Unit 1-1 shall: 56 (A) Hold allowances in the S02 compliance subaccount for Bonanza Unit 1-1, as of the allowance transfer deadline defined in 40 CFR 72.2 (after deductions under 40 CFR 73.34(c)) no less than the total annual S02 emissions for the previous calendar year from Unit 1-1; and (B) Comply with the applicable Acid Rain emissions limitation for SO2. [40 CFR 72.9(c)(1)] Deseret has met remained below annual emissions allowances for the 2017 and 2018 calendar years. (iv) Each ton of S02 emitted in excess of the Acid Rain emissions limitations for S02 shall constitute a separate violation of the Clean Air Act. [40 CFR 72.9(c)(2)] (v) Starting January 1, 2000, Bonanza Unit 1-1 is subject to the requirements of 40 CFR 72.9(c)(l), Sulfur Dioxide Requirements. [40 CFR 72.9(c)(3)(iii)] (vi) Allowances shall be held in, deducted from, or transferred among Allowance Tracking System accounts in accordance with the Acid Rain Program. [40 CFR 72.9(c)(4)] (vii) An allowance shall not be deducted in order to comply with the requirements of 40 CFR 72.9(c)(1)(i) prior to the calendar year for which the allowance was allocated. [40 CFR 72.9(c)(5)] (viii) An allowance allocated by the EPA Administrator under the Acid Rain Program is a limited authorization to emit S02 in accordance with the Program. No provision of the Program, the Acid Rain permit application, the Acid Rain permit, or an exemption under 40 CFR 72.7 and 72.8, and no provision of law, shall be construed to limit the authority of the United States to terminate or limit such authorization. [40 CFR 72.9(c)(6)] (ix) An allowance allocated by the EPA Administrator under the Acid Rain Program does not constitute a property right. [40 CFR 72.9(c)(7)] Deseret has been in compliance with their SO2 emissions and has emitted less than their allowance. (d) Nitrogen oxide. [40 CFR Parts 72 and 76] (i) The owners and operators of Bonanza Unit 1-1 shall comply with the applicable Acid Rain emissions limitation for NOx. The applicable Phase II NOx emission limitation for dry bottom wall fired boilers is 0.46lb/MMBtu on an annual average basis, beginning on January 1, 2008. [40 CFR 72.9(d) and 76.7(a)(2)] 57 [Explanatory note: The initial Acid Rain permit issued for Bonanza plant on December 29, 1997, specified a NOx early election emission limit of 0.50 lb/MMBtu. Under 40 CFR 76.8(a)(2), the early election limit expired on January 1, 2008 and the NOx emission limit reverted to the applicable standard Phase II NOx limit, which is 0.46 lb/MMBtu for Bonanza plant.] A review of 2021 and 2022 annual averages have shown Deseret to be in compliance with this limit. (e) Excess emissions. [ 40 CFR Parts 72 and 77] (i) The designated representative of Bonanza Unit 1-1 that has excess emissions in any calendar year shall submit a proposed offset plan, as required by 40 CFR Part 77. [40 CFR 72.9(e)(l)] Deseret has not reported excess emissions since the previous inspection in 2019. (ii) The owners and operators of Bonanza Unit 1-1 that has excess emissions in any calendar year shall: (A) Pay without demand the penalty required, and pay upon demand the interest on that penalty, as required by 40 CFR Part 77; and (B) Comply with the terms of an approved offset plan, as required by 40 CFR Part 77. [40 CFR 72.9(e)(2)] Deseret has not reported excess emissions since the previous inspection in 2021. (f) Recordkeeping and reporting. [40 CFR Parts 72, 73 and 75] (i) Unless otherwise provided, the owners and operators of Bonanza Unit 1-1 shall keep on site at Bonanza plant each of the following documents for a period of 5 years from the date the document is created. This period may be extended for cause, at any time prior to the end of 5 years, in writing by the Administrator. (A) The certificate of representation for the designated representative for Bonanza Unit 1-1 and all documents that demonstrate the truth of the statements in the certificate of representation, in accordance with 40 CFR 72.24; provided that the certificate and documents shall be retained on site at Bonanza plant beyond such 5-year period until such documents are superseded because of the submission of a new certificate of representation changing the designated representative. 58 (B) All emissions monitoring information, in accordance with 40 CFR Part 75, provided that to the extent that Part 75 provides for a 3-year period for recordkeeping, the 3-year period shall apply. (C) Copies of all reports, compliance certifications, and other submissions and all records made or required under the Acid Rain Program. (D) Copies of all documents used to complete an Acid Rain permit application and any other submission under the Acid Rain Program or to demonstrate compliance with the requirements of the Acid Rain Program. [40 CFR 72.9(f)(1)] The EPA received an updated notice of change of the designated representative on 4/5/2016. Additionally, Deseret provided the EPA with all requested documents and information. (ii) The designated representative for Bonanza Unit 1-1 shall submit the reports and compliance certifications required under the Acid Rain Program, including those under Subpart I of 40 CFR Part 72, and 40 CFR Part 75. [40 CFR 72.9(t)(2)] It appears that Deseret is in compliance with the CEMS and permitting reporting requirements. (g) Liability. [40 CFR Parts 72 through 78] (ii) Any person who knowingly violates any requirement or prohibition of the Acid Rain Program, a complete Acid Rain permit application, an Acid Rain permit, or an exemption under 40 CFR 72.7 or 72.8, including any requirement for the payment of any penalty owed to the United States, shall be subject to enforcement pursuant to section 113(c) of the Act. [40 CFR 72.9(g)(l)] (iii) Any person who knowingly makes a false, material statement in any record, submission, or report under the Acid Rain Program shall be subject to criminal enforcement pursuant to section 113(c) of the Act and 18 U.S.C. 1001. [40 CFR 72.9(g)(2)] (iv) No permit revision shall excuse any violation of the requirements of the Acid Rain Program that occurs prior to the date that the revision takes effect. [40 CFR 72.9(g)(3)] (v) Each affected source and each affected unit shall meet the requirements of the Acid Rain Program. [40 CFR 72.9(g)(4)] (vi) Any provision of the Acid Rain Program that applies to an affected source (including a provision applicable to the designated representative of an affected 59 source) shall also apply to the owners and operators of such source and of the affected units at the source. [ 40 CFR 72.9(g)(5)] (vii) Any provision of the Acid Rain Program that applies to an affected unit (including a provision applicable to the designated representative of an affected unit) shall also apply to the owners and operators of such unit. Except as provided under 40 CFR 72.44 (Phase II repowering extension plans) and 40 CFR 76.11 (NOx averaging plans), and except with regard to the requirements applicable to units with a common stack under 40 CFR Part 75 (including 40 CFR 75.16, 75.17, and 75.18), the owners and operators and the designated representative of one affected unit shall not be liable for any violation by any other affected unit of which they are not owners or operators or the designated representative and that is located at a source of which they are not owners or operators or the designated representative. [40 CFR 72.9(g)(6)] (viii) Each violation of a provision of 40 CFR Parts 72, 73, 74, 75, 76, 77, and 78 by an affected source or affected unit, or by an owner or operator or designated representative of such source or unit, shall be a separate violation of the Act. [40 CFR 72.9(g)(7)] No violations of the Acid Rain Program were apparent during the previous onsite inspection. (h) Effect on other authorities. [40 CFR Parts 72 and 73] No provision of the Acid Rain Program, an Acid Rain permit application, an Acid Rain permit, or an exemption under 40 CFR 72.7 or 72.8 shall be construed as: (i) Except as expressly provided in title IV of the Act, exempting or excluding the owners and operators and, to the extent applicable, the designated representative of an affected source or affected unit from compliance with any other provision of the Act, including the provisions of title I of the Act relating to applicable National Ambient Air Quality Standards or State Implementation Plans; (ii) Limiting the number of allowances a unit can hold; provided, that the number of allowances held by the unit shall not affect the source's obligation to comply with any other provisions of the Act; (iii) Requiring a change of any kind in any State law regulating electric utility rates and charges, affecting any State law regarding such State regulation, or limiting such State regulation, including any prudence review requirements under such State law; (iv) Modifying the Federal Power Act or affecting the authority of the Federal Energy Regulatory Commission under the Federal Power Act; or, (iv) Interfering with, or impairing, any program for competitive bidding for power supply in a State in which such program is established. [40 CFR 72.9(h)] 60 This condition was not specifically evaluated by EPA during the inspection. B. Fugitive Emission Sources The requirements in this section II.B pertain to sources of emissions at Bonanza plant other than point sources (main boiler, auxiliary boiler, emergency diesel generator, emergency diesel fire pump, and construction heaters). (a) Requirements from Federal PSD Permit Issued February 2, 2001- BACT for Roads and Fugitive Emissions. (a) The permittee shall enclose the coal and limestone conveyors and all drop points shall be vented to fabric filter dust collectors. Addressed in PSD permit evaluation, part 28 (p.27 of this report) (b) The permittee shall ensure that the track hopper for bottom dump coal shall have water sprays in place. The water spray shall be used during dumping when conditions warrant. Conditions which warrant operation of the sprays are defined as any time the 20% opacity level is in jeopardy of being exceeded. To ensure that the sprays are always operative, the equipment shall be tested at least once per month, except when weather conditions prohibit. A log of testing and operation shall be kept. The log shall include: (i) Times of testing and results; (ii) Times of coal deliveries; (iii) Times of spray operation; (iv) Weather conditions at time of coal deliveries; and (v) Coal conditions (washed, unwashed, dry, moist, etc.). Addressed in PSD permit evaluation, part 29 (p.27 of this report) (c) The permittee's coal pile shall not exceed 22 acres in total area. The active reclaim area shall not exceed 11 acres at any one time. The reclaim area may be moved to any location on the coal pile. The remainder of the coal pile shall be the long-term storage area. Emissions of particulate from the long-term storage area shall be controlled by compaction of the coal pile surface and sealing with a surfactant initially and by subsequent application of sealing agent as warranted. A surfactant and spray mechanism to apply it shall be available and operative at all times. Conditions which warrant application of the surfactant are defined as any time the 20% opacity level might be exceeded. A log of operation shall be kept. The log shall include: (i) Times of spray operation; (ii) Compaction operation; (iii) Weather conditions; and (iv) Surface conditions (dry, crumbled, moist, etc.). 61 Addressed in PSD permit evaluation, part 30 (p.28 of this report) (d) The permittee's limestone storage shall be sealed with a surfactant as dry conditions warrant or as determined necessary by the EPA. Addressed in PSD permit evaluation, part 31 (p.29 of this report) (e) The permittee shall manage the fly ash FGD sludge mixture at the end of the conveyor and prior to being completely covered in accordance with landfill procedures. The permittee shall add sprayed water to minimize fugitive emissions as conditions warrant, in accordance with the facility's Fugitive Emissions Dust Control Plan. [Explanatory note: The Fugitive Emissions Dust Control Plan appears as Attachment 2 to this permit.] Addressed in PSD permit evaluation, part 32 (p.29 of this report) (f) The permittee shall maintain a record/log of stabilization work done which includes dates, type of stabilizing agent, amount applied, and area of application. Addressed in PSD permit evaluation, part 33 (p.29 of this report) (g) The permittee shall water spray and/or chemically treat all unpaved roads and other unpaved operational areas that are used by mobile equipment to control fugitive dust. The application of water or chemical treatment shall be used. Treatment shall be of sufficient frequency and quantity to maintain the surface material in a damp/moist condition. The opacity shall not exceed 20% during all times the areas are in use or the outside temperature is below freezing. If chemical treatment is to be used, the plan shall be approved by the EPA Region 8 Office. The permittee shall maintain records of water treatment for all periods when the plant is in operation. The records shall include the following items: (i) Date; (ii) Number of treatments made, dilution ratio, and quantity; (iii) Rainfall received, if any, and approximate amount; and (iv) Time of day treatments were made. Records of treatment shall be made available to the EPA Region 8 Office upon request and shall include a period of two years ending with the date of the request. Addressed in PSD permit evaluation, part 34 (p.30 of this report) (h) The permittee shall control visible emissions from haul-road traffic and mobile equipment in operational areas by implementing procedures in its Fugitive Emissions Dust Control Plan. Addressed in PSD permit evaluation, part 35 (p.30 of this report) 62 (i) The permittee shall develop a Fugitive Emissions Dust Control Plan and provide the EPA Region 8 Office with a copy of this Plan by 90 days after the effective date of the EPA PSD permit issued on February 2, 2001. The Plan shall address all applicable conditions in this permit. The permittee shall review this Plan annually, by the anniversary date of this Permit, and, if necessary, update or change the Plan to ensure that fugitive emissions are minimized from the facility. The permittee shall provide the EPA Region 8 Office with the most current copy of the Fugitive Emissions Dust Control Plan within 90 days after revisions are made to it. Addressed in PSD permit evaluation, part 36 (p.30 of this report) 2. Requirements from 40 CFR Part 60, Subpart Y: Standards of Performance for Coal Preparation Plants. (a) The provisions of Subpart Y apply to coal preparation plants commencing construction or modification after October 24, 1974 and processing more than 200 tons per day of coal. "Coal preparation plant" is defined in Subpart Y as any facility (excluding underground mining operations) which prepares coal by one or more of the following processes: breaking, crushing, screening, wet or dry cleaning, and thermal drying. Affected facilities at coal preparation plants include the following equipment at Bonanza plant: coal processing and conveying equipment (including breakers and crushers) and coal storage systems. "Coal storage system," as defined in Subpart Y, excludes open storage piles. [40 CFR 60.250 & 60.251] There is nothing to evaluate with this general condition. (b) The following provision of Subpart Y applies to Bonanza plant: On and after the date on which the performance test required to be conducted by 40 CFR 60.8 is completed, the permittee shall not cause to be discharged into the atmosphere gases which exhibit 20 percent opacity or greater, from any coal processing and conveying equipment (including breakers and crushers) and coal storage. Opacity shall be determined by Method 9 and the procedures in 40 CFR 60.11. [40 CFR 60.252(c) & 60.254(b)(2)] No visible emissions were identified during a visual inspection of the coal processing, handling and impoundments during the on-site inspection. Dust suppressant technologies are installed at the coal handling facilities and storage impoundment. Following an evaluation of semi-annual opacity reports, it appears that Deseret is in compliance with this condition. (c) Method 9 observations shall be conducted no less frequently than monthly. Dates and locations where observations were conducted, as well as the opacities that were recorded, shall be identified in the semi-annual monitoring reports required by this permit. [40 CFR 71.6(c)(1)] 63 [Explanatory note: There is no wet or dry cleaning or thermal drying of coal at Bonanza plant. Also, there is no equipment at Bonanza plant meeting the definition of "coal transfer and loading system" in Subpart Y, since no coal is shipped from the plant.] An evaluation of all semi-annual monitoring reports (for September 2021 to March 2023) showed that Deseret was in compliance with this permit condition. III. Facility-Wide or Generic Permit Requirements Conditions in section III of this permit apply to all emissions units located at the facility, including any units not specifically listed in Tables 2 and 3 of section I.B. A. Air Pollution Control Equipment Operation and Operator Training [40 CFR 52.21 and Federal PSD permit dated February 2, 2001] 1) In addition to the requirements of 40 CFR 60.11 (d), the permittee shall adequately and properly maintain all installations and facilities covered by this permit. Instructions from the vendor or established maintenance practices that maximize pollution control shall be used. All necessary equipment control and operating devices, such as electronic monitoring displays, pressure gauges, amperes and voltage measurements, flow rate indicators, temperature gauges, CEMs, etc., shall be installed and operated properly and be easily accessible to compliance inspectors. 2) A copy of all manufacturers' operating instructions for pollution control equipment and pollution emitting equipment shall be kept on site. These instructions shall be available to all employees and personnel who operate the equipment and shall be made available to compliance inspectors upon their request. 3) The permittee may have written dated guidance available to ensure the proper operation and maintenance of pollution control equipment that supplements or complements manufacturer's instructions. This guidance may be prepared based on the permittee's experience with operating pollution control equipment. The guidance shall be available to all employees and personnel who operate the equipment and shall be made available to compliance inspectors upon their request. 4) The permittee shall provide adequate training, and periodic re-training, to all employees or personnel who operate air pollution control equipment. Records of operator training shall be made available to EPA upon verbal or written request. The EPA PSD permit dated February 2, 2001, shall be made available by the permittee to all employees or personnel who operate the equipment covered by the PSD permit. Answered in PSD permit evaluation, parts 38-40 (p.32 of this report) B. Recordkeeping Requirements [40 CFR 71.6(a)(3)(ii) and 63.10(b)(3)] 64 In addition to the unit-specific recordkeeping requirements in section II of this permit, the permittee shall comply with the following generally applicable recordkeeping requirements of 40 CFR Parts 63 and 71: 1) Types of records. The permittee shall keep records of required monitoring information that include the following: (a) The date, place, and time of sampling or measurements; (b) The date(s) analyses were performed; (c) The company or entity that performed the analyses; (d) The analytical techniques or methods used; (e) The results of such analyses; and (f) The operating conditions as existing at the time of sampling or measurement. Deseret's stack test reports (RATA and Particulate Emission Reports) includes the required information listed above, in compliance. 2) Records retention. The permittee shall retain records of all required monitoring data and support information for a period of at least 5 years from the date of the monitoring sample, measurement, report, or application. Support information includes all calibration and maintenance records, all original strip-chart recordings for continuous monitoring instrumentation, and copies of all reports required by this permit. [40 CFR 71.6(a)(3)(ii)] This condition was not specifically evaluated by EPA during this inspection. Deseret provided the EPA with all requested documents and no problems were noted regarding records not being kept for a sufficient length of time. 3) Records of 40 CFR Part 63 non-applicability determinations. 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 is not subject to a relevant standard or other requirement established under 40 CPR Part 63, the permittee shall keep a record of the non-applicability determination on site at the source for a period of five years after the determination, or until the source changes its operations to become an affected source, whichever comes first. The record of the nonapplicability 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 CPR 63.10(b)(3)] To the EPA's knowledge there has not been a non-applicability determination for the Deseret power plant since the previous inspection. C. Reporting Requirements [40 CFR 71.6(a)(3)(iii)] 65 In addition to the unit-specific reporting requirements in section II of this permit, the permittee shall comply with the following generally applicable reporting requirements of 40 CPR Part 71: 1) Semiannual monitoring reports. The permittee shall submit all reports of any required monitoring under this permit at least every six months, by April 1 and October 1 of each year. The report due on April 1 shall cover the six-month period ending on the last day of February before the report is due. The report due on October 1 shall cover the six-month period ending on the last day of August 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 condition IV.E.l below. "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 (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: (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; (c) A situation in which observations or data collected demonstrates noncompliance with an emission limitation or standard or any work practice or operating condition required by the permit; or (d) A situation in which an exceedance or an excursion, as defined in 40 CFR Part 64 occurs. No deviations were reported since the previous inspection. 2) Deviation reports. The permittee shall promptly report to the EPA Regional Office any 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 timeframe for reporting deviations provided in an underlying applicable requirement as identified in this permit; or (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 hazardous air pollutant or a toxic air pollutant (as identified in the applicable regulation) that continue for more than an hour in excess of permit 66 requirements, the report shall be made within 24 hours of the occurrence; (ii) For emissions of any regulated air pollutant, excluding a hazardous air pollutant or a toxic air pollutant that continue for more than two hours in excess of permit requirements, the report shall be made within 48 hours; (iii) For all other deviations from permit requirements, the report shall be submitted with the semi-annual monitoring report required in paragraph III.C.1 above. No deviations were reported since the previous inspection. D. Compliance Schedule and Progress Reports [40 CFR 71.6(c)(3) and (4); 71.5(c)(8)(iii)] For applicable requirements with which the permittee is in compliance, the permittee shall continue to comply with such requirements. For applicable requirements that will become effective during the permit term, the permittee shall meet such requirements on a timely basis. No new applicable requirements have become effective as of the date of this inspection report. E. Permit Shield [40 CFR 71.6(f)] 1) Nothing in this permit shall alter or affect the following: (a) The liability of the permittee for any violation of applicable requirements, prior to or at the time of permit issuance; (b) The applicable requirements of the Acid Rain Program, consistent with section 408(a) of the Clean Air Act; (c) The ability of the EPA to obtain information under Section 114 of the Clean Air Act; or (d) The provisions of Section 303 of the Clean Air Act (emergency orders), including the authority of the Administrator under that section. There is nothing to evaluate with this condition. 2) Compliance with the conditions of this permit shall be deemed compliance with any applicable requirements in effect as of the date of permit issuance, provided that: (a) Such requirements are included and are specifically identified in the permit; or 67 (b) Those requirements not applicable to the source are specifically identified and listed in the permit, including the determination of non-applicability or a concise summary thereof. There is nothing to evaluate with this condition. F. Emissions Trading and Operational Flexibility [40 CFR 71.6(a)(13)(i) through (iii), 71.6(a)(8) and 71.6(a)(10)] 1) The permittee is allowed to make a limited class of changes under Section 502(b)(10) of the CAA within this permitted facility that contravene the specific terms of this permit without applying for a permit revision, provided the changes do not exceed the emissions allowable under this permit (whether expressed therein as a rate of emissions or in terms of total emissions) and are not Title I modifications. This class of changes does not include: (a) Changes that would violate applicable requirements; or (b) Changes that would contravene federally enforceable permit terms and conditions that are monitoring (including test methods), recordkeeping, reporting, or compliance certification requirements. [40 CFR 71.6(a)(13)(i)] There have been no modifications to the facility. As such, this condition is not currently applicable. 2) The permittee is required to send a notice to EPA at least 7 days in advance of any change made under this provision. The notice shall describe the change, when it will occur, any change in emissions, and identify any permit terms or conditions made inapplicable as a result of the change. The permittee shall attach each notice to its copy of this permit. [40 CFR 71.6(a)(13)(i)(A)] There have been no modifications to the facility. As such, this condition is not currently applicable. 3) Any permit shield provided in this permit does not apply to changes made under this provision. [40 CFR 71.6(a)(l3)(i)(B)] There is nothing to evaluate with this condition. 4) No permit revision shall be required, under any approved economic incentives, marketable permits, emissions trading and other similar programs or processes, for changes that are provided for in this permit. [40 CFR 71.6(a)(8)] There is nothing to evaluate with this condition. 68 G. Stratospheric Ozone and Climate Protection [40 CFR Part 82] 1) Subpart F - Recycling and Emissions Reduction. The permittee shall comply with applicable standards for recycling and emissions reduction pursuant to 40 CFR Part 82, Subpart F, except as provided for motor vehicle air conditioners (MVACs) in Part 82, Subpart B. The requirements below apply to any air conditioning appliances at Bonanza plant ("appliance" as defined in 40 CFR 82.152) that contain Class I or Class II refrigerants, in an amount less than 50 pounds: (a) Persons opening appliances for maintenance, service, repair, or disposal shall comply with the applicable required practices pursuant to 40 CFR 82.156; (b) Equipment used during the maintenance, service, repair, or disposal of appliances shall comply with the applicable standards for recycling and recovery equipment pursuant to 40 CFR 82.158; (c) Persons performing maintenance, service, repair, or disposal of appliances shall be certified by an approved technician certification program pursuant to 40 CFR 82.161; and. (d) Persons disposing of small appliances, MV ACs, and MV AC-like appliances (as defined in 40 CFR 82.152) shall comply with recordkeeping requirements pursuant to 40 CFR 82.166(i). ("MV AC-like appliance" as defined at 40 CFR 82.152) These conditions were not evaluated during this inspection. 2) Subpart H - Halon Emissions Reduction. The permittee shall comply with the following requirements from 40 CFR Part 82, Subpart F, applicable to any fire protection equipment at Bonanza plant containing Halon 1211, 1301, 2402, any isomers of these chemicals, or any blend of these chemicals: (a) Persons testing, maintaining, servicing, repairing, or disposing of halon-containing equipment or using such equipment for technician training must comply with the requirements of 40 CFR 82.270(b ); [40 CFR 82.270(b)] (b) Organizations that employ technicians who test, maintain, service, repair or dispose of halon-containing equipment must comply with the requirements of 40 CFR 82.270( c); and [40 CFR 82.270(c)] (c) Persons who dispose of halon-containing equipment must comply with the requirements of 40 CFR 82.270(d). [40 CFR 82.270(d)] These conditions were not evaluated during this inspection. 69 H. Acid Rain Program Requirements from Part 71 [40 CFR 71.6(a)(4) and 71.7(e)] 1) Emissions exceeding any allowances that the source lawfully holds under 40 CFR Parts 72 through 78 are prohibited. [40 CFR 71.6(a)(4)] To our knowledge there have been no allowance exceeding emissions. 2) No permit revision shall be required for increases in emissions that are authorized by allowances acquired pursuant to the Acid Rain Program, provided that such increases do not require a permit revision under any other applicable requirement. [40 CFR 71.6(a)(4)(i)] There have been no increases in emissions that require a permit revision. 3) No limit shall be placed on the number of allowances held by the source. The source may not, however, use allowances as a defense to noncompliance with any other applicable requirement. [40 CFR 71.6(a)(4)(ii)] There is nothing to evaluate with this condition. 4) Any allowances shall be accounted for according to the procedures established in regulations 40 CFR Parts 72 through 78. [40 CFR 71.6(a)(4)(iii)] This condition was not evaluated during this inspection. 5) A permit modification for purposes of the Acid Rain portion (section II.A.7) of this permit shall be governed by 40 CFR Part 72. [40 CFR 71.7(e)] There have been no modifications to this permit. IV. General Provisions 1) Annual Fee Payment (Title V permit p.83) 2021 annual fee - $267,542.34 2022 annual fee - $309,764.40 Deseret was found to be in compliance with this condition. 2) Annual Emissions Inventory (Title V permit p.85) NOx (tons) SO2 (tons) PM10 (tons) 2021 3749.6 849.2 126.0 2022 4584.4 959.3 117.8 Deseret was found to be in compliance with this condition. 70 3) Compliance Requirements (Title V permit p.86) This inspection report evaluates compliance with this requirement. 4) Duty to Provide and Supplement Information (Title V permit p. 87) Deseret provided the EPA with all requested information within a reasonable time. 5) Submissions (Title V permit p.88) All submissions included a "CTAC", certifying truth, accuracy and completeness. 6) Severability Clause (Title V permit p. 88) This condition has no requirements. 7) Permit Actions (Title V permit p. 88) This condition has no requirements. 8) Administrative Permit Amendments (Title V permit p. 89) The last administrative permit amendment requested by Deseret was on 9/23/2016. 9) Minor Permit Modifications (Title V permit p.89) No minor permit amendments have been requested. 10) Significant Permit Modifications (Title V permit p. 91) No significant permit amendments have been requested. 11) Reopening for Cause (Title V permit p.91) This condition has no requirements. 12) Property Rights (Title V permit p.92) This condition has no requirements. 13) Inspection and Entry (Title V permit p.92) 71 There were no issues with access to the Deseret power plant. 14) Emergency Provisions (Title V permit p.92) This condition was not evaluated during this inspection. 15) Transfer of Ownership or Operation (Title V permit p.93) There was no transfer of ownership since the previous inspection. 16) Off Permit Changes (Title V permit p. 93) This condition was not evaluated during this inspection. 17) Permit Expiration and Renewal (Title V permit p.94) This permit has not expired. 72 Minor NSR Permit Requirements (MNSR-U0-000004-2015.004) C. Nitrogen Oxide (NOx) Control Requirements and Emissions Limits 1. The Permittee shall install and operate low NOx burners with over-fire air (LNB/OFA) at the Plant no later than June 30, 2016, if the EPA Region 8 issues a final MNSR permit for the Plant on or before December 31, 2015, or no later than June 30, 2018, if the EPA Region 8 issues a final MNSR permit for the Plant on or after January 1, 2016. The final MNSR permit was issued after Decmeber 31, 2015. As such Deseret must install the Low NOx Burners before June 30th 2018. The facility installed the low NOx burners on during a plant shutdown in September 2016. In compliance. 2. Beginning no later than 425 boiler operating days after installation of LNB/OF A, Bonanza Unit 1 shall not discharge into the atmosphere NOx in excess of 0.28 pounds per million British thermal units (lbs/MMBtu) heat input, based on a 365 boiler operating day rolling average. A "boiler operating day" means a 24-hour period between midnight and the following midnight during which any fuel is combusted at any time in the steam generating unit, as defined by 40 CFR Part 60 Subpart Da. Compliance shall be monitored as laid out in condition I.E.3 of this permit. A new 365 boiler operating day rolling average emission rate shall be calculated for each new boiler operating day. The NOx emission limit of 0.28 lb/MMbtu became effective on 11/21/2017. Based on a review of 365-day rolling average NOx data provided by Deseret, the site has emitted less than 0.28 lb/MMBtu from September 2021 through February 2023. 3. Total NOx emissions from the Plant shall not exceed 5,700 tons per year on a rolling 12 calendar month basis (the "Base Limit"), to begin in the third calendar month that permitted operations of LNB/OFA commence. The Permittee shall provide written notification to EPA Region 8 of the date that operation of the LNB/OFA commences. Compliance shall be monitored as laid out in condition I.E.4 of this permit. A new 12-month emission total shall be calculated at the end of each calendar month. Deseret submits semiannual SIXMON reports, and the reports from September 2021 through February 2023 have included 12-month rolling NOx emissions summaries, in compliance with the 5,700 ton annual limit. 4. For the period from January 1, 2030, until the permanent cessation of operations to generate electricity at Bonanza Unit 1 (the "End of Service"), total NOx emissions from the Plant shall not exceed 3,000 tons per year on a rolling 12 calendar month basis. Compliance shall be monitored as laid out in condition 73 I.E.4 of this permit. A new 12- month emission total shall be calculated at the end of each calendar month. In 2030 compliance with this condition will be determined. 5. In determining NOx emissions under condition I.C of this permit, from the period beginning no later than 60 boiler operating days after installation of the LNB/OF A until the End of Service, the Permittee shall use data from the continuous emission monitoring system (CEMS) as defined in 40 CFR 72.2 and installed and operated in accordance with 40 CFR Part 75, and shall include all periods of startup, shutdown, and malfunction. The NOx data need not be bias adjusted and the missing data substitution procedures of 40 CFR Part 75 shall not apply to such determinations. Diluent capping (i.e., 5% carbon dioxide (C02)) may be applied to the NOx emission rate for any hours where the measured C02 concentration is less than 5%, following the procedures in 40 CFR Part 75, Appendix F, Section 3.3.4.1. The facility currently operates a CEMS to monitor NOx and calculate the 12month rolling NOx emissions. D. Coal Consumption Cap 1. Subject to the provisions of condition I.D.3 of this permit, for the period from January 1, 2020 through End of Service of Unit 1, coal consumption at the Plant shall not exceed 20,000,000 short tons of coal. 2. Coal consumption under this condition I.D shall be determined by weight avoirdupois, regardless of coal source or quality. Quantity of coal consumed will be measured by the Unit 1 coal pulverizer feeder belt scales and calculated monthly. Reports of accumulated coal consumption shall be submitted as required by condition I.H.3. The pulverizer feeder belt scales shall be calibrated per manufacturer's calibration procedures no less than twice per calendar year and in at least two (2) different calendar quarters during the year. A pulverizer feeder belt scale calibration shall also be conducted when a pulverizer feeder belt is replaced. A copy of the calibration procedure and, for each calibration, a record of the pulverizer number, calibration data and reason for calibration shall be kept on site. A copy of any revision to the manufacturer's calibration procedures and a record of the dates of each completed calibration shall be provided by the Permittee with its annual compliance certification required by 40 CFR 71.6(c)(5). 3. Contingent Releases from Coal Consumption Cap (a) The coal consumption cap in condition I.D.1 of this permit shall not apply after the date that any of the following events occur: 74 (i) The Permittee applies for and receives approval to construct from the EPA (to the extent required), and installs and operates Selective Catalytic Reduction (SCR) for NOx control at Unit 1 prior to December 31, 2029, and Unit 1 achieves and continuously complies with a NOx emission limit of 0.05 lb/MMBtu on a 12month rolling average, measured with CEMS (with permit terms that establish monitoring, recordkeeping and reporting requirements specific to the SCR system) as defined and required in condition l.C.5 of this permit, beginning no later than 180 days after the SCR installation is complete; or (ii) Due to petitions or other actions commenced by unaffiliated third parties or governmental authorities (including the EPA), and without the Permittee's consent, the Permittee is required to and does install and operate an SCR at Unit 1 prior to December 31, 2030, and achieves and continuously complies with a NOx emission limit of 0.05 lb/MMBtu on a 12-mortth rolling average, measured with CEMS (with permit terms that establish monitoring, recordkeeping and reporting requirements specific to the SCR system) as defined and required in condition I.C.5 of this permit, beginning no later than 180 days after the SCR installation is complete. (b) As required by the proposed settlement agreement, the Permittee shall notify the Sierra Club and Wild Earth Guardians of its decision to install and operate an SCR at Unit 1 at least 24 months in advance of its intended date for commencing SCR operation, and shall apply to the EPA for a revision to this permit at least 12 months in advance of its intended date for commencing construction, and shall receive a revision to this permit before commencing construction of SCR, to incorporate requirements for SCR. (c) If the Permittee does not notify Sierra Club and Wild Earth Guardians of its choice to install SCR prior to December 31, 2027 (in the event of voluntary SCR installation under condition I.D.3.(a)(i) of this permit), or prior to December 31, 2028 (in the event of SCR installation under condition I.D.3.(a)(ii) of this permit), then the release in condition I.D.3.(a) of this permit shall not apply and the coal consumption cap in condition I.D.1 of this permit will continue in effect until the End of Service of Unit 1. Deseret has been including coal consumption since January 1, 2020 in each semi-annual report since April 2020. As of February 2023, the facility's coal consumption is 5.363 million tons. 75 E. Monitoring Requirements [40 CFR 49.155(a)(3)] 1. CEMS Required. At all times after the effective date of this permit, a NOx CEMS in the Unit 1 Main Stack, as defined in 40 CPR 72.2, shall be maintained, calibrated, and operated in full compliance with the requirements found at 40 CFR Part 75, to accurately measure NOx, diluent, and stack gas volumetric flow rate. The CEMS shall be used to determine compliance with the NOx emission limitations in this permit. A NOx CEMS is currently operational at the facility and is maintained according to 40 CFR Part 75. 2. CEMS Operation. The Permittee shall maintain and operate the CEMS consistent with requirements at 40 CFR Part 75 including, but not limited to, the following: (a) For any hour in which fuel is combusted in Unit 1, the hourly average NOx concentration in lb/MMBtu at the CEMS shall be calculated, in accordance with the requirements of 40 CFR Part 75. (b) An hourly average NOx emission rate in lb/MMBtu is valid only if the minimum number of data points, as specified in 40 CFR Part 75, is acquired by both the NOx pollutant concentration monitor and the diluent monitor (oxygen (02)) or carbon dioxide (C02). (c) Data reported to meet the requirements of this section shall not include data substituted using the missing data substitution procedures of Subpart D of 40 CFR Part 75, nor shall the data have been bias adjusted according to the procedures of 40 CFR Part 75. A NOx CEMS is currently operational at the facility and is maintained according to 40 CFR Part 75. 3. Monitoring compliance with NOx emission limit in lb/MMBtu on a 365 boiler operating day rolling average. At the end of each boiler operating day, a new 365 boiler operating day rolling average emission rate in lb/MMBtu for NOx shall be calculated and recorded, as follows: (a) Sum the pounds of NOx emitted from Unit 1 during the most recent boiler operating day and the previous 364 boiler operating days, based on NOx CEMS data; (b) Sum the total heat input to Unit 1 in MMBtu during the most recent boiler operating day and the previous 364 boiler operating days, using data from the Unit 1 heat input monitoring system; and 76 (c) Divide the total number of pounds of NOx emitted during the 365 boiler operating days by the total heat input during the 365 boiler operating days. Periods of boiler operation during startup, shutdown and malfunction shall be included in the calculation of average emission rates. No periods of boiler operation may be excluded. Based on Deseret's 12-month rolling NOx emissions data, the site appears to be in compliance with the requirements above. 4. Monitoring compliance with NOx emission limits in tons on a rolling 12-month basis. At the end of each calendar month, a new 12-month total for NOx emissions shall be calculated and recorded, as follows: (a) Sum the pounds of NOx emitted from Unit 1 for the calendar month, based on NOx CEMS data; (b) Add the sum to the pounds of NOx emitted from Unit 1 for the previous 11 calendar months and convert the result to tons. Periods of boiler operation during startup, shutdown and malfunction shall be included in the calculation of tons of emissions. No periods of boiler operation may be excluded. For monitoring continuous compliance with the NOx emission limit of 5,700 tons per rolling 12-month period, the first compliance calculation shall be recorded no later than fifteen calendar months after permitted operation of LNB/OFA commences, and shall cover the 12-month period beginning three months after permitted operation of LNB/OFA commences. For monitoring continuous compliance with the NOx emission limit of 3,000 tons per rolling 12-month period, which takes effect beginning in the year 2030, the first compliance calculation shall be recorded no later than the end of December 2030, and shall cover the 12-month period beginning January 1, 2030. Deseret submits semiannual SIXMON reports, and the reports from September 2021 until February 2023 have included 12-month rolling NOx emissions summaries, in compliance with the 5,700 ton annual limit. F. Recordkeeping Requirements [40 CFR 49.155(a)(4)(i)] The Permittee shall keep the following records: 1. All NOx CEMS data, including all rolling 365 boiler operating day NOx emissions in lb/MMBtu, all rolling 12-month NOx emissions in tons, and all information used to calculate these values. 77 2. All coal consumption data and associated weight measurements at the coal pulverizer feeder belt scales used to demonstrate compliance with this permit, to include records of any calibration of the weighing device and the calibration procedure. 3. Records of quality assurance and quality control activities for the NOx CEMS, including, but not limited to, any records required by 40 CFR Part 75. 4. Records of all major maintenance activities conducted on the air pollution control equipment and NOx CEMS covered by this permit. 5. Any other NOx CEMS records required by 40 CFR Part 75. 6. All specifications and maintenance requirements developed by the manufacturer, vendor, or Permittee for each emission control and monitoring device required in this permit, including any updates to such requirements. 7. All calibration, maintenance, repairs, rebuilds or replacements conducted for each emission control device and monitoring device required in this permit. 8. The results of all required performance testing and monitoring in this permit. The records shall include the following: (a) The date, place, and time of sampling or measurements; (b) The date(s) analyses were performed; (c) The company or entity that performed the analyses; (d) The analytical techniques or methods used; (e) The results of such analyses or measurements; and (f) The operating conditions as existing at the time of sampling or measurement. 9. All deviations of permit requirements, a description of the probable cause of the deviation, and any corrective actions or preventative measures taken. The facility has provided all requested documentation. Appears to be in compliance. G. Records Retention Requirements [40 CFR 49.155(a)(4)(ii)] 78 1. The Permittee shall retain all records required by this 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-to-day operational control over the facility, or the location that has day-to-day responsibility for compliance of the facility. The facility has provided all requested documentation. Appears to be in compliance. H. Reporting Requirements [40 CFR 49.155(a)(5)] 1. Emission compliance reports (a) Reporting compliance with NOx emission limit in lb/MMBtu on a 365 boiler operating day rolling average: Beginning no later than 425 boiler operating days after installation of LNB/OF A, the Permittee shall submit written reports by April 1 and October 1 of each year, demonstrating compliance with the NOx emission limit in condition I.C.2. The reports shall include the 365 boiler operating day rolling average NOx emissions in lb/MMBtu for each boiler operating day in the reporting period. (b) Reporting compliance with NOx emission limits in tons on a rolling 12month basis: (i) Beginning fifteen calendar months after permitted operation of LNB/OFA commences, the Permittee shall submit written reports by April 1 and October 1 of each year, demonstrating compliance with the NOx emission limit in condition I.C.3, to include the rolling 12-month total NOx emissions at the end of each month in the reporting period. (ii) Beginning no later than January 1, 2031, the Permittee shall submit written reports by April I and October I of each year, demonstrating compliance with the NOx emission limit in condition I.C.4, to include the rolling 12-month total NOx emissions at the end of each month in the reporting period. The reports due on April I shall cover the six-month period ending on the last day of February before the report is due. The reports due on October 1 shall cover the six-month period ending on the last day of August before the report is due. In addition to the information required above, all reports shall identify any period during which emissions exceeded the emission limits in this permit, the cause(s) for the excess 79 emissions (if known), and the corrective action taken or preventative measures adopted to eliminate the exceedance. Deseret submits semiannual SIXMON reports. The reports since September 2021 have included 12-month rolling NOx emissions summaries in compliance with the 5,700 ton annual limit. 2. CEMS performance reports The permittee is required to submit reports of CEMS performance under 40 CFR Part 75. [Note to Permittee: Reports which satisfy the requirements of this regulation that are submitted under the terms of the facility's Clean Air Act "Air Pollution Control Permit to Operate" (Permit Number V-U0-000004-00.01), shall be considered satisfactory for purposes of this permit.] 3. Coal Consumption Reports Beginning in the year 2020 until the End of Service of Unit 1, semiannually by April 1 and October 1 of each year, the Permittee shall submit written reports of accumulated coal consumption in short tons since January 1, 2020 for Unit 1, as measured by Unit 1 coal pulverizer feeder belt scales. The report due on April 1 shall provide the accumulated coal consumption in short tons from January 1, 2020, until the last day of February before the report is due. The report due on October 1 shall provide the accumulated coal consumption in short tons from January 1, 2020, until the last day of August before the report is due. This reporting requirement becomes effective in 2020. 4. Report submissions All reports described in conditions I.H.1, I.H.2 and I.H.3 of this permit shall be certified to truth and accuracy by the person primarily responsible for Clean Air Act compliance for the Permittee, and 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 Reports may be submitted electronically to r8airreportenforcement@epa.gov. There is nothing to evaluate with this general condition. 5. Deviation Reports 80 The Permittee shall promptly submit to the EPA a written report of any deviations of permit requirements, a description of the probable cause of such deviations, and any corrective actions or preventative measures taken. A "prompt" deviation report is one that is postmarked or submitted via electronic mail to r8airreportenforcement@epa.gov as follows: (a) Within 30 days from the discovery of any deviation of the emission limits or operational limits that are left uncorrected for more than 24 hours 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. 6. Reports Upon EPA Request The Permittee shall submit any record or report required by this permit upon EPA request. The facility provided all requested reports. II. General Provisions A. Conditional Approval: Pursuant to the authority of 40 CFR 49 .151, the EPA hereby conditionally grants this permit. This authorization is expressly conditioned as follows: 1. Document Retention and Availability: This permit and any required attachments shall be retained and made available for inspection upon request at the location set forth herein. 2. Permit Application: The Permittee shall abide by all representations, statements of intent and agreements contained in the application submitted by the Permittee. The EPA shall be notified 10 days in advance of any significant deviation from this permit application as well as any plans, specifications, or supporting data furnished. 3. Permit Deviations: The issuance of this permit may be suspended or revoked if the EPA determines that a significant deviation from the permit application, specifications, and supporting data furnished has been or is to be made. If the proposed source is constructed, operated, or modified not in accordance with the terms of this permit, the Permittee will be subject to appropriate enforcement action. 81 4. Compliance with Permit: The Permittee shall comply with all conditions of this permit, including emission limitations that apply to the affected emissions units at the permitted facility/source. Noncompliance with any permit term or condition is a violation of this permit and may constitute a violation of the CAA and is grounds for enforcement action and for a permit termination or revocation. 5. Fugitive Emissions: The Permittee shall take all reasonable precautions to prevent and/or minimize fugitive emissions during the construction period. 6. National Ambient Air Quality Standards and PSD Increments: The permitted source shall not cause or contribute to a NAAQS violation or a PSD increment violation. 7. Compliance with Federal and Tribal Rules, Regulations, and Orders: Issuance of this permit does not relieve the Permittee of the responsibility to comply fully with all other applicable federal and tribal rules, regulations, and orders now or hereafter in effect. 8. Enforcement: It is not a defense, for the Permittee, in an enforcement action, to claim that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit. 9. Modifications to Existing Permitted Emissions Units/Limits: For proposed modifications, as defined at 40 CFR 49 .152( d), that would increase an emissions unit's allowable emissions of pollutants above its existing permitted annual allowable emissions limit, the Permittee shall first obtain a permit modification pursuant to the MNSR regulations approving the increase. For a proposed modification that is not otherwise subject to review under the PSD or MNSR regulations, such proposed increase in the annual allowable emissions limit shall be approved through an administrative permit revision as provided at 40 CFR 49.159(f). 10. Relaxation of Legally and Practically Enforceable Limits: At such time that a new or modified source within this permitted facility/source or modification of this permitted facility/source becomes a major stationary source or major modification solely by virtue of a relaxation in any legally and practically enforceable limitation which was established after August 7, 1980, on the capacity of the permitted facility/source to otherwise emit a pollutant, such as a restriction on hours of operation, then the requirements of the PSD regulations shall apply to the source or modification as though construction had not yet commenced on the source or modification. 11. Revise, Reopen, Revoke and Reissue, or Terminate for Cause: This permit may be revised, reopened, revoked and reissued, or terminated for cause. The filing of a request by the Permittee, for a permit revision, revocation and reissuance or termination or of a notification of planned changes or anticipated noncompliance 82 does not stay any permit condition. The EPA may reopen this permit for a cause on its own initiative, e.g., if this permit contains a material mistake or the Permittee fails to assure compliance with the applicable requirements. 12. Severability Clause: The provisions of this permit are severable, and in the event of any challenge to any portion of this permit, or if any portion is held invalid, the remaining permit conditions shall remain valid and in force. 13. Property Rights: This permit does not convey any property rights of any sort or any exclusive privilege. 14. Information Requests: The Permittee shall furnish to the EPA, within a reasonable time, any information that the EPA may request in writing to determine whether cause exists for revising, revoking and reissuing, or terminating this permit or to determine compliance with this permit. For any such information claimed to be confidential, the Permittee shall also submit a claim of confidentiality in accordance with 40 CFR Part 2, Subpart B. 15. Inspection and Entry: The EPA or its authorized representatives may inspect this permitted facility/source during normal business hours for the purpose of ascertaining compliance with all conditions of this permit. Upon presentation of proper credentials, the Permittee shall allow the EPA or its authorized representative to: (a) Enter upon the premises where this permitted facility/source is located or emissions-related activity is conducted, or where records are required to be kept under the conditions of this permit; (b) Have access to and copy, at reasonable times, any records that are required to be kept under the conditions of this permit; (c) Inspect, during normal business hours or while this permitted facility/source is in operation, any facilities, equipment (including monitoring and air pollution control equipment), practices, or operations regulated or required under this permit; (d) Sample or monitor, at reasonable times, substances or parameters for the purpose of assuring compliance with this permit or other applicable requirements; and (e) Record any inspection by use of written, electronic, magnetic and photographic media. 16. Permit Effective Date: This permit is effective immediately upon issuance unless comments resulted in a change in the proposed permit, in which case the permit is effective 30 days after issuance. The Permittee may notify the EPA, in writing, 83 that this permit or a term or condition of it is rejected. Such notice should be made within 30 days of receipt of this permit and should include the reason or reasons for rejection. 17. Permit Transfers: Permit transfers shall be made in accordance with 40 CFR 49.l59(f). The Air Program Director shall be notified in writing at the address shown below if the company is sold or changes its name. U.S. Environmental Protection Agency, Region 8 Office of Partnerships and Regulatory Assistance Tribal Air Permitting Program, 8P-AR 1595 Wynkoop Street Denver, Colorado 80202 18. Invalidation of Permit: Unless this permitted source of emissions is an existing source, this permit becomes invalid if construction is not commenced within 18 months after the effective date of this permit, construction is discontinued for 18 months or more, or construction is not completed within a reasonable time. The EPA may extend the 18-month period upon a satisfactory showing that an extension is justified. This provision does not apply to the time period between the construction of the approved phases of a phased construction project. The Permittee shall commence construction of each such phase within 18 months of the projected and approved commencement date. 19. Notification of Startup: The Permittee shall submit a notification of the anticipated date of initial startup of this permitted source to the EPA within 60 days of such date, unless this permitted source of emissions is an existing source. The facility appears to be in compliance with the requirements above. 84 Appendix A: Satellite Imagery of Facility 85