# Environmental Programs Division (2022) > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/tribal%3Asouthern_ute%3A8e7a373f26ede830 ## Record - **Collection:** Tribal code - **Document type:** Tribal code ## Text AIR QUALITY PROGRAM Environmental Programs Division Southern Ute Indian Tribe PO Box 737 MS#84 Ignacio, CO 81137 Phone 970-563-4705 http://www.southernute-nsn.gov/environmental-programs/air-quality February 1, 2023 Mr. Oakley Hayes Environmental Specialist Harvest Midstream Company PO Box 61229 Houston, TX 77208 Re: Final Part 70 Operating Permit Title V Permit #V-SUIT-0027-2022.00 Harvest Four Corners LLC Ignacio Gas Plant Dear Mr. Hayes: The Southern Ute Indian Tribe Air Quality Program (Tribe) has completed its review of Harvest Four Corner’s LLC request to renew a Title V Permit to Operate pursuant to the Title V Operating Permit Program at 40 CFR Part 70, for the Ignacio Gas Plant. Based on the information submitted in the company’s application, and the comments received during the public comment period, the Tribe hereby issues the enclosed Title V Permit to Operate. The final permit will become effective on February 01, 2023. A 30-day public comment period was held from September 23, 2022 to October 23, 2022. The Tribe received comments from Harvest Four Corners, LLC and no comments were received from the public, affected states, or tribes. Following the 30-day public comment period, the AQP made the following changes: 1.) Section III.1.2.4.3.1.-Incorporated missing citations. 2.) Section III.1.7.2.4.1.-Added a provision to align reporting dates with SIXMON reporting dates. For a more detailed discussion of these comments and the resultant changes, please review the Response to Comments document attached to this permit. The AQP made additional revisions that the AQP became aware of through unofficial comments. The revisions were typographical and formatting errors. A 45-day Administrative Review period at EPA Region 8 was held from December 15, 2022 to January 29, 0223. No comments were received from EPA Region 8 during this review period. Pursuant to RAC § 2-109(8), within 60 days after the final permit has been issued, the applicant, any person who participated in the public comment process and is aggrieved by the action, and any other person who could obtain judicial review of that action under applicable law, may appeal to the Environmental Commission in accordance with the Southern Ute Indian Tribe/State of Colorado Environmental Commission’s Reservation Air Code (RAC) and the Commission’s Procedural Rules. Additionally, the regulations at RAC § 2-109(7) specify that any person may petition the EPA Administrator within 60 days after the expiration of the Administrator’s 45-day review period to make an objection that the permit would not be in compliance with applicable requirements. Any such petition must be based only on objections to the permit that were raised with reasonable specificity during the public comment period unless the petitioner demonstrates that it was impracticable to raise such objections within such period, or unless the grounds for such objections arose after such period. If you have any questions concerning the enclosed permit, please contact Jacob Stokes at 970-563-2229. Sincerely, Jacob Stokes Air Quality Scientist Southern Ute Indian Tribe Cc: Patrick Wauters – Air Permitting Modeling and Monitoring Unit – US EPA Region 8 AIR QUALITY PROGRAM ENVIRONMENTAL PROGRAMS DIVISION THE SOUTHERN UTE INDIAN TRIBE PO BOX 737, MS 84, IGNACIO, CO 81137 (970) 563 – 4705 ∙ (970) 563 – 0384 FAX 12/15/2022 Response to Comments Document Operator: Harvest Four Corners LLC Facility: Ignacio Gas Plant Permit Action: Title V Operating Permit Renewal Comments from Harvest Four Corners LLC received on Draft Title V Operating Permit V-SUIT-0027-2022.00 A. Comment: Harvests requests that the AQP add in the language from 60.635(b)(1) and (2) after provision III.1.2.4.3 on page 28 of the draft permit. AQP’s Response: The requested change has been made. The draft permit has been revised and reads as follows: III.1.2.4.3.1. When each leak is detected as specified in § 60.633(b)(2) of this subpart, a weatherproof and readily visible identification, marked with the equipment identification number, shall be attached to the leaking equipment. The identification on the pressure relief device may be removed after it has been repaired. III.1.2.4.3.2. When each leak is detected as specified in § 60.633(b)(2) of this subpart, the following information shall be recorded in a log and shall be kept for 2 years in a readily accessible location: [40 CFR 60.635(b)(1) and (2)] B. Comment: For the reporting provision at III.1.5.2.4, Harvest requests to align the specified reporting dates with the AQP’s SIXMON reporting dates of April 1 and October 1. AQP’s Response: The requested change has been made. The draft permit has been revised and reads as follows (A citation numbering error was also corrected): III.1.7.2.4.1. The permittee shall submit to the Tribe all reports of any required monitoring under this permit semiannually, by April 1 and October 1 of each year. The report due on April 1 shall cover the July 1 - December 31 reporting period of the previous calendar year. The report due on October 1 shall cover the January 1 - June 30 reporting period of the current calendar year. All instances of deviations from permit requirements shall be clearly identified in such reports. All required reports shall be certified by a responsible official consistent with the Submissions section of this permit. [RAC 2-110(7)(a)] Southern Ute Indian Tribe Air Quality Program Title V Operating Permit Southern Ute Indian Tribe Environmental Programs Division Air Quality Program 71 Mike Frost Way Ignacio, Colorado 81137 AIR POLLUTION CONTROL TITLE V PERMIT TO OPERATE In accordance with the provisions of Title V of the Clean Air Act (42 U.S.C. 7661-7661f) and Part 1, Article II of the Southern Ute Indian Tribe/State of Colorado Environmental Commission’s Reservation Air Code (RAC) and applicable rules and regulations, Harvest Four Corners, LLC Ignacio Gas Plant is authorized to operate air emission units and to conduct other air pollutant emitting activities in accordance with the conditions listed in this permit. This source is authorized to operate at the following location: Southern Ute Indian Reservation SE ¼ of Section 35 SW ¼ of Section 36, T34N R9W La Plata County, Colorado Terms not otherwise defined in this permit have the meaning assigned to them in the referenced regulations. All terms and conditions of the permit are enforceable by the Tribe and citizens under the Clean Air Act. Daniel Powers, Air Quality Program Manager Environmental Programs Division Southern Ute Indian Tribe AIR POLLUTION CONTROL TITLE V PERMIT TO OPERATE Harvest Four Corners, LLC Ignacio Gas Plant SUIT Account Identification Code: 2-036 Permit Number: V-SUIT-0027-2022.00 [Replaces Permit No.: V-SUIT-0027-2017.03] Issue Date: Effective Date: Expiration Date: February 1, 2023 February 1, 2023 February 1, 2028 The SUIT account identification code and permit number cited above should be referenced in future correspondence regarding this facility. Permit Issuance History DATE TYPE OF ACTION DESCRIPTION OF ACTION PERMIT NUMBER November 19, 2003 Initial Permit Issued # V-SU-0027-00.00 January 28, 2013 1st Renewal Permit Issued # V-SU-000027-2008.00 June 5, 2017 Initial Part 70 Permit issued # V-SUIT-0027-2017.00 December 7, 2018 Permit Revision November 23, 2020 Permit Revision November 15, 2021 Permit Revision February 1, 2023 Permit Renewal Administrative Revision • Change of Ownership from Williams Four Corners, LLC to Harvest Four Corners, LLC. • Updated Air Quality Program Manager • Updated Responsible Official Title Administrative Revision • Corrected emission unit IDs • Corrected Compliance Assurance Monitoring plan Significant Revision • Incorporation of emission units B001 and B002 • Reclassification from major source to area source of HAPs 1st Part 70 Renewal Permit Issued #V-SUIT-0027-2017.01 #V-SUIT-0027-2017.02 #V-SUIT-0027-2017.03 #V-SUIT-0027-2022.00 Table of Contents Abbreviations and Acronyms ................................................................................................................................ iii Section I – Source Information and Emission Unit Identification ............................................................................ 1 Source Information ..........................................................................................................................................1 The uncontrolled releases of VOC are minimized through the implementation of a Leak Detection and Repair (LDAR) program. .......................................................................................................................................................5 Source Emission Points ....................................................................................................................................5 Section II – General Requirements ......................................................................................................................... 9 Title V Administrative Requirements ...............................................................................................................9 1.1. Annual Fee Payment [RAC 2-110(1)(h) and RAC 2-118] ........................................................................9 1.2. Compliance Requirements ..................................................................................................................11 1.3. Duty to Provide and Supplement Information [RAC 2-110(7)(e), 2-106(5), and 2-124] ....................12 1.4. Submissions [RAC 2-105] .....................................................................................................................13 1.5. Severability Clause [RAC 1-106 and RAC 2-110(1)(f)] .........................................................................13 1.6. Permit Actions [RAC 2-110(3)] ............................................................................................................13 1.7. Administrative Permit Revision [RAC 2-111(2)] .................................................................................14 1.8. Minor Permit Revisions [RAC 2-111(3)] ..............................................................................................14 1.9. Significant Permit Revisions [RAC 2-111(4)] .......................................................................................15 1.10. Permit Reopenings, Revocations and Reissuances, and Terminations [RAC 2-112] .........................15 1.11. Property Rights [RAC 2-110(3)(e)] .......................................................................................................16 1.12. Inspection and Entry [RAC 2-110(9)(b)] ..............................................................................................16 1.13. Emergency Situations [RAC 2-117]......................................................................................................17 1.14. Permit Transfers [RAC 2-113] ..............................................................................................................17 1.15. Off-Permit Changes [RAC 2-116(2)].....................................................................................................18 1.16. Permit Expiration and Renewal ..........................................................................................................18 Facility-Wide Requirements...........................................................................................................................19 2.1. General Recordkeeping Requirements [RAC 2-110(6)] ......................................................................19 2.2. General Reporting Requirements .......................................................................................................20 2.3. Alternative Operating Scenarios [RAC 2-110(8)] ................................................................................21 2.4. Permit Shield [RAC 2-110(10)(c)].........................................................................................................23 2.5. Stratospheric Ozone and Climate Protection [40 CFR Part 82] ..........................................................23 Section III – Site Specific Permit Terms ................................................................................................................ 25 New Source Performance Standards (NSPS) and 40 CFR Part 60 ..................................................................25 1.1. 40 CFR Part 60, Subpart Kb – Standards of Performance for Volatile Organic Liquid Storage Vessels [40 CFR 60.110b-60.116b and RAC 3-102] .........................................................................................................25 1.2. 40 CFR Part 60, Subpart KKK – Standards of Performance for Equipment Leaks of VOC from Onshore Natural Gas Processing Plants [40 CFR 60.630 – 60.636, RAC 3-102] ................................................25 1.3. 40 CFR Part 60, Subpart LLL – Standards of Performance for SO2 Emissions from Onshore Natural Gas Processing Plants [40 CFR 60.640 – 60.648 and RAC 3-102] ......................................................................33 1.4. 40 CFR Part 60, Subpart KKKK – Standards of Performance for Stationary Combustion Turbines [40 CFR 60.4300 – 60.4420 and RAC 3-102] .............................................................................................................34 1.5. 40 CFR Part 60, Subpart OOOO – Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution [40 CFR 60.5360 – 60.5430 and RAC 3-102] ...............................36 1.6. 40 CFR Part 60, Subpart OOOOa – Standards of Performance for Crude Oil and Natural Gas Facilities [40 CFR 60.5360a – 60.5499a, RAC 3-102] .........................................................................................46 i 1.7 40 CFR Part 60, Subpart Dc – Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units [40 CFR 60.40c – 60.48c, RAC 3-102] .........................................................................55 2. National Emission Standards for Hazardous Air Pollutants (NESHAP) and 40 CFR Part 63 ...........................57 2.1. 40 CFR Part 63, Subpart HH – National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities [40 CFR 63.760 – 63.63.779 and RAC 4-103] ........................................57 2.2. 40 CFR Part 63, Subpart ZZZZ – National Emission Standards for Hazardous Air Pollutants from Reciprocating Internal Combustion Engines [40 CFR 63.6580 – 63.6675 & RAC 4-103] ..................................57 2.3. 40 CFR Part 63, Subpart CCCCCC – National Emission Standards for Hazardous Air Pollutants for Source Category: Gasoline Dispensing Facilities [40 CFR 63.11110 – 63.11132] .............................................61 3. Reserved – Tribal Minor New Source Review ................................................................................................63 4. Prevention of Significant Deterioration Requirements (PSD Permit #PSD-SU-00027-01.00) ........................63 4.1. Requirements for the 10,700 bhp Turbines (Unit 10 and Unit 11) ....................................................63 4.2. Requirements for the Amine Treatment System (Unit 17) ................................................................64 4.3. Requirements for the Turbo-Expansion Unit .....................................................................................66 4.4. Requirements for the West Dehydrator (Unit 15) .............................................................................67 4.5. Requirements for the East Dehydrator (Unit 16) ...............................................................................68 5. Reserved – Consent Decree Requirements ....................................................................................................70 6. Compliance Assurance Monitoring (CAM) Requirements .............................................................................70 6.1. 40 CFR Part 64 CAM.............................................................................................................................70 7. Enhanced Monitoring, Recordkeeping, and Reporting..................................................................................73 Section IV – Appendix .......................................................................................................................................... 74 1. Compliance Assurance Monitoring (CAM) Plan.............................................................................................74 Inspection Information ..................................................................................................................................90 2.1 Driving Directions: ...................................................................................................................................90 2.2 Global Positioning System (GPS): ............................................................................................................90 2.2 Safety Considerations: .............................................................................................................................90 ii Abbreviations and Acronyms 4SLB 4SRB AFS AQP bbl BACT CAA CAM CEMS CFR CMS COMS CO CO2 dscf dscm EPA gal GPM H 2S HAP hr ID kg lbs MACT Mg MMBtu MMSCFD mo NESHAP NMHC NOx NSPS NSR pH PM PM10 ppbvd ppm ppmvd PSD PTE psi psia RAC RICE RMP scf scfm SI SO2 SUIT THOx Four-Stroke Lean-Burn Four-Stroke Rich-Burn Air Facility System database Southern Ute Indian Tribe’s Air Quality Program Barrels Best Available Control Technology Clean Air Act [42 U.S.C. Section 7401 et seq.] Compliance Assurance Monitoring Continuous Emission Monitoring System Code of Federal Regulations Continuous Monitoring System (includes COMS, CEMS and diluent monitoring) Continuous Opacity Monitoring System Carbon monoxide Carbon dioxide Dry standard cubic foot Dry standard cubic meter United States Environmental Protection Agency Gallon Gallons per minute Hydrogen sulfide Hazardous Air Pollutant Hour Identification Number Kilogram Pounds Maximum Achievable Control Technology Megagram Million British Thermal Units Million standard cubic feet per day Month National Emission Standards for Hazardous Air Pollutants Non-methane hydrocarbons Nitrogen Oxides New Source Performance Standard New Source Review Negative logarithm of effective hydrogen ion concentration (acidity) Particulate Matter Particulate matter less than 10 microns in diameter Parts per billion by volume, dry Parts per million Parts per million by volume, dry Prevention of Significant Deterioration Potential to Emit Pounds per square inch Pounds per square inch absolute Southern Ute Indian Tribe/State of Colorado Environmental Commission’s Reservation Air Code Reciprocating Internal Combustion Engine Risk Management Plan Standard cubic feet Standard cubic feet per minute Spark Ignition Sulfur Dioxide Southern Ute Indian Tribe Callidus Thermal Oxidizer iii tpy Tribe US EPA VOC Ton(s) Per Year Southern Ute Indian Tribe United States Environmental Protection Agency Volatile Organic Compounds iv Table of Figures Table 1 - Emission Units................................................................................................................. 5 Table 2 - Insignificant Emission Units ........................................................................................... 7 v Section I – Source Information and Emission Unit Identification Source Information Owner Name: Facility Name: Facility Location: Latitude: Longitude: State: County: Responsible Official: SIC Code: ICIS Identification Number: EPA Facility Registry ID: Harvest Four Corners, LLC Ignacio Gas Plant SE ¼ of Section 35 SW ¼ of Section 36, T34N R9W 37.145278 °N 107.784444 °W Colorado La Plata EH & S Manager 1321 SU000000008067U0038 110009557470 Other Clean Air Act Permits: EPA issued the first PSD permit to the facility in 1984. PSD Permit #PSDSU-0027-01.00 was issued on December 22, 2010 to incorporate the requirements of the 1984 PSD permit and two Consent Decrees. There are no other CAA permits issued to this facility. Process Description: The Ignacio Gas Plant provides compression, dehydration, sweetening, and natural gas liquids (NGL) recovery for the San Juan Gathering Systems, an approximately 5,300 mile pipeline system gathering gas from the San Juan Basin. The San Juan Basin spans the southwest corner of Colorado and the northwest corner of New Mexico. The Ignacio Gas Plant has the ability to condition approximately 500 to 650 million standard cubic feet (MMscfd) of field gas per day into saleable NGL and residue gas. The primary plant operations include inlet compression, dehydration, carbon dioxide removal, NGL removal, fractionation, and storage. There are two primary incoming pipelines to the plant, Trunk S and Trunk C: • The 30” Trunk S line from the San Juan Basin area of primarily New Mexico brings hydrocarbon liquidrich gas for processing. In July 2011, the Four Corners Area Consolidation Project was approved for construction of a pipeline (S-87 lateral) from the Dogie Compressor Station to Trunk S. The Trunk S line now transfers what were historically Lybrook Gas Plant volumes to the Ignacio Gas Plant. A filter separator and slug catcher recover free liquids from the inlet stream, which serves to protect the compressor turbines from foreign material and free liquids. • The 16” Trunk C pipeline brings in gas with a lower content of recoverable hydrocarbon liquids that contains about 6% carbon dioxide. The Trunk C gas is treated or blended with the cryogenic process reside stream for the entire outlet stream to meet interstate pipeline quality specifications. The gas may also be processed in the amine treater and/or cryogenic plant if necessary to achieve interstate pipeline gas quality specifications. 1 The facility includes a Turbo-Expander Plant [cryogenic] nominally rated at 450 MMscfd and one NGL fractionation plant. The present total gas throughput averages close to 500 MMscfd. Approximately 380 MMscfd is natural gas from the Trunk S inlet that is processed in the cryogenic plant. About 90 MMscfd is Trunk C inlet gas that is dehydrated, and then normally bypasses other plant processes including amine treatment and the cryogenic plant. Primary plant operations include inlet compression turbines, the east glycol dehydration unit, the amine plant, the west glycol dehydration unit, the molecular sieve dehydrator, the turbo-expander plant (cryogenic removal of NGL), the fractionation plant, and recompression. The plant operations are described below. Inlet Compression Inlet compression at the facility is accomplished through an arrangement of compressors driven by stationary natural gas turbines. The inlet compression turbines include one (1) Solar Titan 130 natural gasfired turbine (Trunk S), one (1) Solar Mars 100 natural gas-fired turbine (Trunk S), and one (1) Solar Taurus 70 natural gas-fired turbine (Trunk C) equipped with a heat recovery steam generator (HRSG). Dehydration Dehydration of Trunk C field gas is accomplished at the East Dehydrator. The East Dehydrator is equipped with a natural gas-fired reboiler rated at 0.75 million British thermal units per hour (MMBtu/hr). The East dehydration unit regenerator vent gas is routed to the Callidus Thermal Oxidizer (ThOx) for emission control. Applicable emission limits and operating requirements for the ThOx are dictated by Prevention of Significant Deterioration (PSD) Permit No. PSD-SU-00027-01.00, issued December 22, 2010. Initial dehydration of Trunk S field gas is accomplished at the West Dehydrator, which removes excess moisture to decrease the burden on the downstream molecular sieve dehydrator. The West Dehydrator is equipped with a steam-heated glycol reboiler. The regenerator vent hydrocarbon slip emissions are controlled by the Plant Flare. Emission limits and operating requirements in PSD-SU-00027-01.00 issued December 22, 2010 may be applicable. The molecular sieve dehydrator consists of four beds. The mole sieve beds are cycled such that three of the beds are operating while the fourth bed undergoes regeneration. Regeneration is accomplished by a natural gas-fired regeneration gas heater which is designated at 18.5 MMBtu/hr. The standby regeneration gas heater, which is also natural gas fired, is design-rated at 13.02 MMBtu/hr. Carbon Dioxide Removal Carbon dioxide removal occurs within the Amine Treatment System. Therefore, the amine reboiler utilizes heat from plant steam, it is not a source of combustion emissions. However, hydrocarbons are released from the process during amine regeneration. The entrained hydrocarbons in the vent stream are controlled by combustion in the ThOx. Emission limits and operating requirements in permit PSD-SU-00027-01.00 issued December 22, 2010 are applicable. NGL Removal, Fractionation and Storage At the Turbo-Expander Plant, the demethanizer separates methane from the NGL. The NGL is then sequentially separated into ethane, propane, butane and natural gasoline at the Fractionation Plant. Variation 2 in fractionation operations can occur based on market conditions. The demethanizer, deethanizer, depropanizer, and debutanizer reboilers utilize plant steam. The facility is equipped with 25 storage tanks of various types and capacities. Storage facilities are located within the facility and include: Product Y-Grade Bullets Propane Bullets Butane Spheres Natural Gasoline Spheres Condensate Bullets LNG Bullet LNG Bullet Propane Bullet Condensate Bullet No. of Vessels 5 10 2 2 2 1 1 1 1 Vessel Size (Gallons) 25,200 42,000 260,232 214,900 41,581 38,500 55,000 90,000 90,000 Pressure Rating (psig) 700 250 85 30 85 185 90 240 240 Loading of NGL NGL are transported off-site via pipelines and tanker trucks. “Y-grade” (demethanized mix of NGL composition of which depends on a number of plant operating variables), is transported off-site via a NGL pipeline. The loading of the remaining NGL occurs through loading racks - two (2)-propane loading racks, one (l)-butane loading rack, two (2)-natural gasoline loading racks, and one (1) liquidified natural gas (LNG) loading rack. These liquids can also be sent to pipeline when excess at the plant is available. Re-Compression The methane stream leaving the Turbo-Expander Plant (TXP) is recompressed by two (2) Solar Titan 130 natural gas-fired turbine driven compressors equipped with HRSGs. Utilities The following combustion sources at the Ignacio Plant are equipped with waste heat recovery units: • Trunk C Inlet - Solar Taurus 70 natural gas-fired turbine • Recompression - Two (2)-Solar Titan 130 natural gas-fired turbines • The Thermal Oxidizer These waste heat recovery units provide the Ignacio Plant with high pressure steam (600 psig) to drive a steam turbine generator set to produce plant electricity, as well as low pressure steam (60 psig). Supplemental low pressure steam is produced by the Vogt CL.VV-22.5 boilers. These units generally operate only when the recompressors are not in operation. The plant includes a two-cell cooling tower. The following combustion sources located at the La Plata B Compressor Station provide steam for the Ignacio Gas Plant, and are included in the facility’s Title V permit: • Two (2) Deltak Delta 3S6-347 boilers 3 Emission Control Equipment Emissions of volatile organic compounds (VOC) may be released from various process units, storage tanks and leaking components. Such releases occur throughout the plant, and may be controlled or uncontrolled (fugitive). Controlled releases are collected and routed through a header to the smokeless flare or the flash gas system. Releases from the following sources are controlled through the flare system: • • • • • • • • • • • • • • • • • • Inlet separator (Trunk C) Inlet Gas Cooler West Dehydration Unit Fuel Gas Line and Filter Various Process Scrubbers and Blow Down Vents Booster Compressor CG-8104 Suction Line (TXP) Deethanizer Reflux Condenser, Overhead Off Gas, Reflux Accumulator, Reboiler and Feed Pre-Heater Depropanizer and Depropanizer Reflux Accumulator Debutanizer, Debutanizer Reflux Pumps and Accumulator Ethane/Propane Product Accumulator Vent from Y-Grade Storage Propane Storage and Loading Butane Storage and Loading Natural Gasoline Loading and Storage Condensate Storage Closed Drain System Chromatography Vent Emergency Releases The Flash Gas System takes various streams for re-compression by two electric driven reciprocating compressors prior to being sent to the facility inlet for re-processing. The flash gas system controls emissions from the following sources: • • • West glycol dehydrator flash tank Amine Treatment flash tank LNG flashing The Thermal Oxidizer operated at the Ignacio Gas Plant is a Callidus Technologies unit, installed in 1999 and equipped with a forced draft combustion air blower and vent stack. The Thermal Oxidizer controls emissions from the East Dehydration Unit and the Amine Treatment System. Applicable Thermal Oxidizer emission limits and operating requirements are set by the PSD permit PSD-SU-00027-01.00 issued December 22, 2010. 4 The uncontrolled releases of VOC are minimized through the implementation of a Leak Detection and Repair (LDAR) program. Source Emission Points Table 1 - Emission Units Emission Unit ID Control Equipment Description C.E. Natco MN620740009020 Molecular Sieve Regeneration Heater 18.5 MMBtu/hr 12 Serial No. IJ052 Install Date: 1/1/1984 Struthers IF – 10 Back-Up Molecular Sieve Regeneration Heater 13.02 MMBtu/hr 12a Serial No. NM085347/M050102 Install Date: None None 1/1/1984 Vogt CL. VV – 22.5 Industrial Boiler 18.0 MMBtu/hr 13 14 Serial No. 1425 Install Date: 1426 1/1/1956 1/1/1956 Sivalls 500 MMscfd TEG Dehydrator Regenerator (West) 3.0 (Steam Heat) MMBtu/hr Glycol Regenerator Reboiler 15 Serial No. 26461 Install Date: 1992 Sivalls 120 MMscfd SB – 18-18H TEG Dehydrator Regenerator (East) 0.75 MMBtu/hr Natural Gas – Fired Glycol Regenerator Reboiler 16 Serial No. 9004-174 Install Date: Serial No. N/A Install Date: Plant Flare (Emission Unit 23) 1/1/1991 Thermal Oxidizer (Emission Unit 22) 1/1/1984 Thermal Oxidizer (Emission Unit 22) Amine Unit Regenerator Vent 17 None Piping Component Fugitives: pumps, pressure relief devices, open ended valve lines, compressors, and flanges or other connectors that are in VOC or wet gas service 18 19 20 N/A Serial No. N/A Install Date: N/A 5 Pre-1971 2011 Enhanced LDAR 1984 / PSD LDAR Program 1998 NSPS KKK LDAR Program Natural Gas Liquids Loadout System (one pipeline and five loading racks) 21 Serial No. N/A Install Date: Pre-1972 Callidus Technologies 203313-00 Thermal Oxidizer 22 Serial No. 203313-000 Install Date: 1/1/1999 Zecco Plant Flare 23 Serial No. 17790 Install Date: 2009 Fluor Company Cooling Tower 24 Serial No. N/A Install Date: 1/1/1956 Waukesha H866D Diesel Fired Water Pump Engine 384 Nameplate Rated Horsepower 25 Serial No. 909602 Serial No. 6TB04260 Install Date: Serial No. OHK19-M3865 Install Date: None None 1/1/1978 None 1/1/1985 Solar Mars 100 Natural Gas Fired Turbine (Trunk S) 27 None None Install Date: Caterpillar 4W-3798 Diesel Fired Water Pump Engine 305 Nameplate Rated Horsepower 26 Plant Flare (Emission Unit 23) 2/1/2013 SoLoNOx Solar Titan 130 Natural Gas Fired Turbine 28 30 OHB19-L6137 Serial No. 31 Install Date: OHC22-L2539 OHC22-L0090 2/1/2013 SoLoNOx 4/29/2022 SoLoNOx 3/28/2022 SoLoNOx Solar Taurus 70 Natural Gas Fired Turbine (Trunk C) 29 Serial No. OHH21-B0605 Install Date: 6 9/29/2021 SoLoNOx Horton 42,000 Gallon Produced Water Storage Tank 32 Serial No. 33 N/A Install Date: N/A 1956 None 1956 None Deltak Delta 3S6-347 Natural Gas Fired Waste Heat Recovery Boiler 29 MMBtu/hr B001 Serial No. B002 G92001A Install Date: G92001B 1992 None 1992 None 1984 None 1984 None General Electric M3142J A/T Natural Gas Fired Turbine *10 Serial No. *11 282514 Install Date: 282515 * According to the previous permit holder, these units have been permanently removed from the facility. However, these units remain listed in the Part 70 permit as they are still listed in the PSD permit for this facility. As of October 2018, this facility is operated by Harvest Four Corners, LLC. Table 2 - Insignificant Emission Units Emission Amount Unit ID N/A N/A N/A N/A N/A N/A TK1 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 2 1 1 1 1 1 1 1 1 1 1 1 2 2 1 1 1 2 5 10 Description Size Units Lube oil storage tank Diesel tank (river water pump building & fire water pump generators) Diesel tank (river water pump building & fire water pump generators) Spent lube oil storage tank Lube oil storage tank Diesel storage tank Diesel storage tank Gasoline storage tank Petroleum solvent storage tank Lube oil storage tank Spent lube oil storage tank Turbine 32 oil storage tank Natural gasoline sphere – 30 psig Natural gas liquid rundown pressurized tank – 85 psig Recovery oil tank (T9103) Recovery oil tank (T9104) Ambitrol storage tank Butane sphere – 85 psig Y-Grade bullet – 700 psig Propane bullet – 250 psig 2,060 290 322 33,694 11,653 517 1,028 582 509 6,300 2,000 8,820 214,924 41,581 504 500 748 260,232 22,321 40,805 gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal 7 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 1 1 1 1 1 1 1 1 2 1 1 1 1 1 1 1 3 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 2 1 1 Sulfuric acid storage tank Sulfuric acid storage tank TEG storage tank Raw water storage tank (West tank) Raw water storage tank (East tank) Optisphere HP55441 tank Ambitrol storage tank DI water storage tank Raw water storage tank Salt water storage tank Depositrol PY5206 tank Biomate MBC2881 tank Cooling tower blend tank Klaraid IC1172 tank Cortol OS2001 tank Steammate NA0120 tank Gas spec (amine) storage tank – 1 fresh, 1 mixed, and 1 regenerated Gas Spec (amine) storage tank Gas spec (amine) storage tank Methanol storage tank Turbine 32 oil storage tank Gengard GN7110 tank Bleach tank Waste oil tank TEG storage tank Turbine 32 oil storage tank (steam turbine) Klaraid IC1172 tank Polyfloc AE1115 tank (inside clear water building) Diesel storage tank LNG pressurized bullet – 185 psig LNG pressurized bullet – 90 psig Waste water frac tank Slop oil tank Odorant storage tank Propane bullet – 240 psig Condensate bullet – 240 psig Sodium Hydroxide tank Lube oil storage tank Lube oil storage tank Lube oil/water storage tank Sodium Hydroxide tank 8 4,200 294 2,910 215,904 200,000 400 2,300 215,977 21,000 4,300 400 55 2,970 400 400 400 16,800 4,200 20,000 24,240 300 550 330 630 719 850 500 120 564 38,513 55,000 16,800 4,200 796 90,000 90,000 35 6,300 2,000 1,000 300 gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal gal Section II – General Requirements Title V Administrative Requirements 1.1. Annual Fee Payment [RAC 2-110(1)(h) and RAC 2-118] 1.1.1. An annual operating permit emission fee shall be paid to the Tribe by the permittee. [RAC 2-118(2)] 1.1.2. The permittee shall pay the annual permit fee each year no later than April 1st for the preceding calendar year. [RAC 2-118(2)] 1.1.3. Fee payments shall be remitted in the form of a money order, bank draft, certified check, corporate check, or electronic funds transfer payable to the Southern Ute Indian Tribe and sent or delivered by the United States Postal Service c/o Environmental Programs Division Part 70 Program, P.O. Box 737 MS #84, Ignacio, Colorado 81137; or by common carrier (such as UPS or FedEx) c/o Environmental Programs Division Part 70 Program, 398 Ouray Drive, Ignacio, Colorado 81137. [RAC 2-118(4)(a)] 1.1.4. The permittee shall send an updated fee calculation worksheet submitted annually by the same deadline as required for fee payment to the address listed in the Submissions section of this permit. [RAC 2-118] 1.1.5. Basis for calculating annual fee: 1.1.5.1. Subtotal annual fees shall be calculated by multiplying the applicable emission fee set pursuant to RAC § 2-119(1) times the total tons of actual emissions for each fee pollutant. In lieu of actual emissions, annual fees may be calculated based on the potential to emit for each fee pollutant. Emissions of any regulated air pollutant that already are included in the fee calculation under a category of regulated pollutant, such as a federally listed hazardous air pollutant that is already accounted for as a VOC or as PM10, shall be counted only once in determining the source’s actual emissions. [RAC 2-119(2)(a)] 1.1.5.1.1. “Actual emissions” means the actual rate of emissions in tpy of any fee pollutant (for fee calculation) emitted from a Title V source over the preceding calendar year or any other period determined by the Tribe to be more representative of normal operation and consistent with the fee schedule adopted by the Tribe and approved by the Administrator. Actual 9 emissions shall be calculated using each emissions units actual operating hours, production rates, in-place control equipment, and types of materials processed, stored, or combusted during the preceding calendar year or other period used for this calculation. [RAC 1-103(2)] 1.1.5.1.2. Actual emissions shall be computed using compliance methods required by the permit. [RAC 2-118(1)(b)] 1.1.5.1.3. If actual emissions cannot be determined using the compliance methods in the permit, the permittee shall use other federally recognized procedures. [RAC 2-118(1)(b)] 1.1.5.2. The total annual fee submitted shall be the greater of the applicable minimum fee or the sum of subtotal annual fees for all fee pollutants emitted from the source. [RAC 2-119(2)(b)] [Explanatory note: The applicable emission fee amount and applicable minimum fee (if necessary) are revised each calendar year to account for inflation, and they are available from AQP prior to the start of each calendar year.] 1.1.5.3. The permittee shall exclude the following emissions from the calculation of fees: 1.1.5.3.1. The amount of actual emissions of any one fee pollutant that the source emits in excess of 4,000 tons per year 1.1.5.3.2. Any emissions that come from insignificant activities not required in a permit application pursuant to RAC § 2-106(4). [RAC 1-103(2)(c)] 1.1.6. Annual fee calculation worksheets shall be certified as to truth, accuracy, and completeness by a responsible official. [RAC 2-105 and RAC 2-118(2)(c)] 1.1.7. Failure of the permittee to pay fees by the due date shall subject the permittee to assessment of penalties and interest in accordance with RAC § 2-118(6). [RAC 2-118(6)] 1.1.8. When notified by the Tribe of underpayment of fees, the permittee shall remit full payment within 30 days of receipt of an invoice from the Tribe. [RAC 2-119(3)(b)] 10 1.1.9. A permittee who thinks a Tribe assessed fee is in error and who wishes to challenge such fee shall provide a written explanation of the alleged error to the Tribe along with full payment of the assessed fee. [RAC 2-119(3)(c)] 1.2. Compliance Requirements 1.2.1. Compliance with the Permit 1.2.1.1. The permittee must comply with all conditions of this part 70 permit. Any permit noncompliance with federally enforceable or Commission-only permit conditions constitutes a violation of the RAC and Clean Air Act and is grounds for enforcement action; for permit termination, revocation and reissuance, or revision; or for denial of a permit renewal application. [RAC 2-110(3)(a)] 1.2.1.2. It shall not be a defense for a permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit. [RAC 2-110(3)(b)] 1.2.1.3. All terms and conditions of this permit which are required under the Clean Air Act or under any of its applicable requirements, including any provisions designed to limit a source’s potential to emit, are enforceable by the Administrator and citizens under the Clean Air Act, except terms and conditions the permit specifically designates as not being federally enforceable under the Clean Air Act that are not required under the Clean Air Act or under any of its applicable requirements. Terms and conditions so designated are not subject to the requirements of RAC §§ 2-108, 2-111, 2-112, other than those contained in this paragraph. [RAC 2-110(3)(f)] 1.2.1.4. This permit, or the filing or approval of a compliance plan, does not relieve any person from civil or criminal liability for failure to comply with the provisions of the RAC and the Clean Air Act, applicable regulations thereunder, and any other applicable law or regulation. [RAC 2-110(3)(g)] 1.2.1.5. For the purpose of submitting compliance certifications in accordance with the Compliance Certifications condition below of this permit, or establishing whether or not a person has violated or is in violation of any requirement of this permit, nothing shall preclude the use, including the exclusive use, of any credible evidence or information, relevant to whether a source would have been in compliance with applicable requirements if the appropriate performance or compliance test or procedure had been performed. 11 [Section 113(a) and 113(e)(1) of the Act, 40 CFR §§ 51.212, 52.12, 52.33, 60.11(g), and 61.12] 1.2.2. Compliance Certifications 1.2.2.1. The permittee shall submit to the Tribe and the Administrator an annual certification of compliance which shall certify the source’s compliance status with all permit terms and conditions and all applicable requirements relevant to the source, including those related to emission limitations, standards, or work practices. The compliance certification shall be certified as to truth, accuracy, and completeness by a responsible official consistent with RAC § 2-110(9)(a). The certification of compliance shall be submitted annually by April 1st and shall cover the preceding calendar year in which the certification of compliance is due, except that the first annual certification of compliance will cover the period from the issuance date of this permit through December 31st of the same year. [RAC 2-110(9)(c)] 1.2.3. Compliance Schedule 1.2.3.1. For applicable requirements with which the source is in compliance, the source will continue to comply with such requirements. [RAC 2-106(4)(l)(ii)] 1.2.3.2. For applicable requirements that will become effective during the permit term, the source shall meet such requirements on a timely basis. [RAC 2-106(4)(l)(iii)] 1.3. Duty to Provide and Supplement Information [RAC 2-110(7)(e), 2-106(5), and 2-124] 1.3.1. The permittee shall furnish to the Tribe, within the period specified by the Tribe, any information that the Tribe request in writing to determine whether cause exists for reopening and revising, revoking, and reissuing, or terminating the permit, or to determine compliance with the permit. Upon request, the permittee shall also furnish to the Tribe copies of records that are required to be kept by the permit, including information claimed to be confidential. Information claimed to be confidential must be accompanied by a claim of confidentiality according to the provisions of RAC 2-124. [RAC 2-110(7)(e) and RAC 2-124] 1.3.2. The permittee, upon becoming aware that any relevant facts were omitted or incorrect information was submitted in the permit application or in a supplemental submittal, shall promptly submit such supplementary facts or corrected information. In addition, a permittee shall provide additional information as necessary to address any requirements that become applicable after the date a complete application is filed, but prior to release of a draft permit. [RAC 2-106(5)] 12 1.4. Submissions [RAC 2-105] 1.4.1. Any application, form, report, compliance certification, or other document submitted by the permittee under this permit shall contain a certification by a responsible official of truth, accuracy, and completeness. This certification shall state that, based on information and belief formed after reasonable inquiry, the statements and information in the document are true, accurate, and complete. [Explanatory Note: The Tribe has developed a reporting form “CTAC” for certifying truth, accuracy and completeness of part 70 submissions. The form may be found on the AQP’s website (http://www.southernute-nsn.gov/environmental-programs/air-quality).] 1.4.2. Except where otherwise noted, any documents required to be submitted under this permit, including reports, test data, monitoring data, notifications, compliance certifications, fee calculation worksheets, and applications for renewals and permit modifications shall be submitted: by email at: airquality@southernute-nsn.gov or by United States Postal Service: Part 70 Program Environmental Programs Division Air Quality Program P.O. Box 737 MS #84 Ignacio, Colorado 81137 or by Common Carrier: Part 70 Program Environmental Programs Division Air Quality Program 398 Ouray Drive Ignacio, CO 81137 1.5. Severability Clause [RAC 1-106 and RAC 2-110(1)(f)] The provisions of this permit are severable, and in the event of any challenge to any portion of this permit, or if any provision is held invalid, the remaining permit conditions shall remain valid and in force. 1.6. Permit Actions [RAC 2-110(3)] 1.6.1. This permit may be modified, reopened and revised, revoked and reissued, or terminated for cause. [RAC 2-110(3)(c)] 1.6.2. The filing by the permittee of a request for a permit revision, reissuance, or termination, or of a notification of planned changes or anticipated noncompliance shall not stay any permit condition. [RAC 2-110(3)(d)] 13 1.7. Administrative Permit Revision [RAC 2-111(2)] 1.7.1. The permittee may submit an application for an administrative permit revision as defined in RAC § 1-103. [RAC 2-111(2)(a)] 1.7.2. The permittee may implement an administrative permit revision immediately upon submittal of the request for the administrative revision. [RAC 2-111(2)(c)] [Note to permittee: If the provisions allowing for an administrative permit revision do not apply, please contact the Air Quality Program for a determination of similarity prior to submitting your request for an administrative permit revision.] 1.8. Minor Permit Revisions [RAC 2-111(3)] 1.8.1. The permittee may submit an application for a minor permit revision as defined in RAC § 1-103. 1.8.2. An application requesting the use of minor permit revision procedures shall meet the requirements of RAC § 2-106(4) and shall include the following: 1.8.2.1. A description of the change, the emissions resulting from the change, and any new applicable requirements that will apply if the change occurs; 1.8.2.2. If changes are requested to the permit language, the permittee’s suggested draft permit changes; 1.8.2.3. Certification by a responsible official, consistent with RAC § 2-105, that the proposed revision meets the criteria for use of minor permit revision procedures and a request that such procedures be used; and 1.8.2.4. Completed forms for the Tribe to use to notify the Administrator and affected programs as required under RAC § 2-108 1.8.2.5. If the requested permit revision would affect existing compliance plans or schedules, related progress reports, or certification of compliance requirements, and an outline of such effects. [RAC 2-111(3)(a)] 1.8.3. The permittee shall not submit multiple minor permit revision applications that may conceal a larger revision that would not constitute a minor permit revision. [RAC 2-111(3)(b)] 14 1.8.4. The permittee may make the change proposed in its minor permit revision application immediately after it files such application, provided, however, for sources that have previously utilized this provision during the term of the permit and, on two or more occasions have failed to file a complete application, may thereafter make the change only after the application is deemed complete. After the permittee makes the change and until the Tribe takes any of the actions specified in the following subsection, the permittee must comply with both the applicable requirements governing the change and the proposed permit terms and conditions. During this period, the permittee need not comply with the existing permit terms and conditions it seeks to modify. If the permittee fails to comply with its proposed permit terms and conditions during this period, however, the existing permit terms and conditions it seeks to modify may be enforced against it. [RAC 2-111(3)(e)] 1.8.5. The permit shield under RAC § 2-110(10) does not extend to minor permit revisions. [RAC 2-110(10)(d)] 1.9. Significant Permit Revisions [RAC 2-111(4)] 1.9.1. The permittee must request the use of significant permit revision procedures as defined in RAC § 1-103. 1.9.2. Significant permit revisions shall meet all requirements of the RAC for permit issuance and renewal, including those for applications, review by the Administrator and affected programs, and public participation. [RAC 2-111(4), 2-109, and 2-106(3)] 1.10. Permit Reopenings, Revocations and Reissuances, and Terminations [RAC 2-112] 1.10.1. The permit may be reopened and revised for any of the reasons listed in the paragraphs below. Alternatively, the permit may be revoked and reissued for the reasons listed in the paragraphs below: 1.10.1.1. Additional requirements under the Clean Air Act become applicable to a major source with a remaining permit term of 3 or more years, provided that the Tribe shall revise such permits to incorporate such additional requirements no later than 18 months after promulgation of such requirements, and no such reopening is required if the effective date of the requirement is later than the permit expiration date unless the original permit or any of its terms or conditions have been extended past the permit expiration date pursuant to RAC § 2-104(2)(b)(iii); 1.10.1.2. Additional requirements (including excess emissions requirements) become applicable to an affected source under the acid rain program. Upon approval by the Administrator, excess emissions offset plans shall be deemed to be incorporated into the permit; 15 1.10.1.3. The Tribe or the Administrator determines that the permit contains a material mistake or that inaccurate statements were made in establishing the terms or conditions of the permit; or 1.10.1.4. The Tribe or the Administrator determines that the permit must be revised or revoked and reissued to assure compliance with applicable requirements. 1.10.2. The permit may be terminated for any of the reasons in (a) through (g) below: 1.11. 1.10.2.1. The permittee fails to meet the requirements of an approved compliance plan; 1.10.2.2. The permittee has been in significant or repetitious noncompliance with the operating permit terms or conditions; 1.10.2.3. The permittee has exhibited a history of willful disregard for environmental laws of any tribal or state authority, or of the United States; 1.10.2.4. The permittee has knowingly misrepresented a material fact in any application, record, report, plan, or other document filed or required to be maintained under the permit; 1.10.2.5. The permittee falsifies, tampers with, or renders inaccurate any monitoring device or method required to be maintained under the permit; 1.10.2.6. The permittee fails to pay fees required under RAC§§ 2-118 and 2-119; or 1.10.2.7. The Administrator has found that cause exists to terminate the permit. Property Rights [RAC 2-110(3)(e)] This permit does not convey any property rights of any sort, or any exclusive privilege. 1.12. Inspection and Entry [RAC 2-110(9)(b)] Upon presentation of credentials and other documents as may be required by law, the permittee shall allow authorized representatives of the Tribe or other authorized representative to perform the following: 1.12.1. Enter upon the permittee’s premises where a source is located or emissions-related activity is conducted, or where records must be kept under the conditions of the permit; 1.12.2. Have access to and copy, at reasonable times, any records that must be kept under the conditions of the permit; 16 1.12.3. Inspect at reasonable times any facilities, equipment (including monitoring and air pollution control equipment), practices, or operations regulated or required under the permit; and 1.12.4. As authorized by the Clean Air Act, sample or monitor at reasonable times substances or parameters for the purpose of assuring compliance with the permit or applicable requirements. 1.13. Emergency Situations [RAC 2-117] 1.13.1. The permittee may seek to establish that noncompliance with a technology-based emission limitation under this permit was due to an emergency as defined in RAC § 1-103. To do so, the permittee shall demonstrate the affirmative defense of emergency through properly signed, contemporaneous operating logs, or other relevant evidence that: 1.13.1.1. An emergency occurred and that the permittee can identify the cause(s) of the emergency; 1.13.1.2. The permitted facility was at the time being properly operated; 1.13.1.3. During the period of the emergency the permittee took all reasonable steps to minimize levels of emissions that exceeded the emissions standards, or other requirements in this permit; and 1.13.1.4. The permittee reported the emergency to the Tribe in compliance with RAC § 2110(7). [RAC 2-117(1)] 1.13.2. In any enforcement preceding the permittee attempting to establish the occurrence of an emergency has the burden of proof. [RAC 2-117(2)] 1.13.3. This emergency situation provision is in addition to any emergency or upset provision contained in any applicable requirement. [RAC 2-117(3)] 1.14. Permit Transfers [RAC 2-113] 1.14.1. This permit shall not be transferable, by operation of law or otherwise, from one location to another or from one source to another, except that a permit may be transferred from one location to another in the case of a portable source that has notified the Tribe in advance of the transfer, pursuant to the RAC. A permit for a source may be transferred from one person to another if the Tribe finds that the transferee is capable of operating the source in compliance with the permit. This transfer must be accomplished through an administrative 17 permit revision in accordance with the Administrative Permit Revisions section of this permit. 1.15. Off-Permit Changes [RAC 2-116(2)] 1.15.1. The permittee is allowed to make, without a permit revision, certain changes that are not addressed or prohibited by this permit provided that the following requirements are met: 1.15.1.1. Each such change meets all applicable requirements and shall not violate any existing permit term or condition; 1.15.1.2. Such changes are not subject to any requirements under title IV of the Clean Air Act and are not modifications under title I of the Clean Air Act; 1.15.1.3. Such changes are not subject to permit revision procedures under RAC § 2-111; and 1.15.1.4. The permittee provides contemporaneous written notice to the Tribe and the Administrator of each such change, except for changes that qualify as insignificant activities. Such notice shall state when the change occurred and shall describe the change, any resulting emissions change, pollutants emitted, and any applicable requirement that would apply as a result of the change. [RAC 2-116(2)(a)] 1.15.2. The permit shield does not apply to changes made under this provision. [RAC 2-110(10)(d)] 1.15.3. The permittee shall keep a record describing changes made at the source that result in emissions of any regulated air pollutant subject to an applicable requirement, but not otherwise regulated under the permit, and the emissions resulting from those changes. [RAC 2-116(2)(b)] 1.15.4. A copy of each off-permit change notification shall be made available to the Tribe upon request. [RAC 2-110(6)] 1.16. Permit Expiration and Renewal [RAC §§ 2-104(3), 2-106(2)(b), 2-107(7)(a), 2-107(7)(b), 2-110(1)(a), and 2-106(3)] 1.16.1. This permit shall expire five years from the effective date of this permit. 18 [RAC 2-110(1)(a)] 1.16.2. Expiration of this permit terminates the permittee’s right to operate unless a timely and complete permit renewal application has been submitted at least 6 months but not more than 18 months prior to the date of expiration of this permit. [RAC 2-107(7)(b)] 1.16.3. If the permittee submits a timely and complete permit application for renewal, consistent with RAC § 2-106 but the Tribe has failed to issue or disapprove a renewal permit before the end of the permit term, then the permit shall not expire and all its terms and conditions shall remain in effect until the renewal permit has been issued or disapproved. [RAC 2-104(2)(b)] 1.16.4. The ability to operate under this permit shall cease if (1) the Tribe takes final action to issue the permittee a renewal permit or deny the permittee a permit or (2) the permittee fails to submit by the deadline specified in writing by the Tribe any additional information identified as being needed to process the application. [RAC 2-104(3)] 1.16.5. Renewal of this permit is subject to the same procedures, including those for public participation and affected program and EPA review, as those that apply to initial permit issuance. [RAC 2-107(7)(a)] 1.16.6. The application for renewal shall include the current permit number, description of permit revisions and off permit changes that occurred during the permit term, any applicable requirements that were promulgated and not incorporated into the permit during the permit term, and other information required by the application form. [RAC 2-106(4)(e)(ix)] Facility-Wide Requirements Conditions in this section of the permit apply to all emissions units located at the facility, including any units not specifically listed in Table 1 or Table 2 of the Source Emission Points section of this permit. [RAC 2-110(1)(d)] 2.1. General Recordkeeping Requirements [RAC 2-110(6)] The permittee shall comply with the following generally applicable recordkeeping requirements: 2.1.1. If the permittee determines that his or her stationary source that emits (or has the potential to emit, without federally recognized controls) one or more hazardous air pollutants is not subject to a relevant standard or other requirement established under 40 CFR part 63, the permittee shall keep a record of the applicability determination, for a period of five years after the determination, or until the source changes its operations to become an affected source, whichever comes first. Each of these records shall be made available to the Tribe upon request. The record of the applicability determination shall include an analysis (or 19 other information) that demonstrates why the permittee believes the source is unaffected (e.g., because the source is an area source). [40 CFR 63.10(b)(3)] 2.1.2. Records shall be kept of off permit changes made, as required by the Off Permit Changes section of this permit. 2.2. General Reporting Requirements 2.2.1. The permittee shall submit to the Tribe all reports of any required monitoring under this permit semiannually, by April 1 and October 1 of each year. The report due on April 1 shall cover the July 1 - December 31 reporting period of the previous calendar year. The report due on October 1 shall cover the January 1 - June 30 reporting period of the current calendar year. All instances of deviations from permit requirements shall be clearly identified in such reports. All required reports shall be certified by a responsible official consistent with the Submissions section of this permit. [RAC 2-110(7)(a)] 2.2.2. “Deviation” means any situation in which an emissions unit fails to meet a permit term or condition. A deviation is not always a violation. A deviation can be determined by observation or through review of data obtained from any testing, monitoring, or recordkeeping established in accordance with RAC 2-110(5) and (6). 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: 2.2.2.1. A situation where emissions exceed an emission limitation or standard; 2.2.2.2. A situation where process or emissions control device parameter values indicate that an emission limitation or standard has not been met; or 2.2.2.3. A situation in which observations or data collected demonstrate noncompliance with an emission limitation or standard or any work practice or operating condition required by the permit. 2.2.2.4. A situation in which an exceedance or an excursion, as defined in 40 CFR Part 64 occurs. [RAC 1-103(21)] 2.2.3. The permittee shall promptly report to the Tribe deviations from permit requirements, (including emergencies), including the date, time, duration, and the probable cause of such deviations, the quantity and pollutant type of excess emissions resulting from the deviation, and any preventative, mitigation, or corrective actions or measures taken. 20 Prompt deviation reports shall be submitted to the following email address: airquality@southernute-nsn.gov 2.2.4. “Prompt” is defined as follows: 2.2.4.1. Where the underlying applicable requirement contains a definition of “prompt” or otherwise specifies a time frame for reporting deviations, that definition or time frame shall govern. 2.2.4.2. 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: 2.2.4.2.1. 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 requirements, the report must be made by email, telephone, verbal, or facsimile communication by the close of business the next working day, upon discovery of the occurrence, and in writing within 10 working days from the occurrence; 2.2.4.2.2. For emissions of any regulated air pollutant, excluding those listed in RAC § 2-110(7)(b)(i), that continue for more than 2 hours in excess of permit requirements, the report must be made by email, telephone, verbal, or facsimile communication by the close of business the next working day, upon discovery of the occurrence, and in writing within 10 working days from the occurrence; 2.2.4.2.3. For all other deviations from permit requirements, the report shall be contained in the report submitted with the semi-annual monitoring report. [RAC 2-110(7)(b)] 2.3. Alternative Operating Scenarios [RAC 2-110(8)] 2.3.1. Replacement of an existing engine or turbine identified in this permit shall be allowed as an off-permit change pursuant to the Off Permit Changes provisions of this permit provided all of the following conditions are met: 2.3.1.1. The engine or turbine replacement is not subject to any requirements under Title IV of the Clean Air Act and is not a modification under Title I of the Clean Air Act; 2.3.1.2. The replacement engine or turbine is of the same make, model, horsepower rating, and configured to operate in the same manner as the engine being replaced. 21 2.3.1.3. The replacement engine or turbine meets all applicable requirements identified in this permit that apply to the existing engine being replaced. 2.3.1.4. All applicable requirements that apply to the replacement engine or turbine are already included in the permit. Replacement of an existing engine or turbine identified in this permit with a new, modified, or reconstructed engine must utilize a Minor Permit Revision as specified in RAC 2-111(3) or a Significant Permit Revision as specified in RAC 2-111(4) to incorporate any new applicable requirements. The applicable requirements include, but may not be limited to: 2.3.1.4.1. Standards of Performance for Stationary Compression Ignition Internal Combustion at 40 CFR Part 60, Subpart IIII 2.3.1.4.2. Standards of Performance for Stationary Spark Ignition Internal Combustion Engines at 40 CFR Part 60, Subpart JJJJ; 2.3.1.4.3. National Emission Standard for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines at 40 CFR Part 63, Subpart ZZZZ; 2.3.1.4.4. Standards of Performance for Stationary Gas Turbines at 40 CFR Part 60, Subpart GG; 2.3.1.4.5. Standards of Performance for Stationary Combustion Turbines at 40 CFR Part 60, Subpart KKKK; 2.3.1.4.6. National Emission Standard for Hazardous Air Pollutants for Stationary Combustion Turbines at 40 CFR Part 63, Subpart YYYY; 2.3.1.4.7. Requirements established in a permit or permits issued pursuant to the Federal Minor New Source Review Program in Indian Country at 40 CFR Part 49; 2.3.1.4.8. Requirements established in a permit or permits issued pursuant to the Prevention of Significant Deterioration of Air Quality Program at 40 CFR Part 52; or 2.3.1.4.9. Requirements established in any promulgated Federal Implementation Plan that may apply to engines located on the Southern Ute Indian Reservation. 2.3.2. The permittee shall provide contemporaneous written notice to the Tribe and the Administrator of any replacement of an existing engine or turbine identified in this permit. Such notice shall state when the replacement occurred and shall describe the replacement and any applicable requirement that would apply as a result of the replacement. 22 2.3.3. The permittee shall keep a record of the engine or turbine replacement. 2.3.4. The use of a backup thermal oxidizer (Unit 22a) with equivalent capacity and emission destruction efficiency and configured to operate in the same manner as the primary thermal oxidizer (Unit 22) shall be an allowed alternative operating scenario under this permit provided that the following conditions are met: 2.3.4.1. Any emission limits, requirements, testing or other provisions that apply to the primary thermal oxidizer shall also apply to the backup thermal oxidizer except that an annual performance test shall only be conducted on the backup thermal oxidizer Unit 22a if the unit operates for more than 500 hours in any calendar year. 2.3.4.2. At no time shall the backup thermal oxidizer operate at the same time the primary thermal oxidizer is operating except periods of transition between the primary and backup thermal oxidizers. Transition events shall be documented, last no more than 30 minutes in duration, and will be reported as excess emission events in accordance with the PSD Permit deviation reporting requirements outlined in this permit. 2.4. Permit Shield [RAC 2-110(10)(c)] Nothing in this permit shall alter or affect the following: 2.4.1. The provisions of Section 303 of the Clean Air Act, 42 U.S.C. § 7603 concerning emergency powers, including the respective authorities of the Administrator under those sections; 2.4.2. The liability of a permittee for any violation of applicable requirements prior to or at the time of permit issuance; 2.4.3. The applicable requirements of the acid rain program consistent with section 408(a) of the Act; or 2.4.4. The ability of the Administrator respectively to obtain information from a source pursuant to Section 114 of the Clean Air Act, 42 U.S.C. § 7414. 2.5. Stratospheric Ozone and Climate Protection [40 CFR Part 82] The permittee shall comply with the standards for recycling and emissions reduction pursuant to 40 CFR Part 82, Subpart F: 2.5.1. Persons opening appliances for maintenance, service, repair, or disposal must comply with the required practices pursuant to 40 CFR §82.156. 23 2.5.2. Equipment used during the maintenance, service, repair, or disposal of appliances must comply with the standards for recycling and recovery equipment pursuant to 40 CFR §82.158. 2.5.3. Persons performing maintenance, service, repair, or disposal of appliances must be certified by an approved technician certification program pursuant to 40 CFR §82.161. 24 Section III – Site Specific Permit Terms New Source Performance Standards (NSPS) and 40 CFR Part 60 1.1. 40 CFR Part 60, Subpart Kb – Standards of Performance for Volatile Organic Liquid Storage Vessels [40 CFR 60.110b-60.116b and RAC 3-102] The permittee shall meet all applicable requirements of 40 CFR Part 60 Subparts A and Kb as they apply to each affected source as defined at 40 CFR 60.110b. 1.1.1. Affected Sources 1.1.1.1. The following emission units are subject to 40 CFR Part 60, Subpart Kb: 33,694 gallon spent lube oil storage tank Two (2) – 21,000 gallon spent lube oil/water storage tanks Two (2) – 42,000 gallon produced water tanks [40 CFR 60.110b] 1.1.2. Recordkeeping Requirements 1.1.2.1. The permittee shall keep readily accessible records showing the dimension of the storage vessel, an analysis showing the capacity of the storage vessel, and an analysis showing the vapor pressure of the storage vessel contents. [40 CFR 60.116b and RAC 2-110(5)] 1.2. 40 CFR Part 60, Subpart KKK – Standards of Performance for Equipment Leaks of VOC from Onshore Natural Gas Processing Plants [40 CFR 60.630 – 60.636, RAC 3-102] This facility is subject to the requirements of 40 CFR Part 60, Subpart KKK. Notwithstanding conditions in this permit, the permittee shall comply with all applicable requirements of 40 CFR Part 60, Subpart A and Subpart KKK. 1.2.1. Affected Sources 1.2.1.1. 40 CFR Part 60, Subpart KKK applies to the following emission units: 1.2.1.1.1. Each compressor in VOC or wet gas service 1.2.1.1.2. The group of all equipment except compressors within a process unit 1.2.1.2. A compressor station, dehydration unit, sweetening unit, underground storage tank, field gas gathering system, or liquefied natural gas unit is covered by this subpart if it is located at an onshore natural gas processing plant. If the unit is not located at the plant site, then it is exempt from the provisions of this subpart. [40 CFR 60.630] 25 1.2.2. Standards 1.2.2.1. The permittee shall comply with the requirements of §§60.482-1 (a), (b), and (d) and 60.482-2 through 60.482-10 of subpart VV, except as provided in §60.633 of this subpart, as soon as practicable, but no later than 180 days after initial startup. [40 CFR 60.632(a)] 1.2.2.2. The permittee may elect to comply with the requirements of §§ 60.483-1 and 60.483-2 of subpart VV. [40 CFR 60.632(b)] 1.2.2.3. The permittee may apply to the EPA Region 8 for permission to use an alternative means of emission limitation that achieves a reduction in emissions of VOC at least equivalent to that achieved by the controls required in this subpart. In doing so, the owner or operator shall comply with requirements of § 60.634 of this subpart. [40 CFR 60.632(c)] 1.2.2.4. The permittee shall comply with the provisions of § 60.485 of subpart VV except as provided in § 60.633(f) of this subpart. [40 CFR 60.632(d)] 1.2.2.5. The permittee subject to the provisions of this subpart shall comply with the provisions of §§ 60.486 and 60.487 of subpart VV, except as provided in §§ 60.633, 60.635, and 60.636 of this subpart. [40 CFR 60.632(e)] 1.2.2.6. The permittee shall use the following provision instead of §60.485(d)(1) of subpart VV: Each piece of equipment is presumed to be in VOC service or in wet gas service unless the permittee demonstrates that the piece of equipment is not in VOC service or in wet gas service. For a piece of equipment to be considered not in wet gas service, it must be determined that the VOC content can be reasonably expected to never exceed 10.0 percent by weight. For a piece of equipment to be considered in wet gas service, it must be determined that it contains or contacts the field gas before the extraction step in the process. For determining the percent VOC content of the process fluid that is contained in or contacts a piece of equipment, procedures that conform to the methods described in ASTEM E169-63, 77, or 93, E168-67, 77, or 92, or E260-73, 91, or 96 (incorporated by reference as specified in §60.17) shall be used. [40 CFR 60.632(f)] 1.2.3. Exceptions 1.2.3.1. The permittee subject to the provisions of this subpart may comply with the following exceptions to the provisions of subpart VV. [40 CFR 60.633(a)] 26 1.2.3.2. Each pressure relief device in gas/vapor service may be monitored quarterly and within 5 days after each pressure release to detect leaks by the methods specified in §60.485(b) of subpart VV except as provided in §60.632(c), §60.633(b)(4), and §60.482-4 (a) through (c) of subpart VV. [40 CFR 60.633(b)(1)] 1.2.3.3. If an instrument reading of 10,000 ppm or greater is measured, a leak is detected. [40 CFR 60.633(b)(2)] 1.2.3.4. When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 calendar days after it is detected, except as provided in §60.482-9 of subpart VV. [40 CFR 60.633(b)(3)(i)] 1.2.3.5. A first attempt at repair shall be made no later than 5 calendar days after each leak is detected. [40 CFR 60.6333(b)(3)(ii)] 1.2.3.6. Sampling connection systems are exempt from the requirements of §60.482-5 of subpart VV. [40 CFR 60.633(c)] 1.2.3.7. Reciprocating compressors in wet gas service are exempt from the compressor control requirements of §60.482-3 of subpart VV. [40 CFR 60.633(f)] 1.2.3.8. Flares used to comply with this subpart shall comply with the requirements of §60.18. [40 CFR 60.633(g)] 1.2.3.9. An owner or operator may use the following provisions instead of §60.485(e) of subpart VV: [40 CFR 60.633(h)] 1.2.4. 1.2.3.9.1. Equipment is in heavy liquid service if the weight percent evaporated is 10 percent or less at 150 °C (302 °F) as determined by ASTM Method D86-78, 82, 90, 95, or 96 (incorporated by reference as specified in §60.17). 1.2.3.9.2. Equipment is in light liquid service if the weight percent evaporated is greater than 10 percent at 150 °C (302 °F) as determined by ASTM Method D86-78, 82, 90, 95, or 96 (incorporated by reference as specified in §60.17). [40 CFR 60.633(h)(1)-(2)] Recordkeeping Requirements 1.2.4.1. Each permittee subject to the provisions of this subpart shall comply with the requirements of § 60.635(b) and (c) in addition to the requirements of § 60.486 of subpart VV as outlined below in this permit section. 27 [40 CFR 60.635(a)] 1.2.4.2. The following recordkeeping requirements of shall apply to pressure relief devices subject to the requirements of 40 CFR 60.635(b)(1) of this subpart. [40 CFR 60.635(b)] 1.2.4.2.1. The permittee of more than one affected facility subject to this subpart may comply with the recordkeeping requirements for these facilities in one recordkeeping system if the system identifies each record by each facility. [40 CFR 60.635(a) and 40 CFR 60.486(a)(2)] 1.2.4.2.2. 1.2.4.3. When each leak is detected as specified in § 60.633(b)(2) of this subpart or §§60.482-2, 60.482-3, 60.482-7, 60.482-8, and 60.843-2 of §60.486 of subpart VV, the following requirements apply: 1.2.4.2.2.1. A weatherproof and readily visible identification, marked with the equipment identification number, shall be attached to the leaking equipment. The identification on the pressure relief device may be removed after it has been repaired. 1.2.4.2.2.2. The identification on a valve may be removed after it has been monitored for 2 successive months as specified in §60.482-7(c) of subpart VV and no leak has been detected during those 2 months. 1.2.4.2.2.3. The identification on equipment except on a valve, may be removed after it has been repaired. [40 CFR 60.635(b)(1) and 40 CFR 60.486(b)(1)-(3)] The following recordkeeping requirements shall apply to pressure release devices subject to the requirements of § 60.633(b)(1) of this subpart 1.2.4.3.1. When each leak is detected as specified in § 60.633(b)(2) of this subpart, a weatherproof and readily visible identification, marked with the equipment identification number, shall be attached to the leaking equipment. The identification on the pressure relief device may be removed after it has been repaired. 1.2.4.3.2. When each leak is detected as specified in § 60.633(b)(2) of this subpart, the following information shall be recorded in a log and shall be kept for 2 years in a readily accessible location: [40 CFR 60.635(b)(1)-(2)] 1.2.4.3.2.1. The instrument and operator identification numbers and the equipment identification number. 1.2.4.3.2.2. The date the leak was detected and the dates of each attempt to repair the leak. 28 Repair methods applied in each attempt to repair the leak. 1.2.4.3.2.4. “Above 10,000 ppm” if the maximum instrument reading measured by the methods specified in §60.635(a) of this subpart or §60.485(a) of subpart VV after each repair attempt is equal to or greater than 10,000 ppm. 1.2.4.3.2.5. “Repair delayed” and the reason for the delay if a leak is not repaired within 15 calendar days after discovery of the leak. 1.2.4.3.2.6. The signature of the owner or operator (or designate) whose decision it was that repair could not be effected without a process shutdown. 1.2.4.3.2.7. The expected date of successful repair of the leak if a leak is not repaired within 15 days. 1.2.4.3.2.8. Dates of process unit shutdowns that occur while the equipment is unrepaired. 1.2.4.3.2.9. The date of successful repair of the leak. 1.2.4.3.2.10. A list of identification numbers for equipment that are designated for no detectable emissions under the provisions of §60.482-4(a) of subpart VV. The designation of equipment subject to the provisions of §60.482-4(a) of subpart VV shall be signed by the owner or operator. [40 CFR 60.635(b)(2)(i)-(x)] 1.2.4.4. 1.2.4.3.2.3. The following information pertaining to the design requirements for closed vent systems and control devices described in §60.482-10 of subpart VV shall be recorded and kept in a readily accessible location: 1.2.4.4.1. Detailed schematics, design specifications, and piping instrument diagrams. 1.2.4.4.2. The dates and descriptions of any changes in the design specifications. 1.2.4.4.3. A description of the parameter or parameters monitored, as required in §60.482-10(e) of subpart VV, to ensure that control devices are operated and maintained in conformance with their design and an explanation of why that parameter (or parameters) was selected for the monitoring. 1.2.4.4.4. Periods when the closed vent systems and control devices required in §§60.482-2, 60.482-3, 60.482-4, and 60.482-5 of subpart VV, are not operated as designed, including periods when a flare pilot light does not have a flame. 29 1.2.4.4.5. 1.2.4.5. Dates of startups and shutdowns of the closed vent systems and control devices required in §§60.482-2, 60.482-3, 60.482-4, and 60.482-5 of subpart VV. [40 CFR 60.635(a) and 40 CFR 60.486(d)(1)-(5)] The following information pertaining to all equipment subject the requirements in §§60.482-1 to 60.482-10 of subpart VV shall be recorded in a log that is kept in a readily accessible location: 1.2.4.5.1. A list of identification numbers for equipment subject to the requirements of this subpart. 1.2.4.5.2. A list of identification numbers for equipment that are designated for no detectable emissions under the provisions of §§ 60.482-2(e), 60.482-3(i) and 60.482-7(f) of subpart VV. 1.2.4.5.3. The designation of equipment as subject to the requirements of §§60.4822(e), 60.482-3(i), or 60.482-7(f) of subpart VV shall be signed by the owner or operator. Alternatively, the owner or operator may establish a mechanism with their permitting authority that satisfies this requirement. 1.2.4.5.4. A list of equipment identification numbers for pressure relief devices required to comply with §60.482-4 of subpart VV. 1.2.4.5.5. The dates of each compliance test as required in §§60.482-2(e), 60.482-3(i), 60.482-4, and 60.482-7(f) of subpart VV. 1.2.4.5.6. The background level measured during each compliance test. 1.2.4.5.7. The maximum instrument reading measured at the equipment during each compliance test. 1.2.4.5.8. A list of identification numbers for equipment in vacuum service. 1.2.4.5.9. A list of identification numbers for equipment that the owner or operator designates as operating in VOC service less than 300 hr/yr in accordance with §60.482-1(e) of subpart VV, a description of the conditions under which the equipment is in VOC service, and rationale supporting the designation that is in VOC service less than 300 hr/yr. [40 CFR 60.635(a) and 40 CFR 60.486(e)(1)-(6)] 1.2.4.6. The following information pertaining to all valves subject to the requirements of §60.482-7(g) and (h) of subpart VV and to all pumps subject to the requirements of §60.482-2(g) of subpart VV shall be recorded in a log that is kept in a readily accessible location: 1.2.4.6.1. A list of identification numbers for valves and pumps that are designated as unsafe-to-monitor, an explanation for each valve or pump stating why the 30 valve or pump is unsafe-to-monitor, and the plan for monitoring each valve or pump. 1.2.4.6.2. A list of identification numbers for valves that are designated as difficult-tomonitor, an explanation for each valve stating why the valve is difficult-tomonitor, and the schedule for monitoring each valve. [40 CFR 60.635(a) and 40 CFR 60.486(f)(1)-(2)] 1.2.4.7. The following information shall be recorded for valves complying with §60.483-2 of subpart VV: 1.2.4.7.1. A schedule of monitoring. 1.2.4.7.2. The percent of valves found leaking during each monitoring period. [40 CFR 60.635(a) and 60.486(g)(1)-(2)] 1.2.4.8. The following information shall be recorded in a log that is kept in a readily accessible location: 1.2.4.8.1. Design criterion required in §§60.482-2(d)(5) and 60.482-3(e)(2) of Subpart VV and explanation of the design criterion; and [40 CFR 60.486(h)(1)] 1.2.4.8.2. Any changes to this criterion and the reasons for the changes. [40 CFR 60.635(a) and 40 CFR 60.486(h)(1) and (2)] 1.2.4.9. The following information shall be recorded in a log that is kept in a readily accessible location for use in determining exemptions as provided in §60.480(d) of subpart VV: 1.2.4.9.1. An analysis demonstrating the design capacity of the affected facility. 1.2.4.9.2. A statement listing the feed or raw materials and products from the affected facilities and an analysis demonstrating whether these chemicals are heavy liquids or beverage alcohol, and 1.2.4.9.3. An analysis demonstrating that equipment is not in VOC service. [40 CFR 60.635(a) and 40 CFR 60.486(i)(1)-(3)] 1.2.4.10. Information and data used to demonstrate that a piece of equipment is not in VOC service shall be recorded in a log that is kept in a readily accessible location. [40 CFR 60.635(a) and 40 CFR 60.486(j)] 31 1.2.4.11. 1.2.5. The permittee shall comply with the following requirement in addition to the requirement of §60.486(j) of subpart VV: Information and data used to demonstrate that a reciprocating compressor is in wet gas service to apply for the exemption on §60.633(f) shall be recorded in a log that is kept in a readily accessible location. [40 CFR 60.635(a) and 40 CFR 60.635(c)] Reporting Requirements 1.2.5.1. The permittee subject to the provisions of this subpart shall comply with the requirements of §60.636(b) and (c) in addition to the requirements of §60.487 of subpart VV. [40 CFR 60.636(a)] 1.2.5.2. The permittee subject to the provisions of this subpart shall submit semiannual reports to the Administrator beginning six months after the initial startup date. [40 CFR 60.636(a) and 40 CFR 60.487(a)] 1.2.5.3. All semiannual reports to the Administrator shall include the following information, summarized from the information in §60.636(c) and §60.487(i-vi) of subpart VV: [40 CFR 60.636(c)] 1.2.5.3.1. Process unit identification 1.2.5.3.2. For each month during the semiannual reporting period, [40 CFR 60.636(c) and 40 CFR 60.487(c)(1)] 1.2.5.3.2.1. Number of valves for which leaks were detected as described in §60.482-7(b) or §60.483-2 of subpart VV, 1.2.5.3.2.2. Number of valves for which leaks were not repaired as required in §60.482-7(d)(1) of subpart VV, 1.2.5.3.2.3. Number of pumps for which leaks were detected as described in §60.482-2(b), (d)(4)(ii)(A) or (B), or (d)(5)(iii) of subpart VV, 1.2.5.3.2.4. Number of pumps for which leaks were not repaired as required in §60.482-2(c)(1) and (d)(6) of subpart VV. 1.2.5.3.2.5. Number of compressors for which leaks were detected as described in §60.482-3(f) of subpart VV, 1.2.5.3.2.6. Number of compressors for which leaks were not repaired as required in §60.482-3(g)(1) of subpart VV, [40 CFR 60.636(c) and 40 CFR 60.487(c)(2)(i)-(vi)] 1.2.5.3.2.7. Number of pressure relief devices for which leaks were detected as required in §60.633(b)(2), [40 CFR 60.636(c)(1)] 32 1.2.5.3.2.8. Number of pressure relief devices for which leaks were not repaired as required in §60.633(b)(3), and [40 CFR 60.636(c)(2)] 1.2.5.3.2.9. The facts that explain each delay of repair and, where appropriate, why a process unit shutdown was technically infeasible. [40 CFR 60.636(c) and 40 CFR 60.487(c)(2)(vii)] 1.2.5.3.3. Dates of process unit shutdowns which occurred within the semiannual reporting period. [40 CFR 60.636(c) and 40 CFR 60.487(c)(3)] 1.2.5.3.4. Revisions to items reported in the initial semiannual report if changes have occurred since the initial report or subsequent revisions to the initial report. [40 CFR 60.636(c) and 40 CFR 60.487(c)(4)] 1.2.5.4. The permittee electing to comply with the provisions of §§60.483-1 or 60.483-2 of subpart VV shall notify the Administrator of the alternative standard selected 90 days before implementing either of the provisions. [40 CFR 60.636(c) and 40 CFR 60.487(d)] 1.2.5.5. The permittee shall report the results of all performance tests in accordance with §60.8 of the General Provisions. The provisions of §60.8(d) do not apply to affected facilities subject to the provisions of this subpart except that an owner or operator must notify the Administrator of the schedule for the initial performance tests at least 30 days before the initial performance tests. [40 CFR 60.636(c) and 40 CFR 60.487(e)] 1.2.5.6. The requirements of paragraphs 60.487(a) through 60.487(c) of subpart VV to remain in force until and unless EPA, in delegating enforcement authority to a State under section 111(c) of the Act, approves reporting requirements or an alternative means of compliance surveillance adopted by such State. In that event, affected sources within the State will be relieved of the obligation to comply with the requirements of paragraphs 60.487(a) through 60.487(c) of subpart VV, provided that they comply with the requirements established by the State. [40 CFR 60.636(c) and 40 CFR 60.487(f)] 1.3. 40 CFR Part 60, Subpart LLL – Standards of Performance for SO2 Emissions from Onshore Natural Gas Processing Plants [40 CFR 60.640 – 60.648 and RAC 3-102] The permittee shall meet all applicable requirements of 40 CFR Part 60 Subpart A and LLL as they apply to each affected source as defined at 40 CFR 60.640. 1.3.1. Recordkeeping and Reporting Requirements 1.3.1.1. To certify that the facility is exempt from the control requirements of these standards, the permittee shall keep, for the life of the facility, an analysis 33 demonstrating that the facility’s design capacity is less than 2 LT/D of hydrogen sulfide expressed as sulfur. [40 CFR 60.640(b) and 60.647(c)] 1.4. 40 CFR Part 60, Subpart KKKK – Standards of Performance for Stationary Combustion Turbines [40 CFR 60.4300 – 60.4420 and RAC 3-102] The permittee shall meet all applicable requirements of 40 CFR Part 60 Subpart A and KKKK as they apply to each affected source as defined at 40 CFR 60.4305. 1.4.1. Affected Sources The following are affected sources under this subpart: • • • • • Unit 27 – Solar Mars 100 natural gas-fired turbine Unit 28 – Solar Titan 130 natural gas-fired turbine Unit 29 – Solar Taurus 70 natural gas-fired turbine Unit 30 – Solar Titan 130 natural gas-fired turbine Unit 31 – Solar Titan 130 natural gas-fired turbine [40 CFR 60.4305] 1.4.2. Emission Standards 1.4.2.1. Units 27, 28, 29, 30, and 31 shall limit NOx emissions to 25 ppm at 15% O2 or 150 ng/J of useful output (1.2 lb/MWh). [40 CFR 60.4320 and Table 1] 1.4.2.2. If the permittee has two or more turbines that are connected to a single generator, each turbine must meet the emission limits for NOx. [40 CFR 60.4320(b)] 1.4.2.3. The permittee must not cause to be discharged into the atmosphere from the subject stationary turbines any gases which contain SO2 in excess of 110 nanograms per Joule (ng/J)(0.90 pounds per megawatt-hour (lb/MWh)) gross output. 1.4.2.4. The permittee must not burn in the subject stationary turbines any fuel which contains total potential sulfur emissions in excess of 26 ng SO2/J (0.060 lb SO2/MMBtu) heat input. If the turbine(s) simultaneously fires multiple fuels, each fuel must meet this requirement. [40 CFR 60.4330(a)] 1.4.3. General Requirements 1.4.3.1. The permittee must operate and maintain the subject stationary turbines, air pollution control equipment, and monitoring equipment in a manner consistent with good air pollution control practices for minimizing emissions at all times including during startup, shutdown, and malfunction. 34 1.4.3.2. When an affected unit with heat recovery utilizes a common steam header with one or more combustion turbines, the owner or operator shall either: 1.4.3.2.1. Determine compliance with the applicable NOx emission limits by measuring the emissions combined with the emissions from other unit(s) utilizing the common heat recovery unit; or 1.4.3.2.2. Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined gross energy output from the heat recovery unit for each of the affected combustion turbines. The Administrator may approve such demonstrated substitute methods for apportioning the combined gross energy output measured at the steam turbine whenever the demonstration ensures accurate estimation of emissions related under this part. [40 CFR 60.4333] 1.4.4. Monitoring Requirements 1.4.4.1. If not using water or steam injection to control NOx emissions, the permittee must perform annual performance tests in accordance with §60.4400 to demonstrate continuous compliance. If the NOx emission result from the performance test is less than or equal to 75 percent of the NOx emission limit for the turbine, the permittee may reduce the frequency of subsequent performance tests to once every 2 years (no more than 26 calendar months following the previous performance test). If the results of any subsequent performance tests exceed 75 percent of the NOx emission limit for the turbine, the permittee must resume annual performance tests. [40 CFR 60.4340] 1.4.4.2. The permittee may elect not to monitor the total sulfur content of the fuel combusted in the turbines if the fuel is demonstrated not to exceed potential sulfur emissions of 26 ng SO2/J (0.060 lb SO2/MMBtu) heat input. The permittee must use one of the following sources of information to make the required demonstration: 1.4.4.2.1. The fuel quality characteristics in a current, valid purchase contract, tariff sheet or transportation contract for the fuel, specifying that the maximum total sulfur content for oil use is 0.05 weight percent (500 ppmw), the total sulfur content for natural gas use is 20 grains of sulfur or less per 100 standard cubic feet, has the potential sulfur emissions of less than 26 ng SO2/J (0.060 lb SO2/MMBtu) heat input; or 1.4.4.2.2. Representative fuel sampling data which show that the sulfur content of the fuel does not exceed 26 ng SO2/J (0.060 lb SO2/MMBtu) heat input. At a minimum, the amount of fuel sampling data specified in section 2.3.1.4 or 2.3.2.4 of appendix D to 40 CFR Part 75 is required. [40 CFR 60.4365] 35 1.4.5. Testing Requirements 1.4.5.1. The permittee must conduct an initial performance test, as required by §60.8 for measuring NOx from Units 27, 28, 29, 30, and 31 within 60 days after achieving the maximum production rate at which the turbines will be operated, but not later than 180 days after initial startup of the turbines, except as specified by §60.8(a)(1), (a)(2), (a)(3), and (a)(4). Subsequent NOx performance tests shall be conducted on an annual basis (no more than 14 calendar months following the previous performance test). The permittee must use the methodology referenced in either §60.4400(1)(i) or 60.4400(1)(ii) to conduct the performance tests. [40 CFR 60.4400(a), and 40 CFR 60.8] 1.4.6. Reporting Requirements 1.4.6.1. For each affected unit required to continuously monitor parameters or emissions, or to periodically determine fuel sulfur content under this subpart, the permittee must submit reports of excess emissions and monitor downtime, in accordance with §60.7(c). Excess emissions must be reported for all periods of unit operation, including start-up, shutdown, and malfunction. 1.4.6.2. For each affected unit that performs annual performance tests in accordance with §60.4340(a), you must submit a written report or the results of each performance test before the close of business on the 60th day following completion of the performance test. [40 CFR 60.4375] 1.4.6.3. If the permittee chooses to monitor the sulfur content of the fuel, excess emissions and monitoring downtime are defined in §60.4385. [40 CFR 60.4385] 1.4.6.4. All reports required under §60.7(c) must be postmarked by the 30th day following the end of each 6-month period. [40 CFR 60.4395] 1.5. 40 CFR Part 60, Subpart OOOO – Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution [40 CFR 60.5360 – 60.5430 and RAC 3102] The permittee shall meet all applicable requirements of 40 CFR Part 60 Subpart A and OOOO as they apply to each affected source as defined at 40 CFR 60.5365. 1.5.1. Standards for Reciprocating Compressors For each affected reciprocating compressor, the permittee must comply with the following standards: 1.5.1.1. The permittee must replace the reciprocating compressor rod packing on each affected emission unit using one of the following options: 36 1.5.1.1.1. Before the compressor has operated for 26,000 hours. The number of hours of operation must be continuously monitored beginning upon initial startup of the reciprocating compressor affected facility, or the date of the most recent reciprocating compressor rod packing replacement, whichever is later. 1.5.1.1.2. Prior to 36 months from the date of the most recent rod packing replacement, or 36 months from the date of startup for a new reciprocating compressor for which the rod packing has not yet been replaced. [40 CFR 60.5385] [Explanatory note – The permittee has represented that the compliance option for reciprocating compressors at this facility will be rod packing replacement and not an emissions collection system. Therefore, the requirements for an emissions collection system are not incorporated into this permit] 1.5.2. Standards for Affected Process Units For each affected process unit, the permittee must comply with the following standards: 1.5.2.1. The permittee must comply with the requirements of §§60.482-1a(a), (b), and (d), 60.482-2a, and 60.482-4a through 60.482-11a of subpart VVa, except as provided in 60.5401. 1.5.2.2. The permittee may apply to the Administrator for permission to use an alternative means of emission limitation that achieves a reduction in emissions of VOC at least equivalent to that achieved by the controls required in this subpart according to the requirements of §60.5402 of this subpart. 1.5.2.3. The permittee must comply with the provisions of §60.485a of subpart VVa, of this part except as provided in 60.5400(f). 1.5.2.4. The permittee must comply with the provisions of §§60.486a and 60.487a of subpart VVa, of this part except as provided in 60.5401, 60.5421, and 60.5422. 1.5.2.5. The permittee must use the following provision instead of §60.485a(d)(1) of subpart VVa: each piece of equipment is presumed to be in VOC service or in wet gas service unless an owner or operator demonstrates that the piece of equipment is not in VOC service or in wet gas service. For a piece of equipment to be considered not in VOC service, it must be determined that the VOC content can be reasonably expected never to exceed 10.0 percent by weight. For a piece of equipment to be considered in wet gas service, it must be determined that it contains or contacts the field gas before the extraction step in the process. For purposes of determining the percent VOC content of the process fluid that is contained in or contacts a piece of equipment, procedures that conform to the methods described is ASTM E169-93, E168-92, or E260-96 (incorporated by reference as specified in §60.17) must be used. [40 CFR 60.5400] 37 1.5.3. Exceptions The permittee may comply with the following exceptions to the provisions of §60.5400(a) and (b). 1.5.3.1. Each pressure relief device in gas/vapor service may be monitored quarterly and within 5 days after each pressure release to detect leaks by the methods specified on §60.485a(b) of subpart VVa, except as provided in §60.5400(c) and in 60.5401(b)(4) of this section, and §60.482-4a(a) through (c) of subpart VVa. 1.5.3.1.1. If an instrument reading of 500 ppm or greater is measured, a leak is detected. 1.5.3.1.1.1. When a leak is detected, it must be repaired as soon as practicable, but no later than 15 calendar days after it is detected, except as provided in §60.482-9a of subpart VVa. 1.5.3.1.1.2. A first attempt at repair must be made no later than 5 calendar days after each leak is detected. 1.5.3.2. Sampling connection systems are exempt from the requirements of §60.482-5a of subpart VVa. 1.5.3.3. An owner or operator may use the following provisions instead of §60.485a(e) of subpart VVa: 1.5.3.3.1. Equipment is in heavy liquid service if the weight percent evaporated is 10 percent at 150°C (302°F) as determined by ASTM Method D86-96 (incorporated by reference as specified in §60.17). 1.5.3.3.2. Equipment is in light liquid service if the weight percent evaporated is greater than 10 percent at 150°C (302°F) as determined by ASTM Method D86-96 (incorporated by reference as specified in §60.17). 1.5.3.4. An owner or operator may use the following provisions instead of §60.485a(b)(2) of subpart VVa: a calibration drift assessment shall be performed, at a minimum, at the end of each monitoring day. Check the instrument using the same calibration gas(es) that were used to calibrate the instrument before use. Follow the procedures specified in Method 21 of appendix A-7 of this part, Section 10.1, except do not adjust the meter readout to correspond to the calibration gas value. Record the instrument for each scale used as specified in §60.486a(e)(8) of subpart VVa. Divide these readings by the initial calibration values for each scale and multiply by 100 to express the calibration drift as a percentage. If any calibration drift assessment shows a negative drift of more than 10 percent from the initial calibration value, then all equipment monitored multiplied by 100 minus the percent of negative drift/divided by 100) must be re-monitored. If any calibration drift assessment shows a positive drift of more than 10 percent from the initial calibration value, then, at the owner/operator’s discretion, all equipment since the last calibration with the instrument readings above the appropriate leak definition 38 and below the leak definition multiplied by (100 plus the percent of positive drift/divided by 100) may be re-monitored. [40 CFR 60.5401] 1.5.4. Initial Compliance 1.5.4.1. The initial compliance period for the affected reciprocating compressors begins upon initial startup and ends no later than one year after the initial startup date. During the initial compliance period, for each affected emission unit, the permittee shall: 1.5.4.1.1. Continuously monitor the number of hours of operation or track the number of months since the last rod packing replacement. 1.5.4.1.2. Submit an initial annual report no later than 90 days after the end of the initial compliance period as required in 60.5420(b) of this section and maintain records as specified in 60.5420(c)(3) of this section. [40 CFR 60.5410(c)] 1.5.4.2. For affected facilities at onshore natural gas processing plants, initial compliance with the VOC requirements is demonstrated if you are in compliance with the requirements of 60.5400. [40 CFR 60.5410(f)] 1.5.5. Continuous Compliance 1.5.5.1. For each affected reciprocating compressor, the permittee must demonstrate continuous compliance as follows: 1.5.5.1.1. Continuously monitor the number of hours of operation for each reciprocating compressor or track the number of months since the date of the most recent reciprocating compressor rod packing replacement. 1.5.5.1.2. Replace the reciprocating compressor rod packing before the total number of hours of operation reaches 26,000 hours or the number of months since the most recent rod packing replacement reaches 36 months. 1.5.5.1.3. Submit annual reports as required in 60.5420(b) and maintain records as required in 60.5420(c)(3). [40 CFR 60.5415(c)] 1.5.5.2. For affected facilities at onshore natural gas processing plants, continuous compliance with VOC requirements is demonstrated if you are in compliance with the requirements of 60.5400. [40 CFR 60.5415(f)] 39 1.5.6. Notifications, Reporting, and Recordkeeping 1.5.6.1. The permittee is not required to submit the notifications required in §60.7(a)(1), (3), and (4) for affected reciprocating compressors. [40 CFR 60.5420(a)(1)] 1.5.6.2. After the initial compliance period, the permittee must submit annual reports on April 1st of each year and covering the previous twelve-month period from January 1st through the December 31st. The annual reports shall contain the following: 1.5.6.2.1. The company name and address of the affected facility. 1.5.6.2.2. An identification of each affected facility being included in the annual report. 1.5.6.2.3. Beginning and ending dates of the reporting period. 1.5.6.2.4. A certification by a certifying official of truth, accuracy, and completeness. This certification shall state that, based on information and belief formed after reasonable inquiry, the statements and information in the document are true, accurate, and complete. [40 CFR 60.5420(b)] 1.5.6.2.5. For each affected reciprocating compressor, the information as follows: 1.5.6.2.5.1. The cumulative number of hours of operation or the number of months since initial startup or since the previous reciprocating compressor rod packing replacement. 1.5.6.2.5.2. Records of deviations from the requirements of this section that occurred during the reporting period. [40 CFR 60.5420(b)(4)] 1.5.6.2.6. For each affected process unit subject to VOC requirements, the permittee shall submit semiannual reports to the Administrator on April and October 1st of each year. The initial semiannual report shall contain the following information: 1.5.6.2.6.1. Process unit identification 1.5.6.2.6.2. Number of valves subject to the requirements of §60.482-7a of subpart VVa, excluding those valves designated for no detectable emissions under the provisions of §60.487a(f) of subpart VVa. 1.5.6.2.6.3. Number of pumps subject to the requirements of §60.482-2a of subpart VVa, excluding those pumps designated for no detectable emissions under the provisions of §60.482-2a(e) of subpart VVa and those pumps complying with §60.482-2a(f) of subpart VVa. 40 1.5.6.2.6.4. Number of connectors subject to the requirements of §60.482-11a of subpart VVa. 1.5.6.2.6.5. Number of pressure relief devices subject to the requirements of §60.5401(b) except for those pressure relief devices designated for no detectable emissions under the provisions of §60.482-4a(a) and those pressure relief devices complying with §60.482-4a(c) of subpart VVa. [40 CFR 60.5422(b), 40 CFR 60.487a(b) and RAC 2-110(7)] 1.5.6.2.7. All semiannual reports to the Administrator shall include the following information for each month, summarized from the information in §60.486a of subpart VVa: Number of valves for which leaks were detected as described in §60.482-7a(b) or §60.483-2a of subpart VVa. 1.5.6.2.7.2. Number of valves for which leaks were not repaired as required in §60.482-7a(d)(1) of subpart VVa. 1.5.6.2.7.3. Number of pumps for which leaks were detected as described in §60.482-2a(b), (d)(4(ii)(A) or (B), or (d)(5)(iii) of subpart VVa. 1.5.6.2.7.4. Number of pumps for which leaks were not repaired as required in §60.482-2a(c)(1) and (d)(6) of subpart VVa. 1.5.6.2.7.5. Number of connectors for which leaks were detected as described in §60.482-11a(b) of subpart VVa. 1.5.6.2.7.6. Number of connectors for which leaks were not repaired as required in §60.482-11a(d) of subpart VVa. 1.5.6.2.7.7. Number of pressure relief devices for which leaks were detected as required in §60.5401(b)(2). 1.5.6.2.7.8. Number of pressure relief devices for which leaks were not repaired as required in §60.5401(b)(3) [40 CFR 60.5422(c) and 60.487a(c)] 1.5.6.3. 1.5.6.2.7.1. The permittee must maintain the following records and the records specified in 40 CFR §60.7(f) onsite or at the nearest local field office for at least 5 years. [40 CFR 60.5420(c)] 1.5.6.3.1. The cumulative number of hours of operation or number of months since initial startup or the previous replacement of the reciprocating compressor rod packing. 1.5.6.3.2. The date and time of each reciprocating compressor rod packing replacement. 41 1.5.6.3.3. Records of deviations in cases where the reciprocating compressor was not operated in compliance with the requirements specified in §60.5385. [40 CFR 60.5420(c)(3)] 1.5.6.3.4. The permittee may comply with the recordkeeping requirements for the affected facilities in one recordkeeping system if the system identifies each record by each facility. [40 CFR 60.5421(a) and 40 CFR 60.486a(a)(2)] 1.5.6.3.5. The permittee shall record the following information for each monitoring event required by §§60.482-2a, 60.482-3a, 60.482-7a, 60.482-8a, 60.48211a, and 60.483-2a of subpart VVa: 1.5.6.3.5.1. Monitoring instrument identification 1.5.6.3.5.2. Operator identification 1.5.6.3.5.3. Equipment identification 1.5.6.3.5.4. Date of monitoring 1.5.6.3.5.5. Instrument reading [40 CFR 60.5421(a) and 40 CFR 60.486a(a)(3)] 1.5.6.3.6. When each leak is detected as specified in §§60.482-2a, 60.482-3a, 60.4827a, 60.482-8a, 60.482-11a, 60.483-2a of subpart VVa, and 60.5401(b)(2) (for pressure relief devices) the following requirements apply: 1.5.6.3.6.1. A weatherproof and readily visible identification, marked with the equipment identification number, shall be attached to the leaking equipment 1.5.6.3.6.2. The identification on a valve may be removed after it has been monitored for 2 successive months as specified in §60.482-7a(c) of subpart VVa and no leak has been detected during those 2 months. 1.5.6.3.6.3. The identification on a connector may be removed after it has been monitored as specified in §60.482-11a(b)(3)(iv) of subpart VVa and no leak has been detected during that monitoring. 1.5.6.3.6.4. The identification on equipment, except on a valve or connector, may be removed after it has been repaired. [40 CFR 60.5421(b)(1) and 40 CFR 60.486a(b)] 1.5.6.3.7. When each leak is detected as specified in §§60.482-2a, 60.482-3a, 60.4827a, 60.482-8a, 60.482-11a, 60.483-2a of subpart VVa, and 60.5401(b)(2) 42 (for pressure relief devices), the following information shall be recorded in a log and shall be kept for 2 years in a readily accessible location: 1.5.6.3.7.1. The instrument and operator identification numbers and the equipment identification number, except when indications of liquids dripping from a pump are designated as a leak. 1.5.6.3.7.2. The date the leak was detected and the dates of each attempt to repair the leak. 1.5.6.3.7.3. Repair methods applied in each attempt to repair the leak. 1.5.6.3.7.4. Maximum instrument reading measured by Method 21 of appendix A-7 of 40 CFR part 60 at the time the leak is successfully repaired or determined to be nonrepairable, except when a pump is repaired by eliminating indications of liquids dripping. 1.5.6.3.7.5. “Above 500 ppm” if the maximum instrument reading measured by the methods specified in paragraph (a) of this section after each repair attempt is 500 ppm or greater (for pressure relief devices only). 1.5.6.3.7.6. “Repair delayed” and the reason for the delay if a leak is not repaired within 15 calendar days after discovery of the leak. 1.5.6.3.7.7. The signature of the owner or operator (or designate) whose decision it was that repair could not be effected without a process shutdown. 1.5.6.3.7.8. The expected date of successful repair of the leak if a leak is not repaired within 15 days. 1.5.6.3.7.9. Dates of process unit shutdowns that occur while the equipment is unrepaired. 1.5.6.3.7.10. The date of successful repair of the leak 1.5.6.3.7.11. A list of identification numbers for equipment that are designated for no detectable emissions under the provisions of §60.482-4a(a) of subpart VVa. The designation of equipment subject to the provisions of §60.482-4a(a) of subpart VVa must be signed by the owner or operator. [40 CFR 60.5421(b)(2) and 40 CFR 60.486a(c)] 1.5.6.3.8. The following information pertaining to all equipment subject to the requirements in §§60.482-1a to 60.482-11a of subpart VVa shall be recorded in a log that is kept in a readily accessible location: 43 1.5.6.3.8.1. A list of identification numbers for equipment subject to the requirements of this subpart. 1.5.6.3.8.2. A list of identification numbers for equipment that are designated for no detectable emissions under the provisions of §§60.482-2a(e), 60.482-3a(i), and 60.482-7a(f) of subpart VVa. 1.5.6.3.8.2.1. The designation of equipment as subject to the requirements of §60.482-2a(e), §60.482-3a(i), or §60.482-7a(f) of subpart VVa, shall be signed by the owner or operator. Alternatively, the owner or operator may establish a mechanism with their permitting authority that satisfies this requirement. 1.5.6.3.8.3. A list of equipment identification numbers for pressure relief devices required to comply with §60.482-4a of subpart VVa. 1.5.6.3.8.4. The dates of each compliance test as required in §§60.482-2a(e), 60.482-3a(i), 60.482-4a, and 60.482-7a(f) of subpart VVa. 1.5.6.3.8.4.1. The background level measured during each compliance test. 1.5.6.3.8.4.2. The maximum instrument reading measured at the equipment during each compliance test. [40 CFR 60.5416(b)] 1.5.6.3.8.5. A list of identification numbers for equipment in vacuum service. 1.5.6.3.8.6. A list of identification numbers for equipment that the owner or operator designates as operating in VOC service less than 300 hr/yr in accordance with §60.482-1a(e) of subpart VVa, a description of the conditions under which the equipment is in VOC service, and rationale supporting the designation that it is in VOC service less than 300 hr/yr. 1.5.6.3.8.7. The date and results of the weekly visual inspection for indications of liquids dripping from pumps in light liquid service. 1.5.6.3.8.8. Records of the information specified in paragraphs 60.486a(e)(8)(i) through (vi) for monitoring instrument calibrations conducted according to sections 8.1.2 and 10 of Method 21 of appendix A-7 of this part and §60.485a(b) of subpart VVa. 1.5.6.3.8.8.1. Date of calibration and initials of operator performing the calibration. 1.5.6.3.8.8.2. Calibration gas cylinder identification, certification date, and certified concentration. 1.5.6.3.8.8.3. Instrument scale(s) used. 44 1.5.6.3.8.8.4. A description of any corrective action taken if the meter readout could not be adjusted to correspond to the calibration gas value in accordance with section 10.1 of Method 21 of appendix A-7 of this part. 1.5.6.3.8.8.5. Results of each calibration drift assessment required by §60.485a(b)(2) (i.e., instrument reading for calibration at end of monitoring day and the calculated percent difference from the initial calibration value) of subpart VVa. 1.5.6.3.8.8.6. If an owner or operator makes their own calibration gas, a description of the procedure used. [40 CFR 60.5401(g) and 40 CFR 60.486a(e)(8)(i)-(vi)] 1.5.6.3.8.9. The connector monitoring schedule for each process unit as specified in §60.482-11a(b)(3)(v) of subpart VVa. 1.5.6.3.8.10. Records of each release from a pressure relief device subject to §60.482-4a of subpart VVa. [40 CFR 60.5421(b) and 40 CFR 60.486a(e)] 1.5.6.3.9. The following information pertaining to all valves subject to the requirements of §60.482-7a(g) and (h), all pumps subject to the requirements of §60.482-2a(g), and all connectors subject to the requirements of §60.482-11a(e) of subpart VVa shall be recorded in a log that is kept in a readily accessible location: 1.5.6.3.9.1. A list of identification numbers for valves, pumps, and connectors that are designated as unsafe-to-monitor, an explanation for each valve, pump, or connector stating why the valve, pump, or connector is unsafe-to-monitor, and the plan for monitoring each valve, pump, or connector. 1.5.6.3.9.2. A list of identification numbers for valves that are designated as difficult-to-monitor, an explanation for each valve stating why the valve is difficult-to-monitor, and the schedule for monitoring each valve. [40 CFR 60.5421(a) and 40 CFR 60.486a(f)(1)-(2)] 1.5.6.3.10. The following information shall be recorded for valves complying with §60.483-2a of subpart VVa: 1.5.6.3.10.1. A schedule of monitoring. 1.5.6.3.10.2. The percent of valves found leaking during each monitoring period. [40 CFR 60.5400 and 40 CFR 60.486a(g)] 45 1.5.6.3.11. The following information shall be recorded in a log that is kept in a readily accessible location: 1.5.6.3.11.1. Design criterion required in §§60.482-2a(d)(5) and 60.482-3a(e)(2) of subpart VVa and explanation of the design criterion; and 1.5.6.3.11.2. Any changes to this criterion and the reasons for the changes. [40 CFR 60.5420 and 40 CFR 60.486a(h)] 1.5.6.3.12. The following information shall be recorded in a log that is kept in a readily accessible location for use in determining exemptions as provided in §60.480a(d) of subpart VVa: 1.5.6.3.12.1. An analysis demonstrating the design capacity of the affected facility, 1.5.6.3.12.2. A statement listing the feed or raw materials and products from the affected facilities and an analysis demonstrating whether these chemicals are heavy liquids or beverage alcohol, and 1.5.6.3.12.3. An analysis demonstrating that equipment is not in VOC service. [40 CFR 60.5400(f) and 40 CFR 60.486a(i)] 1.5.6.3.13. Information and data used to demonstrate that a piece of equipment is not in VOC service shall be recorded in a log that is kept in a readily accessible location. [40 CFR 60.5400(f) and 40 CFR 60.486a(j)] 1.5.6.3.14. The provisions of §60.7(b) and (d) do not apply to affected facilities subject to this subpart. [40 CFR 60.5400 and 40 CFR 60.486a(k)] 1.6. 40 CFR Part 60, Subpart OOOOa – Standards of Performance for Crude Oil and Natural Gas Facilities [40 CFR 60.5360a – 60.5499a, RAC 3-102] The permittee shall meet all applicable requirements of 40 CFR Part 60 Subpart A and OOOOa as they apply to each affected source as defined at 60.5365a. 1.6.1. Standards for Affected Process Units For each affected process unit, the permittee must comply with the following standards: 1.6.1.1. The permittee must comply with the requirements of §§60.482-1a(a), (b), and (d), 60.482-2a, and 60.482-4a through 60.482-11a of subpart VVa, except as provided in 60.5401a. 46 1.6.1.2. The permittee may apply to the Administrator for permission to use an alternative means of emission limitation that achieves a reduction in emissions of methane and VOC at least equivalent to that achieved by the controls required in this subpart according to the requirements of §60.5402a of this subpart. 1.6.1.3. The permittee must comply with the provisions of §60.485a of subpart VVa, except as provided in 60.5400a(f). 1.6.1.4. The permittee must comply with the provisions of §§60.486a and 60.487a of subpart VVa, except as provided in 60.5401a, 60.5421a, and 60.5422a. 1.6.1.5. The permittee must use the following provision instead of §60.485a(d)(1) of subpart VVa: each piece of equipment is presumed to be in VOC service or in wet gas service unless an owner or operator demonstrates that the piece of equipment is not in VOC service or in wet gas service. For a piece of equipment to be considered not in VOC service, it must be determined that the VOC content can be reasonably expected never to exceed 10.0 percent by weight. For a piece of equipment to be considered in wet gas service, it must be determined that it contains or contacts the field gas before the extraction step in the process. For purposes of determining the percent VOC content of the process fluid that is contained in or contacts a piece of equipment, procedures that conform to the methods described is ASTM E169-93, E168-92, or E260-96 (incorporated by reference as specified in §60.17) must be used. [40 CFR 60.5400a] 1.6.2. Exceptions The permittee may comply with the following exceptions to the provisions of §60.5400a(a) and (b). 1.6.2.1. Each pressure relief device in gas/vapor service may be monitored quarterly and within 5 days after each pressure release to detect leaks by the methods specified on §60.485a(b) except as provided in §60.5400a(c) and in 60.5401a(b)(4) of this section, and §60.482-4a(a) through (c) of subpart VVa. 1.6.2.1.1. If an instrument reading of 500 ppm or greater is measured, a leak is detected. 1.6.2.1.1.1. When a leak is detected, it must be repaired as soon as practicable, but no later than 15 calendar days after it is detected, except as provided in §60.482-9a of subpart VVa. 1.6.2.1.1.2. A first attempt at repair must be made no later than 5 calendar days after each leak is detected. 1.6.2.2. Sampling connection systems are exempt from the requirements of §60.482-5a of subpart VVa. 47 1.6.2.3. An owner or operator may use the following provisions instead of §60.485a(e) of subpart VVa: 1.6.2.3.1. Equipment is in heavy liquid service if the weight percent evaporated is 10 percent at 150°C (302°F) as determined by ASTM Method D86-96 (incorporated by reference as specified in §60.17). 1.6.2.3.2. Equipment is in light liquid service if the weight percent evaporated is greater than 10 percent at 150°C (302°F) as determined by ASTM Method D86-96 (incorporated by reference as specified in §60.17). 1.6.2.4. An owner or operator may use the following provisions instead of §60.485a(b)(2) of subpart [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/tribal%3Asouthern_ute%3A8e7a373f26ede830. Public record. Not legal advice.