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Home My WebLink About20180488.tiffoa-al= 15a Department oaf Public Health Er Emir Dedicated to protecting and improving the health and environment of the people of Colorado Weld County - Clerk to the Board 1150 0 St PO Box 758 Greeley, CO 80632 February 8, 2018 Dear Sir or Madam: On February 15, 2018, the Air Pollution Control Division will begin a 30 -day public notice period for Kerr McGee Gathering, LLC - Latham Gas Plant. A copy of this public notice and the public comment packet are enclosed. Thank you for assisting the Division by posting a copy of this public comment packet in your office. Public copies of these documents are required by Colorado Air Quality Control Commission regulations. The packet must be available for public inspection for a period of thirty (30) days from the beginning of the public notice period. Please send any comment regarding this public notice to the address below. Colorado Dept. of Public Health 8 Environment APCD-SS-B1 4300 Cherry Creek Drive South Denver, Colorado 80246-1530 Attention: Clara Gonzales Regards, Clara Gonzales Public Notice Coordinator Stationary Sources Program Air Pollution Control Division Enclosure 4300 Cherry Creek Drive S., Denver, CO 80246-1530 P 303-692-2000 www.colorado.gov/cdphe John W. Hickenlooper, Governor I Larry Wolk, MD, MSPH, Executive Director and Chief Medical Officer - - Cc. PL (M,,A�//7P) 1 -IL (P 8), ' J(ER/c14/Jr/4/eK) O Z 2018-0488 Air Pollution Control Division Notice of a Proposed Project or Activity Warranting Public Comment Website Title: Kerr McGee Gathering, LLC - Latham Gas Plant - Weld County Notice Period Begins: February 15, 2018 Notice is hereby given that an application for a proposed project or activity has been submitted to the Colorado Air Pollution Control Division for the following source of air pollution: Applicant: Kerr McGee Gathering, LLC Facility: Latham Gas Plant Natural Gas Processing Plant Section 2, Township 3N, Range 66W Weld County The proposed project or activity is as follows: The operator is requesting permit coverage for 3 natural gas heaters, an MDEA amine unit, open flare controlling maintenance activity, and fugitive equipment leaks. The open flare is granted 98% control. The Division has determined that this permitting action is subject to public comment per Colorado Regulation No. 3, Part B, Section III.C due to the following reason(s): • permitted emissions exceed public notice threshold values in Regulation No. 3, Part B, Section III.C.1.a (25 tpy in a non -attainment area and/or 50 tpy in an attainment area) • the source is requesting a federally enforceable limit on the potential to emit in order to avoid other requirements The Division has made a preliminary determination of approval of the application. A copy of the application, the Division's analysis, and a draft of Construction Permit 17WE0398 have been filed with the Weld County Clerk's office, A copy of the draft permit and the Division's analysis are available on the Division's website at https://www.colorado.gov/pacific/cdphe/air-permit-public-notices The Division hereby solicits submission of public comment from any interested person concerning the ability of the proposed project or activity to comply with the applicable standards and regulations of the Commission. The Division will receive and consider written public comments for thirty calendar days after the date of this Notice. Any such comment must be submitted in writing to the following addressee: Christian Lesniak Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South, APCD-SS-B1 Denver, Colorado 80246-1530 cdphe.cornmentsapcd@state.co.us Facility Name: Plant AIRS ID: Physical Location: County: General Description: Latham Gas Plant 12319F22 SEC 2 T3N R67W Weld County Natural Gas Processing Plant Equipment or activity subject to this permit: Facility Equipment ID AIRS Point Description Amine regen 1 001 Amine regeneration gas heater equipped with ultra -low NOx burners. The heater is design rated for an input rate of 55.0 MMBtu/hr. This heater is fueled by natural gas. T1 mole sieve heater 002 Mole sieve regeneration gas heater equipped with ultra -low NOx burners.` The heater is design rated for an input rate of 18.36 MMBtu/hr. This heater is fueled by natural gas: T2 mole sieve heater 003 Mole sieve regeneration gas heater equipped with ultra -low NOx burners. The heater is design rated for an input rate of 18:36 MMBtu/hr. This heater is fueled by natural gas.- A-1 004 Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 153 MMscf/day This emissions unit is equipped with Three (3) amine recirculation pumps with a total limited capacity of 600 gallons per minute of lean amine. This system includes two (2) natural gas/amine contactors, a flash tank, still vent, and an indirect fired hot oil amine regeneration reboiler (point 001). Still vent emissions will be routed directly to the thermal oxidizer. The thermal oxidizer has a minimum destruction and removal efficiency (DRE) of 99%. The flash tank emissions are recycled via VRU (process equipment). During allowed. VRU downtime of up to 2190 hours per year, flash tank emissions are routed to the plant process flare (Point 005) and controlled at the granted control percentage for that point. Air assisted, elevated and open tip process flare to control maintenance activities and purging of gas, as well as backup control for amine unit (Point 004). Purge gas prevents low flashback problems to the flare and keeps the flame stable. The purge gas and pilot gas used is sales gas FL -90100 005 and helps the flare maintain a minimum required positive flow through the system. This flare has a minimum flare tip cross sectional area of {TBD) square inches. Flare is granted 98% control efficiency when meeting control requirements as stated in permit. Flare is granted 95% control if unable to comply with control requirements. Fugitive equipment leaks (fugitive VOCs).fttm a natural gas Fugitives 006 processing plant THIS PERMIT IS GRANTED SUBJECT TO ALLRULES AND REGULATIONS OF THE COLORADO AIR QUALITY CONTROL COMMISSION AND THE COLORADO AIR POLLUTION PREVENTION AND CONTROL ACT C.R.S. (25-7-101 et seg), TO THOSE GENERAL TERMS AND CONDITIONS INCLUDED IN THIS DOCUMENT AND THE FOLLOWING SPECIFIC TERMS AND CONDITIONS: REQUIREMENTS TO SELF -CERTIFY FOR FINAL AUTHORIZATION 1. Points 001-005: YOU MUST notify the APCb no later than fifteen days after commencement of the permitted operation or activity by submittina a Notice of Startup (NOS) form bathe APCD. The Notice of Startup (NOS) form may be downloaded online at http://www.colorado.gov/cs/Satellite/CDPHE-AP/CBON/1251596800297. Failure to notify the APCD of startup of the permitted source is a violation of AQCC Regulation No. 3, Part B, Section I II.G.1 and can result in the revocation of the permit. 2 Within one hundred and eighty days (180) after commencement of permitted operation for Points 001-006, compliance with the conditions contained on this permit shall be demonstrated to the Division. It is the permittee's responsibility to self -certify compliance with the conditions. Failure to demonstrate compliance within 180 days for Points 001- 006 may result in revocation of the permit. (Reference: Regulation No. 3, Part B, III.G.2). 3 This permit shall expire if the owner or operator of the source for which this permit was issued: (i) does not commence construction/modification or operation of this source within 18 months after either, the date of issuance of this construction permit or the date on which such construction or activity was scheduled to commence as set forth in the permit application associated with this permit; (ii) discontinues construction for a period of eighteen months or more; (iii) does not complete construction within a reasonable time of the estimated completion date. The Division may grant extensions of the deadline per Regulation No. 3, Part B, III.F.4.b. (Reference: Regulation No. 3, Part B, III.F.4.) Within one hundred and eighty days (180) after commencement of the permitted operation or activity, the operator shall complete all initial compliance testing and sampling as required in this permit and submit the results to the Division as part of the self -certification process. (Reference: Regulation No. 3, Part B, Section Ill.E.) 5. Points 001-003 and 005: The manufacturer, model number and serial number of the subject equipment shall be provided to the Division within fifteen days (15) after commencement of operation. This information shall be included on the Notice of Startup (NOS) submitted for the equipment. (Reference: Regulation No. 3, Part B, III.E.) The operator shall retain the permit final authorization letter issued by the Division after completion of self -certification, with the most current construction permit. This construction permit alone does not provide final authority for the operation of this source. EMISSION LIMITATIONS AND RECORDS DRAFT 7. Emissions of air pollutants shall not exceed the following limitations (as calculated in the Division's preliminary analysis). (Reference: Regulation No. 3, Part B, Section II.A.4) Monthly' Limits: Facility Equipment ID AIRS Point Pounds per Month Emission Type NO, SO2 VOC CO H2S Amine regen 1 001 1637 --- 777 1637 --- Point Ti` mole sieve heater 002 546 --- 260 546 --- Point T2 mole sieve heater 003 546 --- 260 546 --- Point A-1 004 2093 2409 848 2078 13 Point FL -90100 005 644 --- 2627 2882 --- Point Fugitives 006 --- --- 2525 --- --- Fugitive Footnotes: 1: Monthly limits are based on a 31 -day month. Annual Limits: Facility Equipment ID AIRS Point Tons per Year Emission Type NO. SO2 VOC CO H2S Amine regen 1 001 9.6 --- 4.6 9.6 --- Point T1 mole sieve heater 002 3.2 --- 1.5 3.2 --- Point T2 mole sieve heater 003 3.2 --- 1.5 3.2 --- Point A-1 004 12.3 14.2 5.0 12.2 0.1 Point FL -90100 005 3.8 --- 15.5 17.0 --- Point Fugitives 006 --- --- 15.0 --- --- Fugitive See "Notes to Permit Holder #4 for information on emission factors and methods used to calculate limits. During the first twelve (12) months after commencement of operation, compliance with both the monthly and annual emission limitations shall be required. After the first twelve (1 2) months after issuance of this permit, compliance with only the annual limitations shall be required. Compliance with the emission limits in this permit shall be determined by recording the facility's annual criteria pollutant emissions, (including all HAPs above the de-minimis DRAFT reporting level) from each emission unit, on a rolling (12) month total. By the end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate monthly emissions and keep a compliance record on site or at a local field office with site responsibility, for Division review. Rolling twelve-month total limitations shall apply to all emission units, requiring an APEN, at this facility. Point 004: The owner or operator shall calculate uncontrolled VOC, HAP, and H2S emissions on a monthly basis using the most recent measured waste gas sample composition for both still vent and flash tank gas, as specified in the compliance testing and sampling section of this permit, and monthly measured waste gas flow volume for both the still vent and flash tank gas, as specified in the Process Limitations and Records section of this permit. A control efficiency of 99%, based on maintaining the minimum temperature requirements specified in the Operating and Maintenance Requirements section of this permit, shall be applied to the uncontrolled VOC, HAP and H2S emissions. Total actual VOC emissions shall be based on the sum of VOC emissions from the waste gas stream plus VOC due to combustion. 9 Point 006: The operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent extended gas and liquids analyses, as required in the Compliance Testing and Sampling section of this permit. The operator shall maintain records of the results of component counts and sampling events used to calculate actual emissions and the dates that these counts and events were completed. These records shall be provided to the Division upon request. PROCESS LIMITATIONS AND RECORDS 10. This source shall be limited to the following maximum processing rates as listed below. Monthly records of the actual processing rate shall be maintained by the applicant and made available to the Division for inspection upon request. (Reference: Regulation 3, Part B, II.A.4) Process/Consumption Limits Facility Equipment ID AIRS Point Process Parameter Annual Limit Monthly Limits (31 days) Amine re en 1 g 001 Natural Gas Combusted 535.3 MMscf/yr 45.5 MMscf/month T1 mole sieve heater 002 Natural Gas Combusted 178.7 MMscf/yr 15.2 MMscf/month T2 mole sieve heater 003 Natural Gas Combusted 178.7 MMscf/yr 15.2 MMscf/month A-1 004 Natural Gas Throughput 55,845 MMscf/yr 4,743 MMscf/month Still Vent Waste Gas Routed to Thermal Oxidizer 2,796 MMscf/yr 237.5, MMscf/month Combustion of supplemental fuel and pilot fuel at Thermal Oxidizer 236.2 MMscf/yr 20.1 MMscf/month Flash Gas routed to plant flare (Point 005) during VRU downtime _ 24.1 MMscf/yr 2.0 MMscf/month FL -90100 005 Natural gas combustion - Process and Purge Gas 86.7 MMscf/yr 7.37 MMscf/month *Note: The process flare will handle gas from pressure relief valves during upset conditions, emergency vent valves and will handle all blowdowns to the flare during routine maintenance DRAFT activities. During any emergency shutdowns of the thermal oxidizer that qualify as a malfunction per Common Provisions, Section II.E, the gas from the amine unit waste stream shall be sent to these points as well. During the first twelve (12) months after commencement of operation, compliance with both the monthly and annual limitations shall be required. After the first twelve (12) months after issuance of this permit, compliance with only the annual limitations shall be required. Compliance with the annual throughput limits shall be determined on a, rolling twelve (12) month total. By the end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate monthly consumption of natural gas and keep a compliance record on site or at a local field office with site responsibility, for Division review. 11. Points 001-003: The owner or operator must install and maintain an operational non- resettable elapsed flow meter to record the flow rate of the fuel gas combusted. A system that collects, sums, and stores electronic data from a continuous fuel flow meter is considered to be an operational non-resettable elapsed flow meter. The flow rate of the fuel combusted in these natural gas -fired combustion emission units shall be measured and recorded at each inlet. Total monthly fuel use shall be recorded once per month. 12. Point 004: This unit shall be limited to the total maximum lean amine recirculation rate of 600 gallons per minute. The lean amine recirculation rate shall be the summed total of the individually metered amine recirculation rates recorded for each amine contactor. The lean amine recirculation rate for each unit shall be recorded daily in a log maintainedon site and made available to the Division for inspection upon request. (Reference: Regulation No. 3, Part B, II.A.4). 13. Point 004: On a monthly basis, the operator must calculate the emissions of flash gas routed to flare using the most recent flash gas sample and the volume of flash gas to the flare measured by meter. Point 004: The operator shall monitor and record Vapor Recover Unit (VRU) downtime and calculate flash gas volume sent to Point 005 for control. The operator shall use flash gas volumes measured by meter and the most recent flash gas analysis to calculate emissions. Any VRU downtime shall be tracked, recorded, and used to determine compliance, with the allowable hours of VRU downtime. Emissions to the flare shall • be calculated on a monthly basis. These records shall be kept for a period of 5 years. The Vapor Recovery Unit shall be allowed 219O hours of annual downtime 15. Point 004: The volumetric flow rate of the waste gas combusted shall be measured and. recorded using an operational non-resettable elapsed flow meter at the thermal oxidizer. A system that collects, sums, and stores electronic data from a continuous fuel flow meter is considered to be an operational non-resettable elapsed flow meter. Point 004: The volumetric flow rate of the gas combusted for supplemental fuel (auxiliary) gas shall be measured and recorded using, an operational non-resettable elapsed flow meter at the thermal oxidizer. A system that collects, sums, and stores electronic data from a continuous fuel flow meter is considered to be an operational non-resettable elapsed flow meter. Point 004: During times of VRU downtime for the amine unit (Point 004) when flash gas is routed to the flare, the operator shall measure the amount of gas routed to the flare from this source using an operational non-resettable elapsed flow meter This volume will be applied to the process limit for the flash tank of the amine unit, and this same amount may be subtracted from the metered throughput to the flare. Calculated emissions from the DRAFT flash tank shall be applied to the emission limit for the amine unit and may be subtracted from the calculated emissions for the flare. A system that collects, sums, and stores electronic data from a continuous fuel flow meter is considered to be an operational non- resettable elapsed flow meter. Point 005: The owner or operator shall install, operate, and maintain an operational non- resettable elapsed flow meter flow meter for the flare to monitor and record the volume of process gas and purge gas routed to the flare. A system that collects, sums, and stores electronic data from a continuous fuel flow meter is considered to be an operational non resettable elapsed flow meter. 19. The emission points in the table below shall be operated and maintained with the control equipment / programs as listed in order to reduce emissions to less than or equal to the limits established in this permit (Reference: Regulation No.3, Part. B, Section lll.E.) Facility Equipment ID, AIRS Point Control Pollutants Controlled A-1 004 Still Vent — Primary: Thermal Oxidizer. Secondary: Plant Process Flare (Point 005) VOC, HAPs, H2S Flash Tank during VRU downtime — Plant Process Flare (Point 005) FL -90100 005 Open Flare VOC, HAPs Fugitives 006 Implementing LDAR program as specified in NSPS 0000a VOC, HAPs STATE AND FEDERAL REGULATORY REQUIREMENTS 20. Points 001-005: The permit number and AIRS ID number shall be marked on the subject equipment for ease of identification. (Reference: Regulation Number 3, Part B, III.E.) (State only enforceable). 21. Visible emissions must not exceed twenty percent (20%) opacity during normal operation of the source. During periods of startup, process modification, or adjustment of control equipment visible emissions shall not exceed 30% opacity for more than six minutes in any sixty consecutive minutes. (Reference: Regulation No. 1, Section II.A.1. &4.) 22. This source ` is subject to the odor requirements of Regulation No. 2. (State only enforceable) 23. Points 001 003: Each heater is subject to the Particulate Matter Emission Regulations of Regulation 1 and Regulation 6,including, but not limited to, the following: No owner or operator shall cause or permit to be emitted into the atmosphere from any fuel -burning equipment, particulate matter in the flue gases which exceeds the following (Regulation 1, Section lI I.A.1): For fuel burning equipment with designed heat inputs greater than 1x106 BTU per hour, but less than or equal to 500x106 BTU per hour, the following equation will be used to determine the allowable particulate emission limitation. PE=0.5(FI)-6 26 Where: PE = Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in. Million BTU per hour (Regulation 1, Section Ill A.1 -.b and (Regulation 6, Part B, Section Il.C.2). Greater than 20 percent opacity (Regulation 6, Part B, Section II.C.3). 24. Points 001 - 003: Each heater is subject to the requirements of Regulation No. 6, PartA, Subpart A, General Provisions, including, but not limited to, the following At all times, including periods of start-up, shutdown, and malfunction, the facility and control equipment shall, to the extent practicable, be maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. Determination of whether or not acceptable operating and maintenance procedures are being used will be based on information available to the Division, which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. (Reference: Regulation No. 6, Part A. General Provisions from 40 CFR 60.11) No article, machine, equipment or process shall be used to conceal an emission which would otherwise constitute a violation of an applicable standard. Such concealment includes, but is not, limitedto, the use of gaseous diluents to achieve compliance with an opacity standard or with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere. (§ 60.12) Written notification of construction and initial startup dates shall be submitted to the Division as required under § 60.7. Records of startups, shutdowns, and malfunctions shall be maintained, as required under § 60.7. Performance tests, if required, shall be conducted as required under §60.8. Points 001-003: Each heater is subject to the New Source Performance Standards requirements of Regulation No. 6, Part A Subpart Dc, Standards of Performance for Small Industrial -Commercial -Institutional Steam Generating Units including, but not limited to, the following: § 60.48c(g)(2) As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or operator of an affected facility that combusts only natural gas, wood, fuels using fuel certification in §60.48c(f) to demonstrate compliance with the SO2 standard,_ fuels not subject to an emissions standard (excluding opacity), or a mixture of these fuels may elect to record and maintain records of the amount of each fuel combusted during each calendar month. § 60.48c(i) All records required under this section shall be maintained by the owner or operator of the affected facility for a period of two years following the date of such record. DRAFT 26. This facility is located in an ozone non -attainment or attainment -maintenance area and subject to the Reasonably Available Control Technology (RACT) requirements of Regulation Number 3, Part B, III.D.2.a.: Facility Equipment ID AIRS Point Meeting RACT Requirements by: Amine regen 1 001 T1 mole sieve Natural gas as fuel, low NOx burners, good heater 002 combustion practices T2 mole sieve heater 003 Routing amine still vent waste -gas to thermal A-1 004 oxidizer. Recycling of flash -tank waste gas by VRU — Routing flash -tank waste gas to flare during allowable VRU downtime. Operating flare according to NSPS 60.18 Flare 005 Implementing LDAR program as specified in NSPS Fugitives 006 0000a 27. Point 005: In order to meet RACT requirements of Regulation Number 3, Part B, III.D.2.b, and to be granted 98% control, the flare shall be designed and operated in accordance with the following: • Flare Requirements Flares shall be designed for and operated with no visible emissions, except for periods not to exceed a total of 5 minutes during any 2 consecutive hours, as determined by the methods specified in the Visible Emissions Monitoring section of this condition. Flares shall be operated with a flame present at all times, except for during periods of flare maintenance or repair, as determined by the methods specified in the Pilot Light Monitoring section of this condition. An owner/operator must adhere to the requirements in the Exit Velocity Calculation section of this condition regarding flare exit velocity and the Net Heating Value Calculation section of this condition regarding gas heat content to flare. o Air -assisted flares shall be designed and operated with an exit velocity less than the velocity, Vmax, as determined by the method specified in the Maximum Permitted Velocity section of this condition. The Flare used to comply with this section shall be air -assisted Monitoring Requirements - Owners or operators of flares used to comply with the provisions of this subpart shall monitor these control devices to ensure that they are operated and maintained in conformance with their designs. Applicable subparts will provide provisions stating how owners or operators of flares shall monitor these control devices. Operating Requirements - Flares used to comply with provisions of this subpart shall be operated at all times when emissions may be vented to them. Visible Emissions Monitoring - At the frequency specified in the Visible Emissions Observation Frequency section : of this condition, the operator is required to conduct an inspection of the subjectcombustion device for the presence or absence of smoke (e.g., visible emissions). If smoke is observed during the visible emissions inspection the operator has the option to either: o Immediately shut-in the equipment to investigate the cause of the smoke, conduct any necessary repairs, and maintain records of the specific repairs completed; Conduct a formal Method 22 observation to determine whether visible emissions are present. Method 22, as contained in the appendix A to 40 cfr 60.18 shall be used to determine the compliance of flares with the visible. emission provisions of this subpart. The observation period is 2 hours and shall be used according to Method 22. The flare shall be operated with no. visible emissions, except for periods not to exceed a total of 5 minutes during any 2 consecutive hours. A record of visual emissions observations shall be kept for a period of 5 years, including the date of each observation, whether smoke was observed, whether equipment was shut in or Method 22 performed as a result of initial smoke observation, records of any repairs with repair dates and name of person doing any visual observations, including Method 22. If repair cannot be immediately completed as a result of visual emissions observation by Method 22, the operator shall shut-in the flare, conduct any necessary repair, and maintain records of the specific repairs completed. Visual Emissions Observation Frequency The frequency of visual emissions monitoring shall be based on the total permitted facility emissions of, according to the following two scenarios: o VOC Emissions < 80 tons per year - Visible Emissions Observation shall be performed Weekly, VOC Emissions ≥ 80 tons per year - Visible Emissions Observation shall be performed Daily O Pilot Light Monitoring - The presence of a flare pilot flame shall be monitored using a thermocouple or any other equivalent device to detect the presence of a flame. The device shall be equipped with an alarm to indicate lack of presence of a pilot flame. Records of the times and duration of all periods of pilot flame outages and estimated emissions shall be maintained and made available to the Division upon request. Estimated emissions during pilot flame outages (uncontrolled emissions) shall assume 0% control. Permitted Minimum Net Heating Value - Flares shall be used only with the net heating value of the gas being combusted being 11.2 MJ/scm (300 Btu/scf) or greater for this air' assisted flare. The net heating value of the gas being combusted shall be determined by the methods specified in the gas Heating Value Calculation section of this condition. Net Heating Value Calculation The net heating value of the gas being combusted in a flare shall be calculated using the following equation: K r Ci Where: HT = Net heating value of the sample, MJ/scm; where the net enthalpy per mole of offgas is based oncombustion at 25 °C and 760 mm Hg, but the standard temperature for determining the volume corresponding to one mole is 20 °C;, I q male MJ aper-ature for i9 mclel ix sat C; = Concentration of sample component i in ppm on a wet basis, as measured for organics by Reference Method 18 and measured for hydrogen and carbon monoxide by ASTM D1946-77 or 90 (Reapproved 1994) (Incorporated by reference as specified in §60.17); and H, = Net heat of combustion of sample component i, kcal/g mole at 25 °C and 760 mm Hg. The heats of combustion may be determined using ASTM D2382-76 or 88 or D4809-95 (incorporated by reference as specified in §60.17) if published values are not available or cannot be calculated: o The most recent sample of gas to the flare, as specified in the initial or periodic sampling section, shall be used to determine the net heating value. Exit Velocity Calculation - The exit velocity of a flare shall be determined by dividing the volumetric flowrate (in units of standard temperature and pressure), as determined by Reference Methods 2, 2A, 2C, or 2D as appropriate; by the unobstructed (free) cross sectional area of the flare tip. o ' The cross sectional area of the flare tip to be used for calculating exit velocity shall be the actual flare tip size. o The exit velocity shall be calculated monthly, using the total throughput to the flare as determined by metering. Maximum Permitted Velocity The maximum permitted velocity, Vmax for air - assisted flares shall be determined by the following equation. V. = 8.706+0.7084 (HT) Vmax= Maximum permitted velocity,'m/sec 8.706=Constant 0.7084=Constant HT = The net heating value as determined in the Net Heating Value Calculation section of this condition. Demonstration of Compliance o Compliance with the required net fuel heating value and flare tip, velocity will be recorded in a log to be kept readily available. The compliance demonstration frequency will be monthly. Each demonstration of compliance will, be kept for a minimum period of 5 years: A control efficiency of 98% shall be applied to the emissions calculated from operation of this flare during each period where compliance is demonstrated A control efficiency of 95% shall be applied to the emissions calculated from operation of this flare during each period where compliance is not demonstrated o Emissions that occur during pilot flame outages shall be considered to have a 0% control. Recordkeeping Requirements o The design specifications of the flareshall be kept on -site for a period of at least 5 years, including the flare -tip cross-sectional area o Records of any flare tip replacements must be kept on -site for a period of at least 5 years Point 006: This source is subject to Regulation No. 7, Section XII.G.1 (State only enforceable). For fugitive VOC emissions from leaking equipment, the leak detection and repair (LDAR) program as provided at 40 CFR Part 60, Subpart OOOO(July 1, 2017) shall apply, regardless of the date of construction of the affected facility unless subject to applicable LDAR program as provided at 40 CFR Part 60, Subpart 0000a (July 1, 2017). The operator shall comply with all applicable requirements of Section XII.G. This facility is subject to 40 C.F.R. Part 60, Subpart OOOOa, and compliance with that rule shall satisfy the requirements of Regulation No. 7, Section XII.G.1. OPERATING & MAINTENANCE REQUIREMENTS 29. Points 001-005: Upon startup of these points, the applicant shall follow the operating and maintenance (O&M) plan and record keeping format approved by the Division, in orderto demonstrate compliance on an ongoing basis with the requirements of this permit. Revisions to your O&M plan are subject to Division approval prior to implementation. (Reference Regulation No. 3, Part B, Section III.G.7.) Point 004: The combustion temperature of the thermal oxidizer used to control emissions from the amine unit shall be greater than 1400 `F, or the temperature established during the most recent stack test of the equipment that was approved by the Division, on a daily average basis_ The approved minimum combustion temperature shall be achieved at all times that any amine unit emissions are routed to the thermal oxidizer. The combustion chamber temperature shall be measured and recorded at least once every hour. if the combustion chamber temperature value is measured more frequently than once per hour, the source shall record either each measured data value or each block average value for each 1 -hour period calculated from all measured data values during each period. Point 004: Periodic maintenance shall be completed to maintain the efficiency of the thermal oxidizer and shall be performed at a minimum of once per every twelve months or more often as recommended by the manufacturer specifications. COMPLIANCE TESTING AND SAMPLING Initial Testina Reauirements 30. 31. 32. Points 001-003: A source initial compliance test shall be conducted on each heater to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits contained in this permit. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from DRAFT the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods Carbon Monoxide using EPA approved methods 33. Point 004: The owner or operator shall complete the initial amine unit still vent waste gas sampling and the initial amine unit flash tank waste gas sampling and submit the results to the Division as part of the self -certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section lll.E.) 34. Point 004: A source initial compliance test shall be conducted on this emissions point to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits specified in this permit. The natural gas throughput, lean amine circulation rate and MDEA concentration entering the amine units shall be monitored and recorded during this test. The operator shall also measure and record combustion zone temperature during the initial compliance test to establish the minimum combustion temperature. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable" number of operating hours for that averaging time (Reference: Common Provisions Section II.C and Regulation No. 3, Part B., Section IIl_G.3) Oxides of Nitrogen using EPA approved methods Volatile Organic Compounds using EPA approved methods Carbon Monoxide using EPA approved methods 35. Point 005: The operator shall complete an initial site -specific extended gas analysis of the natural gas that is routed to the flare in order to verify the VOC content of the stream as well as the heat content of the gas routed to the flare. The sampled stream shall represent the combined streams of all gas being routed to the flare at the time of sampling. The extended gas analysis shall be conducted using ASTM methods or equivalent, if approved in advance by the Division. The extended gas analysis shall be used to calculate emissions as specified in the Notes to Permit Holder section of this permit. The heat value shall be used to meet the heating value and flare tip velocity requirements in this permit. Periodic Testing Reauirements Point 004: The operator shall measure the emission rate for the pollutants listed below at least once every 12 months, unless the emission point has not operated in the last 12 months, in order to demonstrate compliance with the emissions limits contained in this permit. Periodic testing shall be conducted within 12 months of the prior test with a minimum period of at least one hundred and eighty (180) days apart. In the event it is not feasible to conduct a test at a minimum of at least one hundred and eighty (180) days apart, a written explanation shall be submitted with the test protocol describing the reasons the testing could not be conducted one hundred and eighty (180) days apart. If the emission point will be operated at any time during a 12 -month period, except for periods of maintenance, it must be tested as required by this condition. If the emission point has DRAFT not operated for more than 12 months, it must be tested within 60 days of resuming operation. The natural gas throughput, lean amine circulation rate, MDEA concentration, and combustion zone temperature shall be monitored and recorded during this test. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show - compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods Volatile Organic Compounds using EPA approved methods Carbon Monoxide using EPA approved methods 37. Point 004: Amine unit still vent waste gas shall be sampled and analyzed from the amine unit including an extended gas analysis at a minimum frequency of once per calendar month. The sample shall be analyzed for total VOC, Benzene, Toluene, Ethylbenzene, Xylene, n -Hexane and 2,2,4-trimethylpentaneand H2S content. The sample shall be collected prior to the inlet of the thermal oxidizer and prior to being, combined with any other stream. The sampled data will be used to calculate VOC and H2S emissions to show compliance with the emission limits. If an amine unit is not operated during a calendar month, monthly sampling is not required. 38. Point 004: Amine unit flash tank waste gas shall be sampled and analyzed from the amine. unit including an extended gas analysis at a minimum frequency of once per six month period. The sample shall be analyzed for total VOC, Benzene, Toluene, Ethylbenzene, Xylene, n -Hexane and 2,2,4-trimethylpentane and H2S content. The sample shall be collected prior to the inlet of the thermal oxidizer and prior to being combined with any other stream. The sampled data will be used to calculate VOC and H2S emissions to show compliance with the emission limits. Point 005: On a quarterly basis, the operator shall complete a site specific extended gas analysis of the natural gas that is routed to the flare in order to verify the VOC content of the stream as well as the heat content of the gas routed to the flare. The sampled stream shall represent the combined streams of all gas being routed to the flare at the time of sampling. The extended gas analysis shall be conducted using ASTM methods or equivalent, if approved in advance by the Division. The extended gas analysis shall be used to calculate emissions as specified in the Notes to Permit Holder section of this permit. The heat value shall be used to meet the heating value and flare tip velocity requirements in this permit. Point 006: On an annual basis, the permittee shall complete an extended gas analysis and an extended natural gas liquids analysis that are representative of volatile organic compounds (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. These extended gas and liquids analyses shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. ADDITlONAL'REQUIREMENTS 41. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation No. 3, Part A, II C) Annually whenever a significant increase in For any criteria.pollutant: For sources emitting less than 100 tons per year, a change in actual emissions of five (5) tons per year or more, above the level reported on the last APEN; or For volatile organic compounds (VOC) and nitrogen oxides sources (NOX) in ozone nonattainment areas emitting less than 100 tons of VOC or NOX per year, a change in annual actual emissions of one (1) ton per year or more or five percent, whichever is greater, above the level reported on the last APEN; or For sources emitting 100 tons per year or more, a change in actual emissions of five percent or 50 tons per year or more, whichever is less; above the level reported on the last APEN submitted; or For any non -criteria reportable pollutant: If the emissions increase by 50% or five (5) tons per year, whichever is less, above the level reported on the last APEN submitted to the Division. Whenever there is a change in the owner or operator of any facility, process, or activity; or Whenever new control equipment is installed, or whenever a different type of control equipment replaces an existing type of control equipment or Whenever a permit limitation must be modified; or No later than 30 days before the existing APEN expires. GENERAL TERMS AND CONDITIONS: 42. This permit and any attachments must be retained and made available for inspection, upon request. The permit may be reissued to a new owner by the APCD as provided in AQCC Regulation No. 3, Part B, Section II.B upon a request for transfer of ownership and the submittal of a revised APEN and the required fee. 43. If this permit specifically states that final authorization has been granted, then the remainder of this condition is not applicable. Otherwise, the issuance of this construction permit does not provide "final authority for this activity or operation of this source. Final authorization of the permit must be secured from the APCD in writing in accordance with, the provisions of 25-7-114.5(12)(a) C.R.S. and AQCC Regulation No. 3, Part B, Section III.G. Final authorization cannot be granted until the operation or activity commences and has been verified by the APCD as conforming in all respects with the conditions of the permit. Once self -certification of all points has been reviewed and approved by the Division, it will provide written documentation of such final authorization. Details for obtaining final authorization to operate are located in the Requirements to Self - Certify for Final Authorization section of this permit. This permit is issued in reliance upon the accuracy and completeness of information supplied by the applicant and is conditioned upon conduct of the activity, or construction,' installation and operation of the source, in accordance with this information and with representations made by the applicant or applicant's agents. It is valid only for the equipment and operations or activity specifically identified on the permit. Unless specifically stated otherwise, the general and specific conditions contained, in this permit have been determined by the APCD to be necessary to assure compliance with the provisions of Section 25-7-114.5(7)(a), C.R.S. Each and every condition of this permit is a material part hereof and is not severable. Any challenge to or appeal of a condition hereof shall constitute a rejection of the entire permit and upon such occurrence, this permit shall be deemed denied ab initio. This permit may be revoked at any time prior to self -certification and final authorization by the Air Pollution Control Division (APCD) on grounds set forth in the Colorado Air Quality Control Act and regulations of the Air Quality Control Commission (AQCC), including failure to meet any express term or condition of the permit. If the Division denies a permit, conditions imposed upon a permit are contested by the applicant, or the Division revokes "a permit, the applicant or owner or operator of a source may request a hearing before the AQCC for review of the Division's action. 47. Section 25-7-114.7(2)(a), C.R.S. requires that all sources required to file an Air Pollution Emission Notice (APEN) must pay an annual fee to cover the costs of inspections and administration. If a source or activity is to be discontinued, the owner must notify the Division in writing requesting a cancellation of the permit. Upon notification, annual fee billing will terminate. 48. Violation of the terms of a permit or of the provisions of the Colorado Air Pollution Prevention and Control Act the regulations of the AQCC may result in administrative, civil or criminal enforcement actions under Sections 25-7-115 (enforcement), -121 (injunctions), -122 (civil penalties), -122.1 (criminal penalties), C.R.S.. By: Christian Lesniak Permit Engineer Issuance Date Description Issuance 1 This Issuance Initial Issuance — Natural Gas Processing Plant - Issued to Kerr McGee Gathering, LLC. Notes to Permit Holder at the time of this permit issuance: 1) The permit holder is required to pay fees for the processing time for this permit. An invoice for these fees will be issued after the permit is issued. The permit holder shall pay the invoice within 30 days of receipt of the invoice. Failure to pay the invoice will result in revocation of this permit (Reference: Regulation No. 3, Part A, Section VI.B.) 2) The production or raw material processing limits and emission limits contained in this permit are based on the consumption rates requested in the permit application. These limits may be revised upon request of the permittee providing there -is no exceedance of any specific emission control regulation or any ambient air quality standard. A revised air pollution emission notice (APEN) and application form must be submitted with a request for a permit revision. 3) This source is subject to the Common Provisions Regulation Part II, Subpart E, Affirmative Defense Provision for Excess Emissions During Malfunctions. The permittee shall notify the Division of any malfunction condition which causes a violation of any emission limit or limits stated in this permit as soon as possible, but no later than noon of the next working day, followed by written notice to the Division addressing all of the criteria set forth in Part II.E.1. of the Common Provisions Regulation. See:_ http://www.cdphe.state.co.us/requlations/airregs/100102agcccommonprovisionsreq. pdf. 4) The following emissions of non -criteria reportable air pollutants are estimated based upon the process limits as indicated in this permit. This information is listed to inform the operator of the Division's analysis of the specific compounds emitted if the source(s) operate at the permitted limitations. AIRS Point Pollutant CAS # Uncontrolled Emission Rate (Ib/yr) Are the emissions reportable? Controlled Emission Rate (Ib/yr) 001 Benzene 71432 1 No 1 Toluene 108883 2 No 2 Formaldehyde 50000 40 No 40 Hexane 110543 964 Yes 964 002, 003 EACH Benzene 71432 0 No 0 Toluene 108883 1 No 1 Formaldehyde 50000 13 No 13 Hexane 110543 322 Yes 322 004 Benzene 71432 41316 Yes 427 Toluene 108883 24558 Yes 252 Ethylbenzene 100414 15068 Yes 154 Xylenes 1330207 42985 Yes 437 n -Hexane 110543 4060 Yes 68 005 Benzene 71432 7359 Yes 147 Toluene 108883 57867 Yes 1157 Ethylbenzene 100414 16668 Yes 333 DRAFT' Xylenes 1330207 63338 Yes 1267 n -Hexane 110543 18941 Yes 379 006 Benzene 71432 12439 Yes 1484 Toluene 108883 12439 Yes 1484 Ethylbenzene 100414 12439 Yes 1484 Xylenes 1330207 12439 Yes 1484 n -Hexane 110543 24878 Yes 2969 224 TMP 540841 12439 Yes 1484 Methanol 67561 2816 Yes 521 5) The emission levels contained in this permit are based on the following emission factors: Points 001: The operator has indicated the following regarding the metering of gas for this point: A data collection system totalizes flow for each calendar month, based on flow measurements that occur at least once per 15 minutes. The totalized flow volumes that are used for demonstrating, compliance represent the totalized flow for each month. CAS Pollutant Emission Factors - Uncontrolled (lb/MMscf Natural Gas combusted) Uncontrolled EF Source NOx 36.00 Manufacturer CO 36.00 Manufacturer VOC 17.10 Manufacturer PM10 6.71 AP -42, Table 1.4-2 PM2.5 6.71 AP -42, Table 1.4-2 SO2 0.53 AP -42, Table 1.4-2 110543 n -Hexane 1.8 AP -42, Table 1.4-3 Emission factors are based on a fuel heating value of 900 btu/scf Points 002, 003: The operator has indicated the following regarding the metering of gas for this point: A data collection system totalizes flow for each calendar month, based on flow measurements that occur at least once per 15 minutes. The totalized flow volumes that are used for demonstrating compliance represent the totalized flow for each month. CAS Pollutant Emission Factors - Uncontrolled (lb/MMscf Natural gas combusted) Uncontrolled EF Source NOx 36.00 Manufacturer CO -36.00 Manufacturer VOG 17.10 Manufacturer PM10 6.71 AP -42, Table 1.4-2 PM2.5 6.71 AP -42, Table 1.4-2 SO2 0.53 AP -42, Table 1.4-2 110543 n -Hexane 1.8 AP -42, Table 1.4-3 Emission factors are based on a fuel heating value of 900 btu/scf Points 004: The operator has indicated the following regarding the metering of gas for this point: A data, collection system totalizes flow for each calendar month, based on flow measurements that occur at least once per 15 minutes. The totalized flow volumes that are used for demonstrating compliance represent the totalized flow for each month. The amine unit is subject to the New Source Performance Standards requirements of 4O CFR, Part 60, Subpart OOOOa-Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification or Reconstruction Commenced After September 18,2015 including, but not limited to; the following: • §60.5365a — Applicability and Designation of Affected Facilities o §60.5365a(g)(3) - Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) are required to comply with recordkeeping and reporting requirements specified in §60.5423(c) but are not required to comply with §§60.5405 through 60.5407 and §§60.5410(g) and 60.5415(g). • §60.5423a — Record keeping and reporting Requirements o §60.5423a(c) - To certify that a facility is exempt from the control requirements of these standards, for each facility with a design capacity less that 2 LT/D of H2 S in the acid gas (expressed as sulfur) you must keep, for the life of the facility, an analysis demonstrating that the facility's design capacity is less than, 2 LT/D of H2 S expressed as sulfur. This rule has not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 6. Emissions from the amine unit result from venting of acid gas (still vent overhead) emissions to the thermal oxidizer, and emissions from the flash tank during permitted hours of VRU downtime routed to the plant flare (Point 005). Additionally, emissions result from combustion of supplemental fuel required to combust the acid gas (still vent overhead) emissions at the thermal oxidizer. Actual VOC, HAP and H2S emissions from venting of still vent acid gas and flash tank emissions shall be calculated based on most recent waste gas sampling and most recent monthly waste gas flow volume. Controlled emissions are based on a thermal oxidizer control efficiency of 99%. SO2 emissions resulting from the control/combustion of H2S emissions in the waste gas are based on mass balance and assuming 100% of the H2S is converted to SO2. Additional combustion emissions (from both supplemental fuel and waste gas) are calculated using the following emission factors and volume of total gas combusted. Total gas combusted is the sum of most recent waste gas flow volume plus most recent supplemental fuel volume plus burner volume. Total actual emissions for each point are then based on the sum of emissions calculated for controlled waste gas ' plus combustion (including supplemental fuel, burner fuel and waste gas). DRAFT Emission Factors for supplemental fuel to thermal oxidizer: Pollutant Emission Factors — Uncontrolled lb/MMscf total gas combusted Uncontrolled €F Source NOx 100 AP -42, Table 1.4-1 VOC' 5.5 AP -42, Table 1.4-1 CO 84 AP -42, Table 1.4-1 PM 1-O 0.041 AP -42, Table 1.4-2 PM2.5 0.041 AP -42, Table 1.4-2 SO22 0.6 AP -42, Table 1.4-2 1: VOC emissions from combustion (calculated using the emission factor in the table. above) must be summed with VOC emissions from the still vent to calculate total actual emissions. 2: SO2 emissions from combustion (calculated using the emission factor in the table above) plus conversion of H2S emissions in, the still vent must be summed to calculate actual SOx emissions. *Still Vent Waste Gas and Supplemental Fuel are based on actual measured monthly flow volumes. Emission Factors for flash gas to flare during VRU downtime: CAS Pollutant Emission Factors - Uncontrolled lb/MMbtu total gas combusted' Uncontrolled EF Source NOx 0.068 AP -42, Table 13.5-1 CO 0.31 AP -42, Table 13.5-2 PM10 0.0075 AP -42, Table 1.4-2 PM2.5 0.0075 AP -42, Table 1.4-2 Equation for Actual VOC Emissions Calculations: lb VOCTotal (month) VOCsz1 Vent Waste Gas + VOCThermalOxidizer Combustion + VOCFlash Tank Waste Gas V OCStiti Vent Waste Gas scf- = VOC concentration (wt %) - 100 x Still Vent Waste Gas Volume ( ) month x Gas Molecular Weight ( lb ) _ 379 ( scf lbmol lbmol x (1- Thermal Oxidizer control %) *VOC concentration and Gas Molecular Weight are taken from the actual monthlysampled values of the amine unit still vent waste gas stream. *Still Vent Waste Gas Volume is the actual measured monthly flow volume of the amine unit still vent. *Thermal Oxidizer control percentage is 99% on the basis of meeting this control percentage in the most recent stack test. VOCcombustion = Emission Factor ( lb ) x [Supplemental Fuel (MMscf) + Burner Fuel (MMscf)]- MMscf month month. *Supplemental Fuel is based on actual measured monthly flow volume. VOCFlash Tank Waste Gas = VOC concentration (wt %) _.100 x Flash Gas Waste Gas Volume month lb scf x Gas Molecular Weight () — 379 () x (1- (flare control %11.00)) lbmollbmol *VOC concentration and Gas Molecular Weight are taken from the most recent sampled values of the amine unit flash tank waste gas stream * Flash Tank Waste Gas Volume is the most recent monthly value measured by meter *Flare control percentage is 98% on the basis of demonstrating compliance with the flare (Point 005) operating requirements in this permit Equation for Actual HAP Emissions Calculations: lb Still Vent HAP ( ) month scf HAP concentration (wt %) _ 100 x Still Vent Waste Gas Volume ( ) month lb s(x Gas Molecular Weight ( ) - 379 ) x (1 — thermal oxidizer control %) lbmol lbmol *HAP concentration and Gas Molecular Weight are taken from the actual monthly sampled values of the amine unit still vent waste gas stream. *Still Vent Waste Gas is the actual measured, monthly flow volume. *Thermal Oxidizer control percentage is 99% on the basis of meeting this control percentage in the most recent stack test: lb Flash Tank HAP O month scf HAP concentration (wt %) — 100 x Flash Tank Waste Gas Volume ( ) lb scf month x Gas Molecular Weight ( ) _ 379 x (1 — (flare control %/100)) lbmol lbmol *HAP concentration and Gas Molecular Weight are taken from the most recent sampled -. values of the amine unit flash tank waste gas stream * Flash Tank Waste Gas Volume is the most recent monthly value measured by meter *Flare control percentage is 98% on the basis of demonstrating compliance with the flare (Point 005) operating requirements in this permit Equation for Actual H2S Emissions Calculations: H2STota1 (month Ib ) = H2Sz Vent Waste Gas + H2S Flash Tank Waste Gas Sulfurs waste Gas + H2S Fuel H2S still Vent Waste Gas scf = H2S concentration (mol %) _ 100 x Still Vent Waste Gas ( ) month x 34.08 ( lb H2S ) ± 379 ( scf ) x (1 — (thermal oxidizer control %/100)) lbmol H2S) lbmol *H2S concentration is taken from the actual monthly sampled values of the amine unit still vent waste gas stream. *Still Vent Waste Gas is the actual measured monthly flow volume. *Thermal Oxidizer control percentage is 99% on the basis of meeting this control percentage in the most recent stack test. H2S Flash Tank Waste Gas scf = H2S concentration (mol %) _ 100 x Flash Tank Waste Gas ( ) lb H2S scf month x 34.08 ( ) = 379 ( ) x (1— (flare control %/100)) lbmol H2S) lbmol *H2S concentration is taken from the most recent sampled values of the amine unit flash tank waste gas stream * Flash Tank Waste Gas Volume is the most recent monthly value measured by meter *Flare control percentage is 98% on the basis of demonstrating compliance with the flare (Point 005) operating requirements in this permit Sulfurs Waste Gas Other Sulfurs concentration (mot %) _ 100 x Still Vent Waste Gas ( x 60.07 ( scf scf month lb Sulfurs ) _ 379 ( ) x (1 — (thermal oxidizer control %/100)) lbmol Sulfurs) lbmol *Other sulfurs concentration is based on sum of total other sulfurs in actual monthly sampled values of the amine unit still vent waste gas stream. lb MMscf MMscf H2SFuei = Emission Factor ( ) x [Supplemental Fuel ( ) + Burner Fuel ( ) MMscf month month DRAFT' *Supplemental Fuel is based on actual measured monthly flow volume. Equation for Actual SOx Emissions Calculations: SOXTotal ( lb ) = SOXWµste Gas. + SOXCombustion ' month SOXwaste Gas = [(H2Sst1u Vent Waste Gas - (1 — (thermal oxidizer control %/100)) + H2S Flash Tank Waste Gas — (1, (flare control %/100))) x 64.05 lb SO2 - 34. 08 lb H2S] + [ Sul furswaste Gas - (1 — (thermal oxidizer control %/100)) x 64.05 lb SO2 - 60 07 lb sulfurs] SOXCombustion = Emission Factor ( lb"'"'�`f ) x [Supplemental ' Fuel (MMscf) + Burner Fuel (l] MMscf month month *Supplemental Fuel is based on actual measured monthly flow volume. Points 005: The 98% control granted for this open flare is based on the proper operation of the flare, as well as meeting the flare tip velocity and waste gas fuel heating value requirements, as described in this permit. The operator has indicated the following regarding the metering of gas for this point: A data collection system totalizes flow for each calendar month, based on flow measurements that occur at least once per 15 minutes. The totalized flow volumes that are used for demonstrating compliance represent the totalized flow for each month. Primary Pollutants from combustion of waste gas: CAS Pollutant Emission Factors — Uncontrolled lb/MMscf Total Gas Combusted Emission Factors - Controlled Ib/MMscf Uncontrolled EF Source VOC 17832.12 356.642 Mass Balance from non -site -specific gas analysis 71432 Benzene 84.8517 1.6970 108883 Toluene 667.271 13.3454 100414 ' Ethylbenzene 192.198 3.8440 1330207 Xylenes 730.352 14.6070 110543 n -Hexane 218.414, 4.3683 Total gas combusted equals process gas volume plus purge gas volume (process gas, volume and purge gas volume are metered) plus fuel volume to flare pilot. Flare combustion efficiency is 98%. DRAFT Secondary pollutants from combustion of waste gas: CAS Pollutant Emission Factors -- Uncontrolled lb/MMBtu Total Gas Combusted Uncontrolled EF Source NOx 0.068 AP -42, Table 13.5-1 CO 0.31 AP -42, Table 13.5-2 PM2.5/PM10 0.0084 AP -42, Table 1.4-2 *PM MMbtu emission factors are based on a an assumed heating value of 900 Btu/scf Pollutants from pilot gas combustion: CAS Pollutant Emission Factors Uncontrolled lb/MMscf Total Gas Combusted Uncontrolled EF Source NOx 100 AP -42, Table 1.4-1 CO 84 AP -42, Table 1.4-1 VOC 5.5 AP -42, Table 1.4-1 PM2.5/PM10 7.6 AP -42, Table 1.4-2 *Total Emissions shall be calculated by adding the sum of waste gas emission to the sum of pilot light combustion emissions. Any flash tank emissions for the amine unit (Point 004) calculated during allowed VRU downtime may be subtracted from the total emissions for this unit for those given pollutants. Flash tank emissions shall be calculated according to the methods specified for the Amine Unit (Point 004). *Volume throughput to the flare shall be the metered throughput to the flare with any flash gas from the amine unit subtracted out. *Pilot Light volume throughput shall be calculated using the pilot combustion design rate Points 006: This facility is subject to 40 CFR, Part 60, Subpart 0000a - Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification or Reconstruction Commenced After September 18, 2015 (Effective August 2, 2016). This rule has not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 6. The emission control percentages for fugitive emission leaks contained in this permit are granted on the basis of implementation and ongoing compliance with an LDAR program meeting the requirements of 40 CFR, Part 60, Subpart OOOOa. In the event that this facility becomes a major source of hazardous air pollutants (HAPs), this source will be subject to the requirements of 40 CFR Part 63, subpart HI -I, for fugitive equipment leaks at facilities not subject to 40 CFR Part 60, Subpart OOOO, including, but not limited to, § 63.769 (a) -(c). DRAFT Fugitive Components and Fluid Compositions: Equipment Type Inlet Gas (Gas) C3+ Gas (Gas) Heavy Oil (Heavy Liquid) Condensate (Light Liquid) C3+ Liquid (Light Liquid) NGL (Light Liquid) Methanol (Light Liquid) Connectors 1202 10604 3953 389 1458 321 92 Flanges 566 342 0 0 317 68 0 Open -Ended Lines 0 0 0 0 0 0 0 Pump Seals 0 0 17 0 8 11 3 Valves 653 1211 468 231 1038 114 29 Other 35 32 9 0 17 5 2 VOC Content (wt%) 22% 100% 100% 100% 100% 100% 100% Benzene (wt%) 4% 4% 4% 4% 4% 4% - Toluene (wt%) 4% 4% 4% 4% 4% 4% - Ethylbenzene (wt%) 4% 4% 4% 4% 4% 4% ` - Xylenes (wt%) 4% 4% 4% 4% 4% 4% - n -hexane (wt%) 8% 8% 8% 8% 8% 8% - 224 TMP 4% 4% 4% 4% 4% 4% - *Other equipment type includes compressors, pressure relief valves, relief valves, diaphragms, drains, dump arms, hatches, instrument meters, polish rods and vents Listed components represent estimated count as provided by source, and listed VOC and HAP weight percentages represent source estimates. TOC Emission Factors (kg/hr-component): Component Gas Service Heavy Oil Light Oil Connectors 2.0E-04 7.5E-06 2.1E-04 Flanges 3.9E-04 3.9E-07 1.1E-04 Open-ended Lines 2.0E-03 1.4E-04 1.4E-03 Pump Seals 2.4E-03 NA 1.3E-02 Valves 4.5E-03 8.4E-06 2.5E-03 Other 8.8E-03 3.2E-05 7.5E-03 Source: EPA -453/R95-017 Compliance with emissions limits in this permit will be demonstrated by using the TOC emission factors listed in the table above with representative component counts, multiplied by the VOC content from the most recent extended gas and liquids analyses. Control Percentages Granted for Compliance with LDAR Program: Component ' Gas Service Heavy Oil Light Oil Connectors 81% 81% 81% Flanges 81% 81% 81% Pump Seals - - 88% Valves 96% - 95% DRAFT 6) In accordance with C.R.S. 25-7-114.1, each Air Pollutant Emission Notice (APEN) associated with this permit is valid for a term of five years from the date it, was received by the Division. A revised APEN shall be submitted no later than 30 days before the five-year term expires. Please refer to the most recent annual fee invoice to determine the APEN expiration date for each emissions point associated with this permit. For any questions regardinga specific expiration date call the Division at (303)-692-3150. 7) This facility is classified as follows: Applicable Requirement Status Operating Permit Synthetic Minor Source: VOC, CO, and HAPs PSD Minor Source NANSR Synthetic Minor Source: VOC MACT HH Area Source Requirements Apply NSPS Dc Applicable NSPS 0000a Applicable 8) Full text of the Title 40, Protecton of Environment Electronic Code of Federal Regulations can be found at the website listed below: http://ecfr.gpoaccess.gov/ Part 60: Standards of Performance for New Stationary Sources NSPS 60.1 -End Subpart A — Subpart KKKK NSPS Part 60, Appendixes Appendix A — Appendix Part 63: National Emission Standards for Hazardous Air Pollutants for Source Categories MACT 63.1-63.599 Subpart A — Subpart Z MACT 63.600-63.1199 Subpart AA — Subpart DDD MACT 63.1200-63.1439 Subpart EEE — Subpart PPP MACT 63.1440-63.6175 Subpart QQQ - Subpart YYYY MACT 63.6580-63.8830 Subpart ZZZZ — Subpart MMMMM MACT 63.8980 -End Subpart NNNNN — Subpart XXXXXX Colorado Air Permitting Project PRELIMINARY ANALYSIS - PROJECT SUMMARY Project Details Review Engineer: Package R: Received Date: Review Start Date: Christian Lesetak Rica Gillette 361635 4/25/2057 5/24/2017 .. Section 01- Facility Information Company Name: Kere:MCGee.Getheerng LLC County AIRS ID: 123' Plant AIRS ID: 9F22 Facility Name: Latham Gas Plant Con original application, mold 4/26/17: tOGas Plant! Physical Address/Location: Section 2, Township 3N, Range 66W, in Weld County, Colorado Type of Facility: ISattesiGas Processing Plant • What industry segment? Chi? aNrot Gas Erodneton&Processing'.. Is this facility located in a NAAOS non -attainment are. Yes: . If yes, for what pollutant? [carbon manoode(co) Olamcuume Matter (pm) I zone (Noce voc) 1 Weld IQuadrant Section 02 - Emissions Units n Permit Application Section I• Township I Range 2 SRI k - g6'.. Protect files thpay File Application documents Correspondence regarding protect AIRS PointD Emissions Source Type Equipment Name Emissions control? Permit Issuance it Selfcert Required? Action 8ineer g Engineering Remarks 001 Bader an Process ' Heater amine men 1 Ntt 17WE0398 CP1 Yes Permit initial Issuance Has "low NOx design". but t - am not considering this control in the traditional sense 002 Boiler or Process Heater Ti male sieve heater - Nis 17WE0398 CP1 Yes Permit lgitiaf issuance Has "low NOx design", but I am not considering this control in the traditional sense 003 8diin-or Process- Heater : T2 mole sieve heater No - 17WE0398 CP1 Yes _ - ' Permit Initial issuance Has "low Nov design", but I am not considering this control in the traditional sense 004 Aniline Sweetening -- Unit A-1 '. Yes, 17WE0398 - CPI Yes Permit Initial Issuance Controlled by TO with 99% control 005 Process Fiore Ft -90100 Yes 17W€0398 CP1 Yes - Permit Initial' Issuance Granted 9E% for following 40cfr60.18 006 Fugitive : Component teaks Fugitives !`es.. 17WE0398 CPI Yes Permit initial Issuance- "control requested to reflect 0000a WAR" 007 Holler or Protean ' ' Heater ,i: stabilizer heater 1 " yes 17WE0399 - XP1 no - APEN Required /Permit Peempt Has "low NOx design", but I am not considering this control in the traditional sense 008 Diesel RICE --. GEN-1 No - 17WE0400 .CN no - APEN Required /Permit Exempt Cancellation notice has since been submitted. This engine is being replaced with natural gas engine. Would have been permit exempt. Emergency Engine (250 hrs) 309 ... Holler or Process -• Heater . Inlet Heated No 17WE0925 XP1 no APEN Required / Permit Exempt Has "taw NOx design, but I am not considering this control in the traditional sense Colorado Air Permitting Project Section 03 - Description of Project Section 04 - Public Comment Requirements Is Public Comment Required? If yes, why? Section 05 -Ambient Air Impact Analysis Require Was a quantitative modeling analysis required? If yes, for what pollutants? If yes, attach a copy of Technical Services Unit modeling results summary. Section 06- Facility -Wide Stationary Source Classification Is this stationary source a true minor? Is this stationary source a synthetic minor? If yes, indicate programs and which pollutants: Prevention of Significant Deterioration (P50) Title V OperatingPermits (OP) Non -Attainment new Source Review (NANSR) Is this stationary source a major source? If yes, explain what programs and which pollutants here: Prevention of Significant Deterioration (PSD) Tide V Operating Permits (OP) Non -Attainment New Source Review (NANSR) SO2 NOx CO VOC PM2.5 PM30 TSP HAPs ❑ ❑ ❑ ❑ O O ❑ ❑ Q D O O O El SO2 NOx CO VOC PM2.5 PM30 TSP HAPs ❑ ❑ ❑ ❑ O O CO ❑ ❑ O O O O ❑ ❑ Section 01 -Administrative Information Facility AIRs ID: County 9P22. 001 amsoe`regen 1 Plant Point Equipment name Section 02 - Equipment Description Details Number heaters/boilers 3-;;=="' :-" One MMBtu/hr MMBtu/hr Manufacturer 0801 . Design input s;-">- - L" Model No. 180' ' Design output '' .. ,' Serial No. 18O Equipment type/purpose 9nrlhetegenerationuheater` •.. Fuel type hta₹dAPafga5. Fuel source 0fpefirte' Low NOx burners? :Y.os:-= � NOx control efficiency 079:-- . : Detailed Emissions Unit Description: Since burner is intrinsic to unit, I am using the manufacturer emisison factor, and not One (1) input rate 55 MMBtu/hr amine regeneration heater. This unit is fueled by natural gas from considering it as a controlled emission factor. This lowers the uncontrolled emission factor. the pipeline. This unit is equipped with low NOx burners. Add-on Emission Control Device: Pollutants controlled: Control Device Emissions Reduction %: Section 03 - Processing Rate Information Notes Heater Design Rate = 55 MMBtu/hr Requested Permit Limit = 55 MMBtu/hr Hours of Operation = 8760 hr/yr Fuel Heat Content = - - 900 Btu/scf Fuel H2S Content = - .. 3.1 ppm Requested Fuel Consumption Limit= ' - 535.3 MMscf/yr 45.5 MMscf/month) 1,, MM,:,:-m:nri'. Norte Stack test results, if available Year heater/boiler ID CO Ib/MMetu NOx lb/MMBtu PM2.5 Ib/MMBtu Section 04 - Emissions Factors & Methodologies boiler type small (.u100); contr.--Low NOR: .. . .. .. Pollutant Ibs/MMBtu lb/MMscf Source lb/MMBtu Notes PM10 7.45E-03 6.71E+00 AP -42 Table -i4-2- 8.44E-03 _ A0-42 Chapter - ,. 1.4 - - PM2.5 7.46E-03 6.705882353 AP -42 Table 1.4-2 8.44E-03 AP -42 Chapter 1.4 SOx ' 5.88E-04 5.29E-01 Burner Manufacturer 6.67E-04 AP42 Chapter - 1.4 NOx . 4.00E-02 " 3.60E+01 Burner Mctiarer. 3.56E-02 "manuf.+10%" VOC 1.90E -02-''''' .90E- 02 '' 1.71E+01 Burner Menufaer -" 6.11E-03 - " °"manuf.+10%" CO 4.00E-02 3.60E+01 Burner Manufacturer 9.33E-02 : : "manuf.+1045" H2S 0.00E+00 Benzene 2.33E-06 2.10E-03 AP -42 Table l.4-3- • 2.33E-06 Not reported on APEN; I Used AP -42 factors Toluene 3.78E-06 - 3.40E-03 AP -42 Table 1.4=3-.- 3.78E-06 Not reported on APEN;) used AP-03factors Formaldehyde 8.33E-05 - 7.50E-02 AP42 Table 1-4-3:'- ' 8.33E-05 Not reported on APEN; Lsert AP -42 factors n -Hexane - 200E-03 1.80E+00 AP-42'Table 1:4-3 - ; • - 2.00E-03 Not reported on APEN;. R. used AP -42 factors ... " POM 0.00E+00 0.00E+00 APv42•Table 1.4-2"' - 0.00E+00 Ftrxt reported ort APEN tiauedAl#-42'factors; ' "'" Methane 2.56E-03 2.30E+00 AP-42Teble: 1.4-2:- - 2.56E-03 Not reported oreAPENfiu:used:Alf42 factors AP 42 chl.? pipeline NG HV 900 btu/scf Section 05 - Emissions Inventory AP42"1.3 lb/MMBtu Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits ton/31-day lb/31-day ®' d 1.8 .1.8 1.8 1.8 r • �. ®° • r r • r 0.0 24 9.E4 9.6 9.6 9.64 9.6 0.8 1637 MEM 438 4.6 4.6 4.6 4.6 M3E3IIMIMIIM MEI= 9.6 9.6 ' 9.6 9.6 IMIED353111111 Hazardous Air Pollutants Formaldehyde Potential to Emit Uncontrolled (tons/year) 0.00 0.00 0.00 rr MIMM Methane 0.00 Actual Emissions Uncontrolled Controlled (tons/year) (tans/year) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 06 0.0 0.6 Actual Emissions Uncontrolled Controlled (lb/yr) (lb/yr) r eMEM t t �' 40 964 40 964 001 Heater K:\PA\2017\17 W E0398.CP 1.xlsm Section 06 - Regulatory Analysis Regulation 6 Part B, section 11.6.2 Yes Constructed, reconstructed, or modified after 1/30/19797 This heater/boiler is subject to the requirements of Regulation 6, Part 8, Section ❑.C.2. NSPS Db No Design input capacity greater than 100 MMBtc/hr? No This heater/boiler is not subject to the requirements of NSPS Db. NSPS Dc Yes Meets definition of steam generating unit? Construction/ modification/ reconstruction commenced after 6/9/1989? Yes Design input capacity between 10- 100 MMBtu/hr (inclusive)? Yes Meets definition of temporary boiler? No Only fuel used is natural gas? Yes - This heater/boiler is subject to the requirements of NSPS Dc. Is an affected facility associated with combustion turbines and that meets applicablity req'ts of NIPS KKKK? Is an affected facility that meets applicablity req'ts of and is subject to NSPS AAAA or CCCC? No' Is an affected facility that meets applicablity req'ts of and is subject to an EPA approved State or Federal section 111)d)/129 plan implementing NIPS BBBB? Is an affected facility that also meets applicablity req'ts under NSPS J orJa? Because the heater uses only natural gas as fuel, requirements are limited to reporting and recordkeeping (such as documenting fuel consumption). Regulation 8 & NESHAP/MAR Facility is a major source of HAP? Area source - Meets definition of boiler? No MACr DDODD No Adapted into CO Reg 8 as amended 11/20/2015 This unit is mot subject to Reg 8. Section 07 - Initial and Periodic Sampling/Testing Initial complrance:.test fee NOx and CO Section 08 -Technical Analysis Notes The source provided documentation for heater manufacturer emission factors_Asheaters have not been specified, testing of heaters to confirm emission -factors for NOx and CO is required. Source resubmitted heater APEN on 1/18/18 using calculations with HI -IV of gas than LNV. ter is subtec€to. ¢JSP3- Cc.'riteltdateeis in t subiec1MACT DDDDD dct tubeing an:area a0sarce ye included NSPS A requirements as well, due to being subject to Dc. On the list of"not subject"? MACE JJJJJJ No Not yet adopted into CO rules Section 09 -Inventory SCC Coding and Emissions Factors Pollutant Uncontrolled Emissions Factor Units 10200662 -- Extemnut Cambustlon Boiler: industrial: Natural. Gas:10 -100 MhAEltuthr PM30 6.71 lb/MMscf PM2.5 6.71 lb/MMscf SOx 0.53 lb/MMscf -NOx 36.00 lb/MMscf VOC 17.10 lb/MMscf CO 36.00 lb/MMscf H2S 0.00 lb/MMscf Benzene 0.00238 lb/MMscf Toluene 0.003853333 lb/MMscf Formaldehyde 0.085 lb/MMscf n -Hexane 1.80E+00 lb/MMscf 001 Heater K:\PA\2017\17 W E0398.CP1.xlsm Section 01- Administrative Information Facility AIRS ID: County 9F22 Plant titi2 •• T7 mole sieve heater Point Section 02 - Equipment Description Details Number heaters/boilers 1' One MMBtu/hr MMBtu/hr Manufacturer TBD Design input 18.4 Model No. T:BD• Design output Serial No. TBD Equipment type/purpose molecular aieve;regeperation heater ' Fuel type natural:gas'; '. Fuel source pipeline Low NOx burners? Yes - NOx control efficiency 0% ... Detailed Emissions Unit One (1) input rate 18.36 MMBtu/hr molecular sieve regeneration heater. This unit is fueled by Description: natural gas from the pipeline. This unit is equipped with low NOx burners. Add-on Emission Control Device: Pollutants controlled: Control Device Emissions Reduction %: Section 03 - Processing Rate Information Notes Heater Design Rate = 18.4 MMBtu/hr Requested Permit Limit = 18.4 MMBtu/hr Hours of Operation = 8760 hr/yr Fuel Heat Content = 900 Btu/scf Fuel H2S Content = 3.1 ppm Requested Fuel Consumption Limit= 178.7 MMscf/yr 15.2 MMscf/month 11 MM,:(•• : ^n, None^ I. Stack test results, if available Year heater/boiler ID CO Ib/MMBtu NOn Ib/MMBtu PM2.5 Ib/MMBtu Section 04 - Emissions Factors & Methodologies AP -42 ch1.4 pipeline NG HV 900 Heater duty Efficiency btu/scf boiler type small (<100); contr-Low Nox Pollutant Ibs/MMBtu lb/MMscf Source Ib/MMBtu Notes PM10 . --T.45E-03'. � 6.71E+00 AP.-42.Table1.42: 8.44E-03 AP -42 Chapter PM2.5 7.45E-03 ' 6.71E+00 AP -42 Table 1.4-2 8.44E-03 _,. AP -42. Chapter SOx : 'S,88E-04 - 5.29E-01 AP-42Table 142 -'. 6.67E-04 AP -42 Chapter - . 1.4 NOx 4.00E-02 3.60E+01 Burner Manufacturer 3.56E-02 "manuf.+10%" VOC 5,90E-02 1.71E+01 Burner Manufacturer 6.11E-03 "manuf;440, CO . 4.00E-02 3.60E+01 Burner Manufacturer 9.33E-02 "manuf.a-IO%" H2S 0.00E+00 Benzene '!:.'.4.33E-06 2.10E-03 AP-42Tablel4-3'--::, 2.33E-06 Not: repDttedonAPEN.l used AP-42factors: .:: Toluene 3.78E-16 3.40E-03 AP -42 Table 1.4-3 ` 3.78E-06 Not reported on APEN; I used AP -42 factors . Formaldehyde . - 8.33E-05 7.50E-02 AP -42 Table 1.4-3 8.33E-05 Not reported on APEN; I used AP -42 factors n -Hexane 1.80E+00 AP-42Table 1.4-3":-- ..- Not reported onAPEN I-usedAP-42.factors- POM - --0.00E+00'' , 0.00E+00 AP-42`:Table142:_ :::,•. :;. 0.00E+00 Not reported on APEN I:usedAP-42'fae'tors. Methane 256E-03 2-30E+00 AP-42Table 1.4-2 .. 2.56E-03 Not reported on APEN; I used AP -42 factors . --' Section 05 - Emissions Inventory Criteria Potential to Emit Requested Permit Limes Actual Emissions Pollutants Uncontrolled Uncontrolled Controlled Uncontrolled Controlled Requested Permit Limits (tons/year) (tons/year) (tons/year) (tons/year) (tons/year) ton/31-day lb/31-day Reportable? PM10 0.6 0.6 0.6 0.6 0.6 0.1 102 no PM2.5 0.6 0.6 0.6 0.6 0.6 0.1 102 no SOx 0.05 0.0 0.0 0.0 0.0 0.0 8 no NOx 3.2 3.2 3.2 3.2 3.2 0.3 546 YES VOC 1.5 1.5 1.5 1.5 1.5 0.1 260 YES CO 3.2 3.2 3.2 3.2 3.2 0.3 546 YES Potential to Emit Actual Emissions Actual Emissions Hazardous Air Uncontrolled Uncontrolled Controlled Uncontrolled Controlled �,:�' ," • 14.22 0.91 002 Heater K:\PA\2017\17 W E0398. C P 1. x l s m �" "' (tons/year) (tons/year) (tons/year) (Ib/yr) I (lb/yr) Reportable? H2S 0.00 ,, y 0.0 0.0 0 0 no Benzene 0.00.,,ro, ` 0.0 0.0 0 0 no Toluene 0.00 �.m. ➢ 0.0 0.0 1 1 no Formaldehyde 0.01 0.0 0.0 13 13 no -:U.Y6khKW��//.tlyN/d/A n -Hexane 0.00 ---- `-- - 0.2 0.2 322 322 YES 002 Heater K:\PA\2017\17WE0398.CP1.xlsm POM 0.00 0.0 0.0 0 0 no Methane 0.21 0.2, 0.2 411 411 YES Section 06 - Regulatory Analysis Regulation 6 Part B, Section II.C.2 Yes Constructed, reconstructed, or modified after 1/30/1979? Yes This heater/boiler is subject to the requirements of Regulation 6, Part B, Section II.C.2. NSPS Db No Design input capacity greater than 100 MMBtu/hr? No This heater/boiler is not subject to the requirements of NSPS Db. NSPS Dc Yes Is an affected facility associated with Meets definition of steam generating combustion turbines and that meets unit? Yes applicablity req'ts of NSPS KKKK? No Construction/ modification/ reconstruction commenced after Is an affected facility that meets applicablity 6/9/1989? Yes req'ts of and is subject to NSPS AAAA or CCCC? No Is an affected facility that meets applicablity req'ts of and is subject to an EPA approved Design input capacity between 10-100 State or Federal section 111(d)/129 plan MMBtu/hr (inclusive)? Yes implementing NSPS BBBB? No Is an affected facility that also meets Meets definition of temporary boiler? No applicablity req'ts under NSPS J or Ja? No Only fuel used is natural gas? Yes This heater/boiler is subject to the requirements of NSPS Dc. Because the heater uses only natural gas as fuel, requirements are limited to reporting and recordkeeping (such as documenting fuel consumption). Regulation 8 & NESHAP/MACT Facility is a major source of HAP? Area source On the list of "not subject"? Meets definition of boiler? No Natural gas boilers are not subject MACE DDDDD No MACT JJJJJJ No Adopted into CO Reg 8 as amended 11/20/2015 Not yet adopted into CO rules This unit is not subject to Reg 8. Section 07 - Initial and Periodic Sampling/Testing Initial compliance test for NOx and CO No Section 08 -Technical Analysis Notes The source provided documentation for heater manufatturer emission factors. As heaters have not been specified, testing of heaters to confirm emission factors for NOx and CO is required. Source resubmitted heater APEN on 1/18/18 using calculations with HHV of gas rather than LHV. The heater is subject to NSPS Dc. The heater is not subject MALT 00000' due to being an area source for HAPs.. I have included NSPS A requirements as well, due to being subject to Dc: Section 09 - Inventory SCC Coding and Emissions Factors SCC Code 10200602 —External Combustion Boiler: Industrial: Natural Gas: 10- 100MMBtulhr PM10 6.71 Ib/MMscf PM2.5 6.71 lb/MMscf SOx 0.53 lb/MMscf NOx 36.00 lb/MMscf VOC 17.10 lb/MMscf CO 36.00 lb/MMscf H2S 0.00 lb/MMscf Benzene 0.00238 lb/MMscf Toluene 0.003853333 lb/MMscf Pollutant Uncontrolled Emissions Factor Units 002 Heater K:\PA\2017\17 W E0398. CP1.xls m Formaldehyde 0.085 lb/MMscf lb/MMscf n -Hexane 1.80E+00 Dropdown lists Equipment type/purpose hot oil heater I amine regeneration heater molecular sieve regeneration heater stabilization heater boiler OTHER: Emission Factor Source AP -42 Table 1.44 AP -42 Table 1.4-2 AP -42 Table 1.4-3 Burner Manufacturer OTHER: Fuel type pipeline natural gas field natural gas ultra low sulfur diesel propane I distillate oil (fuel oil #1 or #2) residual oil coal wood OTHER: Fuel source pipeline plant gas system OTHER: Y/N Yes No HAP Major source Area source ILE Yes No SCC 10200601-- External Combustion Boiler: Industrial: Natural Gas: > 100 MMBtu/hr 10200602-- External Combustion Boiler: Industrial: Natural Gas: 10 -100 MMBtu/hr 10200603-- External Combustion Boiler: Industrial: Natural Gas: <10 MMBtu/hr 10200604-- External Combustion Boiler:. Industrial: Natural Gas: Cogeneration 10200701-- External Combustion Boiler: Industrial: Process Gas: Petroleum Refinery G 10200710-- External Combustion Boiler: Industrial: Process Gas: Cogeneration 10201001-- External Combustion Boiler: Industrial: Liquified Petroleum Gas (LPG): But 10201002-- External Combustion Boiler: Industrial: Liquified Petroleum Gas (LPG): Pro 10201003 --External Combustion Boiler: Industrial: Liquified Petroleum Gas (LPG): But 10300601-- External Combustion Boiler:, Commercial/Institutional: Natural Gas: > 100 10300602-- External Combustion Boiler: Commercial/Institutional: Natural Gas: 10-11 10300603-- External Combustion Boiler: Commercial/Institutional: Natural Gas: < 10 I). OTHER: 10200601 -- Exter' al Comb in 1,istrial: Natural Gas: > 100 MMB1 1020060 External Comb Industrial: Natural Gas: 10 - 100 MN 10200603 -- External Comb industrial: Natural Gas: < 10 MMBtu 10200604 -- Este, :al Cbnb h:dustr:ai: - Natural Gas. Cogeneratio 10200/01 -- E:+:ermai Comp industrial- Process Gas: Petrmeurn:R 10200✓10 -- External Can:: Industrial: Process Gas: Cogeneratio 1O1r" 001 -- Extar :a1 Comb I.,dustnial: Liquified Petrole Butane 102C1CO2--'cx`er,:,lCombindnfrial: Liquified Petrole Propane 10200003 External Comb Industrial: Liquified Petrole Butane/Prqu 1 10300601 — Exte:: al Come Commercial/institu Natural Gas: > 100 MMBt 10300602 -- External Comb Commercial/Institu Natural Gas: 10. 100 MM 10300603 -- E,te• iai Comb Commercial/Institu Natural Gas: < 10 MMBtu 002 Heater K:\PA\2017\17WE0398.CP1.xlsm K:\PA\2017\17WE6398.CP1.xlsm K:\PA\2017\17 W E0398. CP1.xism K:\PA\2017\17WE0398.Cpl.xlsm u/hr iatujhr elhery Gas 002 Heater K:\PA\2017\17W E0398.CP1.xlsm Section 01 - Administrative Information Facility AIRS ID: County Plan Point Section 02 - Equipment Description Details T2 mole sieve heater Number heaters/boilers 1, --)- One MMBtu/hr MMBtu/hr Manufacturer 1PD Design input 15.1 3 Model No. TADS Design output Serial No. Equipment type/purpose ;malecularsieve regeneratior heater:...",, _ _. = -: Fuel type nasurallgas Fuel source pipeline '. Low NOx burners? lea NOx control efficiency Detailed Emissions Unit One (1) input rate 18.36 MMBtu/hr molecular sieve regeneration heater. This unit is fueled by Description: natural gas from the pipeline. This unitis equipped with low NOx burners. Add-on Emission Control Device: Pollutants controlled: Control Device Emissions Reduction %: Section 03 - Processing Rate Information Notes Heater Design Rate = 18.4 MMBtu/hr Requested Permit Limit= ,` ' - 1a 4i.;MMBtu/hr Hours of Operation = 6760:hr/yr Fuel Heat Content = 900- Btu/scf Fuel H2S Content = 3.i ppm Requested Fuel Consumption Limit = 78.7' MMscf/yr 15 MMscf/month 15 MliAscf/rnonth Stack test results, if available Year heater/boiler ID CO Ib/MMBtu NOx Ib/MMBtu PM2.5 Ib/MMBtu Section 04 - Emissions Factors & Methodologies boiler type AP -42 ch1.4 pipeline NG HV 900 , Heater duty Efficiency btu/scf 11 Pollutant lbs/MMBtu Ib/MMscf Source lb/MMBtu Notes 14.22 0.91 PM10 6.71E+00 8.44E-03 A PM2.5 745 6.71E+00 8.44E-03 SOx 4 5.29E-01 AP v. ib 4 6.67E-04 NOx 3.60E+01 fFK 3.56E-02 ii 1+ VOC 1.71E+01 adufac 6.11 E-03 in CO 4. 3.60E+01 urn 9.33E-02 H25 0.00E+00 Benzene 2.10E-03 AP-42Tabie'1.4-3' -= A AP -42 Table€7;A AP 4E' Table IASP 42Tab1e=1.4�-�.- AP-42•Tabiel4 2 2.33E-06 3.78E-06 Not reported on APEN;: €;used AP -42 fad Not reported, onAPEN lusedA Not reported on APEN, l"ufedAP'-42 factors Toluene 3.i8E-06 '. 3.40E-03 2 Tabl&l. 4 Formaldehyde 33€.A5,.1° 7.50E-02 8.33E-05 n -Hexane 1.80E+00 epo[ted on APEN. i used. AP -42 tacto POM • 0.00E+00 2.30E+00 0.00E+00 2..56E-03 n AP. 5N, 1 used AP -42 faefors;'. Methane E0 AlptiePaiitedian..Ap ise,AF-42 Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits ton/31-day lb/31-day Reportable? PM10 0.6 0.6 ' 0.6 0.6 0.6 0.1 102 no PM2.5 0.6 0.6 0.6 0.6 0.6 0.1 102 no SOx 0.0 0.0 0.0 0.0 0.0 0.0 8 - no NOx 3.2 3.2 3.2 3.2 3.2 0.3 546 YES VOC 1.5 1.5 1.5 1.5 1.5 0.1 260 YES CO 3.2 3.2 3.2 3.2 3.2 0.3 546 . YES Hazardous Air Potential to Emit Uncontrolled ;, ` J. Actual Emissions Uncontrolled Controlled Actual Emissions Uncontrolled Controlled . 003 Heater K:\PA\2017\17W E0398. CP1.xlsm a, IL.D(tons/year) , , (tons/year) (tons/year) - (Ib/yr) I (Ib/yr) Reportable? H2S 0.00 0.0 0.0 0 0 no Benzene 0.00 "- - 0.0 0,0 0 . 0 no Toluene 0.00 ; ; 0.0 0.0 1 1 no Formaldehyde 0.01 0.0 0.0 13 13 no n -Hexane 0.00 `, �,,,;��-�, 0.2 0.2 322 _ 322 YES 003 Heater K:\PA\2017\17WE0398.CP1.xlsm POM 0.00 0.0 0.0 0 0 no Methane 0.21 0.2 0.2 411 411 YES Section 06 - Regulatory Analysis Regulation 6 Part B, Section II.C.2 Yes Constructed, reconstructed, or e _ modified after 1/30/1979? This heater/boiler is subject to the requirements of Regulation 6, Part 8, Section II.C.2. NSPS Db No Design input capacity greater than 100 MMBtu/hr? This heater/boiler is not subject to the requirements of NSPS Db. NSPS Dc Yes Meets definition of steam generating unit? Construction/ modification/ reconstruction commenced after 6/9/1989? No Design input capacity between 10-100 MMBtu/hr (inclusive)? Yes Meets defintion of temporary boiler? Only fuel used is natural gas? This heater/boiler is subject to the requirements of NSPS Dc. Because the heater uses only natural gas as fuel, requirements are limited to reporting and recordkeeping (such as documenting fuel consumption). Is an affected facility associated with combustion turbines and that meets applicablity req'ts of NSPS KKKK? Is an affected facility that meets applicablity req'ts of and is subject to NSPS AAAA or CCCC? No . Regulation 8 & NESHAP/MACT Facility is a major source of HAP? Area source Meets definiion of boiler? No - . MACPDDDDD No Adopted into CO Reg 8 as amended 11/20/2015 This unit is not subject to Reg 8. Section 07 - Initial and Periodic Sampling/Testing Is an affected facility that meets applicablity req'ts of and is subject to an EPA approved State or Federal section 111(d)/129 plan implementing NSPS BBBB? Is an affected facility that also meets applicablity req'ts under NSPS J or Ja? On the list of "not subject"? Natural gas boilers are not subject MACE JJJJJJ No Not yet adopted into CO rules Section 08 -Technical Analysis Notes The source peonided, documental on for heater malibfaetar r em sstc is factors. As treaters. have not been spec confirm emission; factors for NOx and CQ'is.r'equired' Source resubmitted; heaterAPENcm 1/18/1.8 using calcutat rather LhanEHV SCC Code !,,,i,i!izaltRpg9,Rgg,EAsmq Industrial t atural as iu Section 09 - Inventory SCC Coding and Emissions Factors Uncontrolled Pollutant Emissions Factor Units PM10 6.71 Ib/MMscf lb/MMscf Ib/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf Ib/MMscf PM2.5 6.71 SOx 0.53 NOx 36.00 VOC 17.10 CO 36.00 H2S 0.00 Benzene 0.00238 003 Heater K:\PA\2017\17 W E0398.CP1.xlsm Toluene 0.003853333 lb/MMscf Ib/MMscf Ib/MMscf Formaldehyde 0.085 n -Hexane 0 Dropdown lists Equipment type/purpose hot oil heater I amine regeneration heater molecular sieve regeneration heater stabilization heater boiler OTHER: Emission Factor Source AP -42 Table 1.4-1 AP -42 Table 1.4-2 AP -42 Table 1.4-3 Burner Manufacturer OTHER: Fuel type pipeline natural gas field natural gas ultra low sulfur diesel propane I distillate oil (fuel oil #1 or #2) residual oil coal wood OTHER: Fuel source pipeline plant gas system OTHER: Y/N, Yes No HAP, Major source Area source Yes No SCC 10200601— External 10200602 -- External 10200603 --External 10200604 -- External 10200701-- External. 10200710-- External 10201001-- External 10201002 --External 10201003-- External Combustion Boiler: Industrial: Natural Gas: > 100 MMBtu/hr Combustion Boiler: Industrial: Natural Gas: 10 -100 MMBtu/hr Combustion Boiler: Industrial: Natural Gas: <10 MMBtu/hr Combustion Boiler: Industrial: Natural Gas: Cogeneration 10200601 -- External Comb Industrial. Natural Gas: > 100 NIMBI 10200602 -- External Como I-rdustnal: Natural Gas. 10 - 100 MN 10200603 -- External Coma: Industrial: Natural Gas: < 10 MMBru 10200604 -- External Comb. industrial Natural Gas. Cogenerat:o Combustion Boiler: Industrial: Process Gas: Petroleum Refinery G 102 00701 -- External Comb Industrial: Process des; - Petroleum R 10200710 -- External Comb ladustriai: Process Gas: Cogeneratio Combustion Boiler: Industrial: Process Gas: Cogeneration Combustion Boiler: Industrial: Liquified Petroleum Gas (LPG): But Combustion Boiler: Industrial: Liquified Petroleum Gas (LPG): Pro Combustion Boiler: Industrial: Liquified Petroleum Gas (LPG): But 10300601-- External Combustion Boiler: Commercial/Institutional: Natural Gas: > 100 10300602-- External Combustion Boiler: Commercial/Institutional: Natural Gas: 10 - li 10300603-- External Combustion Boiler: Commercial/Institutional: Natural Gas: < 10 h OTHER: _0201001 -- External Comb industrial: Liquified Petrole Butane 10201002 -- Eaternai Comb Industrial: Liquified Petrole Propane 10201003 -- External Comb Industrial: Liquified Petrole Butane/Pro 10300601 -- External Comb Commercial/Institu Natural Gas: > 100 MMBt 10300602 -- External Comb Commerc el/Institu Natural Gas: 10 -100 MA/ 10300603 -- External Comb Commercial/Inntito Natural Gas: < 10 MMBtu 003 Heater K:\PA\2017\17WE0398.CP1.xlsm wsIx•Ldy86£03MLi\LEOZ\Vd\:N 003 Heater K:\PA\2017\17WE0398.CP1.xlsm K:\PA\2017\17VVE0398.CP1.xlsm- 13th /hi .eEr`,ery Gas )a+me Mixture! specify %butane in comments K:\PA\2017\17 W E0398. CP1. xlsm Glycol bettydrator Emissions Inventory. Section 01-Admbdslattee Information Fadlity AWN ID: ss e: ..�. M-2:: County Plant Poi Section 02- Equipment Desglppon Detells Amine Sweetening Utdtlnformation Amine Type: Make: Model: Serial Number. Design Capacity: Redreula0on Pump Information Number of Pumps Pump Type Make: Model: Design/Max Recirculation Rate: Amine Unit Equipment Flash Tank Rebciler Burner Stripping Gas Dehydrator Equipment Description Em iss ion Control Device Description: , flash tank, and reboiler burner Volume Process Limits Gas Processed to amine unit 55,845 mmsd/yr Still Vent Waste Gas 2736 mmscf/yr Supplemental Fuel for Thermal Oxidizer 236.2 mmscf/yr Flash Gas to Flare During up to 2190 hrs of VRU downtime 24.1 mmscf/yr 4743 nensef/mo 237.5 mmscf/mo 20.1 mmscf/ma 2.0 mmscf/ma Methyidiethmmlamine (MOEA) natural gas sweetenirgsystem for add gas removal with adesigntapatity of 153 MMsef/day (Make: MD: Model: MD; 5N:TBD). Thisemisionsurdt is equipped with Three(3)emine reeeeule0on pumps with a total limited rapacity of Goo gallons per minute of lean amine. Tha system includestwo )2) natural gas/amine contactors, a flash tank, still vent, and an indirect fired hot oil amine regeneration reboiler (point The amine flash stream is muted to a closed loop system thet utilizes a vapor recovery unit (maximum 2190 hours annual downdme). Emissions during the dowmimewili be muted tea flarewkh 30% desoucu'on efficiency (AIRS Point 005(. The acid gasstreamfmmthe still overheads is routed too thermal oxidizer (Make: TBD: Model: TED; SN: TBD) rated at 27.5 MM9to/hrwith a minimum destruction efficiency of 9.3%. Section 03-Ru.eving Remirtformatianfor Emissions Exfma,es Primary Emissions -Amine Acid Gas and Flash Tank Requested Permit UmltThroughput= , _ _. ,„) SUi8461i1:MMsd per year Potential to Emit (PTE) Throughput = 55,845 MMsd per year Secondary Emissions.. Combustion Devise(s) for Air Pollution Control Still Vera Control Primary control devim: Primary control devim operation: Secondary control device: Secondary control device operation: Still Vent Gas Heating Value: Still Vent Waste Gas Went Rate: Flash tank Control Primary control doubt: Primary control device operation: Secondary control device: Secondary control desire operation: Flash Tank Gas Hearing Value Flash Tank Waste Gas Vent Rate: 4743 MMscf per month Still Vent Primary Control: Still Vent Secondary Control: Soil Vent Primary Control: Still Vent Secondary Control: 1230E+00 MMBtu/hr Flash Tank Primary Control: Flash Tank Secondary Control: Flash Tank Primary Comtral: Flash Tank Secondary Control: (Unbuffered) Wet Gas Processed: 55,845.0 MMsd/yr 0.0 MMsd/yr Waste Gas Combusted: 1,597.7 MMsd/yr 0.0 MMscf/Yr Wet Gas Processed: 41,883.8 MMsd/yr 23,361.3 NINIscf/yr Waste Gas Combusted: 0.0 MMsd/yr 132 MMsd/yr 9ammeeted aar� rl:sxorn-roe, c=e�r•mn. 1356963 s MMsfr/yr 237.468525 MMai•mo 1.167925 Mtcht 16rnr,.o Glycol Dehydrator Emissions Inventory Section 04- Emissions Fectnrs & Methodologies Amine Unit Input Parameters Inlet Gas Pressure Inlet Gas Temperature Requested Glycol Recirculate Rate Supplemental Fad Total TO Bumerilating Heat content WaterlbmoVhr Carbon Oiodde Ibmo3hr Hydrogen Sulfide lbmothr Nitrogen Ibmdlnr Methane Ibmnfht Ethaneomn0hr Propane Ibmollhr n-Bulane hnnL64 iso-nutane mn50 r n -Pentane IhmnMir Isc-Pentane Ibmothr CycloPentane lbmoohr n -Helena Ibmol/hr CyloloHexane IbmoVhr 275 MM9tu/hr 1020 btu/scf Still Vent Fimh Tank 2.72E+01 0.52E+02 5.05E-02 34.08 3.23E-04 8.55E-01 2.6E-01 6,550E-02 44.1 2.70E-02 58.12 1.15E-01 5812 3.32E-03 72,15 3.52E-03 72.15 3.95E-05 70.1 1.78E-03 86.18 Benzene 'Mimi/lir .5.84E-02 nHeptane Ibmol/hr 2 -Methyl Hexane Ibmol/hr Toluene Ibmol/hr n -octane Ibmol/hr Ethyl Benzene Ibmol/hr o-Xylenelbmol/hr m-Xylene Ibmol/hr p-Xylene mmol/hr n-Oemne Ibmol/hr TOTAL VOCsr. 0.0 0.6 0.6 003 0.6 0.02 0,01 0.01 0.6 0.6 M 1621 100.2 92.14 114,23 105.17 10,.16 10636 14779 0.7731 1-446 0.00028595 0,016159 111105 2.0279 /;B% 0.6031 1.57 0.1966 6 T. 0,258 0_9 0.032674 21-5 0.034592 g O00069928 Nat, 0.014547 0.00053486 t 56 O.0oe686 0.15 0.0087637 0 0.000061471 2.73 339E-03 0.17 4.88E-03 7 1.51E-03 0.7 4.43E-04 OS 4.92E-06 3 1, 199003 45,79 2,65E+01 Mmbtu/In(Stillvent mmbtu/hy load wassubtractsd from TO burner rating 227.5613434 MMsd/yr 193 MMsc{/munch 236.2 MMsd/yr 20.1 MMacf/month ^Based on Total rating. S;�SL_'a9h 0.009745176 2659671 11.426392 1499496 23574291 2,4958128 0,049019528 125366041 0,045013818 0,625551746 0.878210377 0,66159394 0,293751534 0.557579476 0,16021053 0.046978985 0.032198872 0,208795488 0.197996535 175%buffer-> Unbuffered -5 108.93 Still Vent 287E+00 157E+6 6.68E+00 2.40E-01 254E-01 2.77E-03 1.54E-01 2,42E-03 456E+6 155E-01 9.98E-05 2,73E+6 1,66E-01 1.68E+6 736E-01 8,17E-01 327E+00 2,70E-01 45,76 62.24643064 25.15 Times 1.75 , After subtracting Still vent gas Still Vent Hash Component coal% HHV(9tu/scf) Water 5.65E+00 4.6726 0 092 9.40E+01 8.7392 0 NZ 6,71E-05 0,099478 0 methane 1.78E-01 671504 1010 ethane 4,79E-02 122564 1769.7 propane 1.35E-02 3,6448 2516.2 46.5442425 +sob Wane 2.40E-02 1.5591 3252 19996186 n -butane 5,61E-03 1.1883 3262.4 2624118sapentane 7,40E-04 0,2133264 4069 4.125500925 n -pentane 6,91E-04 0,1975 4008.7 43676724 Hexanes (Avg of 2-8 0,632327 4748,85 0,085784174 heptanes 0.6 0.05333833 5502.5 2,193905805 Octanes+ (Avg of CE 0.6 2.95E-02 6996.1 0.078774181 Nonanes 6996.4 1.094715556 Oecanes+ 0,00 0,0084101 7743 133686816 Benzene 1.22E-4)2 0.0048403 37419 0,01072894 Toluene 0.01 193E-02 44749 0514065185 Ethylbenzene 0.6_ 9.12E-03 5222 0.975764083 Xylenes (Avg of o, n 0.01 1.75E-02 5208.7 0280368428 n -Hexane 3.71E-04 -0.087921 4756 0.082213223 224-TMP (LHV/HHV 0 62489 0.091348026 52S 1.05E-02 0.617239 637.1 03653srzna 16 0,346493936 Higher Heating Valu 555E+6 1105.181275 littu/scf Glycol Dehydrator Emissions Inventory STILLVaNT Pollutant VOC H2S Benzene Toluene Ethylbernene Xykces ndiexa0, 224-TMP OA/1th 175% buffer) UncoNmtled (Ib42r) i�)4S7917Fb^1FI Control Scenario Primary 003531ed (ib/hr) 0.9579 0.0172 0.0656 0.0273 0.0168 0.0483 0.0015 Secondary Controlled (IWhr) 0.9158 0.0349 0.0912 0.0596 0.0331 0.091c 0.003 itklee eeemfateEepeee INIIIIMSWeeeee MieeeeetWeiiiiti S02 (Reduced from H25 by cwnbus6on) FLASH TANK Pollutant VOC 025 Benzene Toluene Ethylbenzene. Xylerres n -Hexane 224.TMP •:Y:,a:: 4:_;3:i1 ::ii) ;j:..:a•. 3233377934 Urocntrolled (lb/br) ©I 3.201041155 3.168710376 Control Scenario PrNnry Secondary Controlled (Ib(hr) Conde phew) 2178623072 0.000195909 0.012511035 0.005871031 0.003204211 0.006159967 0.025073209 L ''zb6b175' %' :'0,6286 :sill 9921071063 r; leieVidoDkeetiOAP SO2 (Reduced from H2S by combustion) 0.018319671 0.017953279 Fin (0502 H2s SO2 1 and )6 1 3(60 Molecular weight (9/mol) 100% conversion 34,08 04.066 Emission Factors Pollutant Amine Untt Uncontrolled Controlled (Ib/MMsci) (Ib/MMscf( (Wet Gas Throughput) (Wet Ges Throughput) 300 H25 0.270 11.976 Benzene 0.739825559 Toluene Ethylberuene %ylene 0.439754962 0.269812178 0.769724445 0.072692567 Emission Factor Source 0.179 0.003 0.00764357 0.004512746 0.002760949 0.007818018 0.001218557 224 TMP Pollutant Still Vent Primary Control Device Emission Factor Source Uncontrolled (Ib/MMBtu) (Ib/MMscf) (Waste Heat (Waste Gas Combusted) Combusted) Uncontrolled 185110 P15125 502 NOx CO VOC 0.0410 0.0410 100.0000 84.0000 5,5450 09 ,f,n2 Ca:+frn wr_ tImontm,:ed ;rh?tr41'bdn» .le/Mtclwl 'Wsstedeat 'War Combusted) ^.amber, •a, ,1 QUM ),0401 1.:.0011 PN12.5 f/Mr Flash Taniromrai Cevina ll.icaaxw'ec•: e. culled •:4a5R Las etermetedt Emission Factor Source enttn 00 iggWOffi.ffO.• x,0 Pollutant Flash Tank Secondary Control Device Uncontrolled (ib/MMBtu) (Waste Heat Combatted) Uncontrolled (Ib/MMsci) (Waste Gas Combusted) PM10 615125 :'.iki3?79 502 NOx 12889 8.2889 NA 75.1523 3426062 Glycol Dehydrator Emissions Inventory Sectionos-Emissionslnventor( Old operator request a buffer? Requested Buffer (%): `See analysis notes Criteria Pollutants Potential to Emtt Uncontrolled (tans/year( Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Reg ested Permit Limits Controlled (lb/month) PM10 PM25 Nog CO VOC H25 502 0.1 0.1 0.1 0.1 0.1 15 0.1 0.1 0.1 0.1 0.1 15 123 123 123 123 12.32 2093 12.2 122 122 12.2 1223 2078 320.4 320.4 5.0 320.4 5.0 848 7.5 7.5 0.1 7.5 0.1 13 14.2 14.2 14.2 14.2 14.2 2409 Hazardous Air Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tans/year) Requested Permit Limits Uncontrolled Controlled (lb/yr) (lb/yr) Benzene Toluene Ethylbeneene Xylene n.Heoane 20.66 20,66 0.21 20.66 0.21 41316 427 12.28 1228 0.13 12.28 0.3.3 24558 252 7.53 7.53 0.08 7.53 0.08 15068 154 21.49 21.49 0,22 21.49 1122 42915 430 2.03 2.03 0.03 2.03 003 4060 68 Section 06- Regulatory Summary Anahys Please see PA asociated with Isseance 1. No regulatory applicability has changed Section 07- Initel and Periodic Semolina and Testing Requirements Was the extended wet gas sample used in the Process model site -specific and collected within a year of application submittal? If no, the permit will contain an "Filial Compliance" testing requirement to demonstrate compliance with emission limits Does the company request a control device efficiency greater than 95%fore flare or combustondevice7 If yes, the permit will contain and initial compliance test condplon to demonstrate the destruction efficiency of the combustion device based on iced and o Wet concentration sampling 6,9,08 -Tecinicel Analysis Rates StIMIenontoiwhtna are be#og/cn010therma#moidlcnr witha requeatedpontr stasistank;amastnnsma recycled ByVM6: A's zban6up,flash taitkamiisshrns.arasemtaahhe ptalu prom sffaxewitha.aontro4 pe A:stadktestw(I) cnnirm tho.9S% SOMMI,nn4Aestedforthetiarma/oxidlaen.:;, - - 1 ertttothe p13r+t pmcess)focm(Farm 005frvttth a.o 04rprperceutageof98 .._ imeuoto2140' hours part TfiBVRtr4ualtfes.as process mmrolaccorpingth the criteria of F5Mema954#5PPlanztion orovlded.ht soPmet;the ',alnory purpose *tot to control el Oh hmmnoonnffilash ays offre(ethe costatthoYOU i systecotthe VMt9 systemuwuidlia imtolled...offalrgna64yreguletlmss:wecenot to placGartdiheproces of vapor recovehnatutristopachentlieVR.Utellstoopetatettot, theVRrlsyst mopertatlonk Uocntcckedfuthovapar recovery pions). i Attiadstreani"Todehy" Is de"scdbeck =sloes toamoloeularsieve dehydrator, which does not anttgipatehaving anyemrssr4ns. FIao1/tank emas#orrscoutadt3the prowssflaredurmgVR)t downtime area«omcsn2for by the metering ofthe process Bare pombfned stream. Theaperator musetrack VR#t downtime andsuhttacttheexpected4ash- gasporttonMrtletotatmeteredgasthwogaputandepPtyiktotheem mNmirfdrtheammounieThe flash tank weetestream'is athludsally:meteaed:andPasho.issampiedsemt-Aonua)StDming20UdmAnlme, thesottocesliai4usethemost re ant onth'smeteredihronghpanand most recent sample ofthetlash-gassireamtoestimatethe Vdtem#ss)ormforth emrzre.un#tfrom this stream. Becausnibestremnsammmhtned a0thepnloess-}tare('Pomnt005fi theoperatfirmap?em0Vethe on)cuheed em) 100siromthe tote#cilculeteciVACerttfsiiOns from rrtet4trfng#anthe proce64here;hecauaethey have heamappllzd3o-01z2mlme emit and'+ i s#m At'ria1heoounted:againasthcNa ' . t..!:.:,.. Whilethe-operator has#ndtcaliedthata'splpkur remauatoyetem toasts attheplantasidefrom the.am#ne tlnte, the operatorhaastructdredits repoe@#or emissions canseivatively:ici Hausa 0fthis, t have removed marrti'mraf The-treatments/stern harnthe Rermit- - Stories requesting that secondary emibslens be calculated conservatively at₹he 25 nunb6/hr rating=Pthe thermal oxidizer for acid gasemunalors.Asth'is istbemuse canservatarthrwU)ao fuetprocess%mU and thewaste gas process hmiG sloesofs02ereconserdattvelyest3maiedusingamessba)ancecoH25.Thomasshalanee essumeothatTOM ofteH28 in the (espectivecomthterPdwastestreams)L cnmbtrstoroed701ueorwetted pietoly to 501 as followsr c.'''.'1.4$.041,0,0= edat(1Wh kNSooNac(m/)c tx.2O2MW)lb burin)(/H25MWt#bflbrno)( amp) present tt f4M1 area.5ourcewil)heyeanmtal/sem".annua)in)ectesting requirement aswal4as Initial tosttw'yonRi ) ca #1aspppNed a 175% halfectd,eatiPsionsfrom Both:th®30)11 verrtand24h4as.streams to account fnrvariahmtgirr gas, *Secondary cvnbustinn am)saon factorslor Rog, €0, and 50'2 were reportettiviinttsoflb/MMscfNatlaai0asT covghputct-e•naztua-gas pr farthesepoffulants are not bong retdse4, " y eshsmotfiecomYruct#ort date For this equipiatentwilt be after September 12,2Q25, the condrt)ran referencing MPS Subpart 0000 *Is ran edfrane.,belyeneAQowance 1, Osnd%on#54.-the applicable requtrelnenisforthtsam#ne unttwdthedn34SF55vbpart 0000a.5ince4he.AQE0hasriot o4eptedde#egationo€thisrulovie Ragulation6, a condition wfEefncluded lathe "notestopermit holder". AddR#on01hte a to to gzag00 ianrwouhtnp'rrn@sbelncludaktptestl2100mnensas,00 ooseaietZa encp5nofrommoatwfth0totebut= fn1e1) has otbeasadoptddhp0%era4Oatheteo4ng,s3dremnPtwgtsur0nt(amotbe _ i64,,d:tnkh eventoti .il ffa5t5'OW.Oa, ttisraw, ,..,,___, ri,,, ,..tud... WF!mllaceondhtonmayheffr,., it2t1arti2,.refereiufag.fast*.lpi•fulfillO gutrem4r*iiit#iy513g60ti iitiiOOO...; ;? thopgnthaTeq ameptsare;vtarttcaFf retainedf0rthl6 isstrame #nca the emtssf tsII Section 09-Inventory5CC Cedine and Emisiona Factors AIR5 Palm It 004 Processit SCC Code 01 Polhmzm PM10 PM2.5 502 NOx VOC CO Benzene Toluene Ethylbenzene Xylene n-Nagane H25 Uncontrolled Emissions Factor Control % 0.003 0 1314 0.657 Units 0.0% b/MMscf 0.003 0.0% b/MMscf 0.508 0.0% b/MMscf 0.441 0.0% b/MMscf 11.5 98.4% b/MMscf 0.438 0.0% b/MMscf 0.740 99.0% b/MMscf 0.440 99.0% b/MMscf 0.270 99.0% b/MMsct 0.770 99.0% b/MMsct 0.073 983%' b/MMscf 0.3 99.0'.4 b/MMscf Ex = emissions of pollutant Q= Volumetric flaw rateNolume of gas processed MW = Molecular weight of gas = SG of gas' MW of air Xx= mass fraction of x In gas C = molar volume of ideal gas (379 scf/Ib-mail) at SOF and 1 atm Maximum Vent Rate I 9417.890216 scf/hr Requestedlnounhput(0 82.5 MMscf/yr 9417.8 scf/hr l 0.226 MMscf/d I 7.01 MMscf/mo I % Vented ) 100% MW 23.690 lb/lb-mai Component mole% MW , Ibx/Ibmol mass fraction E 1h/hr lb/yr try Helium 0 4.0028 0000 0.000 Helium 0.0 0 000 CO2 3.274 44,01 1.441 0.361 CO2 358 3136`0 156.62 02 0.453 28.013 0.127 0.005 N2 3.2 27823 13.81 methane 70.917 16.041 11.360 0480 methane 282.3 2472770 1236.38 ethane 12.966 30.063 3.888 0.163 ethane 96.1 841956 420.98 ProPar0 9.268 44.362 4.0664 0172 propane 101.5 889530 444.76 iscbutane n -butane 0.300 0.672 58.118 58.115 0.1790 0.3906 0.008 0.016 sabutane a -butane 4.4 07 38905 00814 19.48 42.51 isopentane 0.182 72.114 0.1312 0.006 isopentane 3.3 2870 1426 n -pentane - 0.21 72.114 0.1514 0.006 e -pentane 3.8 32965 16.48 cyclapenlane 0.014 70.13 0.0008 0.000 cyclopentane 0.2 2137 1.07 n -Hexane 0.0980 86.18 0.0845 0.004 n -Hexane 2.1 18384 010 cyclohoxane 0.0420 84.16 0.0353 0.001 cyclahexane 0.9 7694 3.85 Otherhexarnes 0.112 86.18 0.0985 0.004 Other hexanes 2.4 21011 10.51 heptanes 0.35 10021 0.3507 0.015 Deplanes 8.7 76347 38.17 methylcyclnhexene 0.266 98.19 0.2612 0.011 methykyolohexane 6.5 56854 28.43 224-TMP 0 114.23 O.000Q 0.000 224-TMP 0.0 0 0.00 Benzene 0.042 78.12 0.0328 0.001 Benzene 08 -7142 3.57 Toluene 0.28 92.15 02500 0.011 Toluene 6.4 56165 28.08 Ethylbenzene 0.07 106.17 00743 0.003 Ethylbenzene 1,8 16178 8.36 Xylenes 0.266 106.17 0.2824 0.012 Xylenes 7.0 61475 30.74 C8+ Heavies 0400 116.000 0.4710 0.020 Ce+ Heavfes 11.7 102518 9126 425. Notes 99,996 VOC Source requested 0.0301 _ 34.08) mass faction: 02911 mass fraction: 0.22 Total Requested Total VOC . VOC Emissions (Uncontrolled) Emissions (Uncontrolled) 750.5 567.2 0.000034 0.0000014 0.001 7.42 0.00 • ' Mole %, MW, and mass fractions are based an 2016 analysis of process gas at KMG Lancaster Natural Gas Processing Plant Emissions are based on 8760 hours of operation per year. MW of 035 Is assumed to be 315 Produced Natural0 s Venting/Flaring Preliminan/ Analysis Section01-Administrative Information Faarrry AIRS ID: Section 02- Eauieraent Description Details Air assisted, elevated and open tip process flare to controlmaintenance acte des and purging of gas, as well as backup control for amine un0 (Point 004). Purge gas prevents low flashback problems to the fare and keeps the flame stable. The purge gas and pilot gas used is ales gas and helps the flaremaintain a minimum required positive flow through the system. This flare has a minimum flee tip. cross sectional area of (TED) square inches. Flare is granted 98% control efficiency when meeting control. requirements as stated in permit Flare is granted 95% control if unable to complywith control requirements. Assumes eontmuouscampliance with 40 cfr 60.18 as stated in permit Failure to comply results in 95% Control Efficiency 98% control for either month or quarter Section 03 -Processing Rate Information for Emissions Estimates Flare Pilot Rating 0.1728 MMB4i/hr 1.3623552 MMscflhr Fuel Gas Heat Value 900 Btu/se FlarePurgeGasRate . 290 acf/hr 0.261 MMetu/hr 2.5608 Process Gas 82.5 MMscf/yr 12.008 MMBtu/hr Process Gase Heat Value 1275 Btu/scf Hours of operation 8760 hr/yr Total Heat Input 12.4415 MMBtir/hr 86.7 MMscf/yr 7.37 eaev9mo Section 04 -Emissions Factors & Methodologies PURGE GAS Emission Calculation Method EPA Emission Inventory Improvement Program Publication: Volume II, Chapter 10 - Displacement Equation (10.4-3) Ex=Q`MW`Xx/C Ex= emissions of pollutant Q.= Volumetrie flaw rate/volume of gas processed MW = Molecular weight of gas = SG of gas' MW of air Xx = mass fraction of x in gas C = molar volume of ideal gas (379 scf/Ib-me) at 60F and 1 etm Maximum Vent Rate I 290 scf/hr RequesfedThroughput(01 250 MMatfM 285.4 scf/hr I 0.007 MMsof/d I oar MMscf/ne %Vented I 98% MW 23.69015/5-moI Component mole% MW Ibe/Ibmol mass fraction E lb/hr lb/yr try Helium 0 4.0026 0.000 0.000 Helium _ - 0.0 0 0.00 CO2 3.274 44.01 1.441 0.061 CO2 1.1 9505 4.75 N2 0.453 28.013 0.127 0.005 52 0.1 837 0.42 methane 70.817 18.041 11.360 0.480 methane e.6 74932 37.47 ethane 12.866 30.063 3.868 0.163 ethane 2.9 25514 12.76 prorane 9.288 44.362 . 4.0864 0.172 propane 3.1 28965 13.48 isobutane 0.308 58.118 01700 0.006 Isobutene 0.1 1181 0.59 n -butane 0.672 58.rre 0.3906 0.016 s -butane 0.3 2576 1.29 isopentane 0.182 72.114 0:1312 0.036 isopentane 0.1 660 0.43 n -pentane 0.21 72.114 0.1514' 0.006 n -pentane 0.1 999 0.500 cycloperrane 0.014 70.13 0.0098 0.000 cycloperrane _ _ -__ 0.0 65 0.03 n -Hexane 0.0980 • 86.18 0.0045 0.004 e -Hexane 0.1 557 0.28 cyelohexane 0.0420 84.16 0.0353 0.001 cyclohexane 0.0 233 0.12 Otherhexanos 0.112 85.18 0.0365 0.004 Otherheranes 0.1 637 0.32 heptarres 0.35 100.21 0.3507 0.015 heptanes _ 0.3 2314 1.16 melhykycleheeane 0.266 98.10 02612 0.011 methylcyclohexane 0.2 1723 0.86 224-TMP 0 114.23 0.0000 0.000 224 -TOP 0.0 0 0.00 Benzene 0.042 78.12 0.0328 0.001 Benzene 0.0 216 0.11 Toluene 0.20 92.15 02580 0.011 . Toluene 0.2 1702 0.85 Ethyibenzene 0.07 10617 0.0743 0003 Ethylbenzere 0.1 490 0.25 Xylenes 0.266 106.17 0.2824 0.012 Xylenes 0.2 1863 0.83 080 Heavies 0.406 116.000 0.4710 0.020 Cat Heavies 0.4 3107 1.55 99.996 VOC mass fraction: 0.2911 Total VOC Emissions (Uncortrolled). Source requested mass fraction: 0.22 Requested Total VOC Emissions (Uncontrolled) Notes 22.7 17.2 Mole %, MW, and mass factions are based on 2016 analysis of fuel gas et KMG Lancaster Natural Gas Processing Plant Emissions are bases on 8760 hours of operation per year. MW of CB+Is assumed to be 315 PROCESS GAS Emission Calculation Method EPA Emission Inventory Improvement Program Publication: Volume II, Chapter 10- Displacement Equation (10.4-3) Ex= Q' MWXx/C H2s assumption Vawmetnc Ppaaabpr 85 1 ppm ecfhr(enersdl•t/t.me0o01 0.220867312 mAsyr paean eta Oct 7.91626(051 INyr H26(34.08IblbmoR 18.12828835 Idyr 3O2 ibmol n¢5868O6msot amp, pom,.ma8 on-O6m6Oz1 Colorado Department of Public Heahh and Environment, • Air Pollution Control Division section 05 - ein'asions Inventory Produced Nat u I Gas Venting/flaring P Burn nary,An lys - Colorado pa t - "Cal - De rtmen ofA WiblieakN Headband YYA erk:-" Alt P0111 orC ntrol Elk Won 'rota .. - tPY, lb/re 773.2 Berrene 3,6793. - 7359 ' Toluene 28.9336 57867. - . Ethylts°nzene. 8:3339" 16668 >Woe_ 31.6689 . 63338 n -Hexane - 9.5- 18941 0 - Uncontrolled Criteria Pollutant Potential to Emit Uncontrolled (ions/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled - (tons/year) (tons/year) lb/31 day PM10 0,3 0.3 0.3 ' 0.3 0.3 56 P1112.5' 0.3 0,3 0.3 0.3 0.3 56 too, ' 3.8 3,8 3,8 3.8 3.8. 644 EO 17.8 - 17.0 17.0 17.0 17.0 2882 UPC 773.2. 773'.2 15,5 773.2 155 2627 r Hazardous Air Pollutants Potentalto Erna Uncontrolled . Actual Emissions Uncontrolled' Controlled Requester Permit Limo. Uncontrolled. Controlled Requested Permit Limrts Uncontrolled. Controlled (tons/year). _ (tons/Read irons/year) (tons/ycarl ttons/year) (nom (lo/yr) Benzene 3.68 3.68 0.07 3.68 8.07 7353. .147 Toruene 28.93 78,93 0.58 78.93 0.38 57867 1157 Ethylbenzene 8.33 8.33 0,17 8.33 _0.17 16668 333 Xylene 31,67 31.67 0.63 ' 31.67 0.63' .63338. 1267 n -Hexane 9.47 9.47 0.13 3.47 0-19 18941 379 224 TMP 0.40 Q.00 0.00 0.00 0.00 0 0 82.0,6645119 82.08645119 Section 06-Seeulatomoummary Analysis Regulation 3,Parm A,B Regulation 7. 5ectior)0Vll.0 Regulation 7,5ectian XV 11.6.22 Unit is required to have an APEN and a permit Unit is oat used to comply with Reg 7 Unit is.not as an alternative control device for Reg] Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Health and Environment Air Pollution Control Dssion Section 07 -Initial and Periodic Sampling and Testing Requirements Was a site -specific gas sample collected within a year of application submittal used to estimate emissions? If no, the permit mil contain an "Inclal Compliance" testing requirememto demorotratee compliancewih emission limits Does the company request a control device efficiency greater than 95%fora flare or combustion device? Destruction efficiency cannot be tested on an open flare. Section 08- Technical ilnalysie Notes TCiiSflaik i5',con₹anllPsriKettussinnr{Forit�iHbwdn al# e ru u;yboo pobict MG, bub.withauta . .. o. ..........._.... .. ... .._ aperatCr cldimz.thax aRiara wd4Les[,soseFl•tnatu�711'� aperazo .iotiawfngN5Prsl'eyaiflere t+prafiR@standardz•ihe�pgard₹f>x Oi ha reau7 ed as acond ECa of sett-certsi`Cgficn. Thaoper orimcfe NSPS'need§Yla be vefifFet fi9.Ygspecifie4th8k rlmimumits f Meebu makdoumtlare-tfpveloclty'boing d addedlr an equation In timmorobi this staadard,as hespoc`fY6asis for attalningbf% conffoii lianrtneli at r eek98%cantml'am�SMe 6aslso#!d"estgning: requisarnagtatbh oole.areaocsufflcinntto-nulyyuaranlen 986wntrolatralhti[nay. The mlhmion 4assesrrmanvandcsed-ifala faihsiachtonf zfteroperatun requnened DD% ntrof:lix the case of openfta es, thiscannopbmvensTed bystadcteen.7n®a- renorbean timed thou eronropdwiltbesuhs₹entiatlymore- fhaneneu¢losud,flare,bynirlue of khe fa,t that tite'apefatatwiif lumpily w€th ₹he requiremeatsaf46CFr 6{R &lietng lturb.a5fihetatlanate. Now ver,70afrEftd0= 3ppltae`ta flares,bVyirtue of?hem beingsub rctta-an NbP5, meantngthat ltdaesnotdisemgg6h between.enclbuitand:apeerflareo,uolivihermeatangful dlffayonee "'punitedbytheugeratornavenotbeensubstaatiatadandamevidencehasbeen.presemedforanyspecificatioasoftbe€tares befaati ap:indicataits;suheaibfty,addi nthepthan.ptlotignt redunda y, ospec cationshave _been.sisfmitad by Rh oparatui antvaactnalfiare-hasnot€teenct'rosenr llaeave,t'fle-up'er2tnr'ibrsirt4rzb0- n tflattheffare s"desigrtettta;oreetab cfr6D,Fa it utdnubeconstruodfll euaupe atiarr3Nat'wv €d be reluvanttodustnunion,efFlctency, slate cumpiianccnulthklteaale;y st to iha,aim maxngastia t g be.mzt and#aat rnaxinumfl metipvehacitybe.met.l'#i tiantaiStrf ttiettate, has nab rtrgaa;thslieatfngualteofgas. nonrmusfed-Th ras sellagatareaat₹he;flame%ipiaidesigrtalemantwhittarac[otttatckha equattansavetttingitame=i'stveledtyhuS: door ontafftettile auWsl' ti0°,''tyy Parar0.#1[:,,T,.tii rpsraer,tiaa,;tne helziiyiaaton:tafRaaf.tha Wanaae'AF'gy16,6aing,red ant anittarta,w.hi hl9,antiralyaaptbfilieoperubaimuprvcess. The equetiondesatibingeheallnwable fiame.thavelaeitytsa foetal'nthftfle.gattlattng htlue_zlte eperataeaclaimithat tlxeflargbetngdasigtied€acorriskaoat Mla requirnneantso€4Qpfl0.Z1lnenrno beaxingonthn flnne:being ahletn"acfiteve' a-highereoriitn'rstiorteff'iriency;: tha:regnaem.ants nt' tuhie%,:Ia are notilaring design spetbcaaoeh but rabher' irrutnsctone far operator no theeellmvablellnwto%Ifeflare on thetiaisaftbepare siae:endges heatingvalue.There-onenadesfgd-:- peci€icatioinsin speninatioitiaiatta€434}p,Sett based err paratiailaacordfngtothe ragateantentcoi4Delt60.1gi€here isasselrtelynerindtbaunn inthepslathatiaDOviiwelie npeeatingplactfeesimply a_higher 98% contml pereontager Tberenaverysmallauuuntafda1ab5 admit Ineatiatis:teileatabgthe puteibititythathighenthtarr2S%-,; antraFwpaesibia, andata4R of datathat can.guaraateaAlarmecaatratpeecentage on thsiasiso€foNwringthoopaiatingraquiremeotuof4Uafrto,19¢ r discussion The dluislotaie00onaleOdra➢owingthe Sa%.canffal.has been based atleast .partly. netgz?fatb hgdecument: fimWanywe3 B .gnv/rto/aiwlftamlyd32f retechrepoxtpdP. 7biastudy .of to parRu'rnfancefar span.. loraninoldinpalt-assiated, bee' t azwauldlaffectflarepnrfarmance. .. Istad. The Aareshallbetaatac eat aeon Thin meanothetthaortiss-settI OR hoLtngthe apilnn fnntatea nr nl"mamflne eestated in the permit(mare caneervafitrej. The apes cal tleie3'ipvelndYy_Additionally, i am cegdhing thatihe 00 days n€sonstrvatlon o€tireftaee. lathe mead€sore, fire aperatorwdi be allowed tonelnvf crony rnbhi€inatian, thisalluovance mill east; sad nnlcula#tauserili enlp relied ₹ittmiormirrn I f yethoowingthe akactftera'3p size. nd be able: Em rmocldth sncati the pi t odificati efl3re-bevel dorsteut'is:aubiavabre;_. rod di lytun 00thafI r iboongiyen thedpeeafarthe apt 00nnlfher spedfylugo r flp;with atarget one butstlil'ealculate thoHare-bp velae≥t+ rsit'ifthey wishedtn r€wngethespecfid iie,tll is bon_g rfn RIOwSpeciiiirteexacl Roue-€ip areawithl i ;ityosingtheacnfel5bra natsta€ed'tuthe permit, butth dpsixa>Thrs iu fu nllowlheaparetarsomeflasfhil fa Tfiecamhinadgasstraa . 4lWfhetested noaeter!$ o aebro ate prknary VOfis aondary.NIDl€and'caem6seWns,and:thegarbeatingvalue £or.pnepascu... 14001 m tn:a 6'l,l&t The rtSi rnunxbta/cfi 5Di18:i 01. Em foennmd'fla vp efdeity almsto#0aboeterad.mdmhfyhased'oeethe eoaufts.afthameut.reeenegp eempfa;..Porapyr,; manth-wheere fit €t re np"aeloaiiy+Feass tmoedta exteedthsm f m, tfieffare shall ontyee-gfanted,9 %uonttat F6n'enygnant where the'he taunt nt a64he pe ntu "sam 1 8 gas #rel w3Di#EaN_tjsc€,ihefla€e�ait6egstrt€ud:45%canfroL =. =' � Because aart of #t ta Bas tatiia flare s pateatishy from dawntiimaoftna vyli td the rush -gas streamnl ale nnebon unitlPnint Do4b.• Fae opora₹orun7l erapkdawntimeof he VRU ars{i usjngthe rpemred₹[ash gcremimiaris, tkeexpacfa# VOf conbeibs,ted from the ammeuntt ag[dgab stroam fn Eficntafaredgas botheylaremayna dedutbed }S�Grrr thuhOC Brglttuth flefe, asa2mustbe eduxrtedtoward. theltC emletrno limoituftlno 2mfaf'Ual oad.sheuldnuf be nount4xice•. ` Sauce eshsf awmh nedffmitaf pnrgegas dprpceitgasaf 5mmscl/yr: thane added tttie ptlotifghtfa eluseas perebo pilot light rernngth.this Ga reads thnl cell reyuestdfuefuse. Yrarat ?With this, astHe,rnat 'captuPe&thecomiltnetl'si4eams AddiztglYaCtyrthc pilvEligtitgas;is zddHt�ta #Ne:prdcess limiY,.and wiil'mot be metared:,tiuE'wib ba. aaicniated inadditbtt ushtgthe pilutlighfdesign rata){srve•. CFiap€erl,efnusianfactarsf'001hntiara plTo€ Ilgh₹era vucd Pant „e b oosumed to he000 bleating value of 900 bIn/scfl - - Section 09- Invensory SCC Coding and Emissions Factors AIRS Point 005 Process p SCC Code 01-;A[C#3�I7,SiS Pollutant PM10 PM2.5 NOx VOC CO Benzene Toluene Ethylbenzen Xylene n -Hexane 224TMP Uncontrolled Emissions Factor 7.600 7.600 87.398 17832.1 391219 84.8517 667.271 192.198 730.352 218.414 0.000 Control % 1.0% 0.0% 0.0% 98.0% 0.0% 98.0% 980% 98.0% 98.0% 98.0% 0110/01 906 Regulation 7 Information Operating Hours:. Fugitive equipment. leaks 8760 hours/year Emission Factor Source Standard EFs -EPA-453/R-95-017 Table 24 Control Efficiency Source:. Calculations Service Component Type Count Emission Factor (kg/hr- source) Table 24 (in lb/hr) Control (%) Pollutant Mass Fraction Emissions (tpy) , Reg. 3. Emissions (tpy) Reg. 3 Connectors 1202 2.00E-04 4.41E-04 81.0 % VOC 022 7.876334526 1.09012554 Flanges 566 3.90E-04 8.60E-04 81.0% ; Benzene 0.0400 1.432060823. 0.19820464 Open -Ended Lines 0 2,00E-03 4.41E-03 0.0% Toluene. - 9.0400 1.432060823 0.19820464 Inlet Gas Pump Seals 0 2.40E-03 5.29E-03 0.0% Ethylbenzene 0.0400 1.432060823 0.19820464 Valves 653 4.50E-03- 9.92E-03 - 96.0% Xylenes 0.0400 1.432060823 0.19820464 Other 35 8.80E-03 1.94E-02 0.0% n -Hexane 0.0800 2.864121646 0.39640929 224 TMP 0,0400 .1.432060823 0.19820464 Connectors 3953 7,50E-06 1.65E-05 81.0% VOC 1 0.411160906 0.17927358 Flanges 0 3.90E-07 8.60E-07 81.0% Benzene 0.0400 0.016446436 0.00717994 Open -Ended Lines- 0 0.00E+00 0.00E+00 0.0% Toluene 0.0400. 0.016446436 0.00717094 Heavy Oil Pump Seals 17 - 5.13E-04 1.13E-03 0.0% Ethylbenzene 0.0400 0.016446436 0.00717994 Valves 468 8,40E-06 1.85E-05 0.0% Xylenes 0.0400 - 0.016446436 0.00717094 Other 9 3.20E-05 7.05E-05 0.0% n -Hexane. 0.0800 0.032892872 0.01434189 - - 224 TMP 0.0400 0.016446436 0.00717094 Connectors 389 2.10E-04. 4,63E-04 81.0% _ VOC 1 6.3652362 0.42869531 Flanges 0 1.10E-04 " 2.43E-04 81.0% Benzene 0.0400 0.254609448 0.01714781 Open -Ended Lines. 0 1.40E-03 3,09E-03 0.0% Toluene 0.0400. 0.254609448 0.01714781 Condensate (Light Oil) Pump Seals 0 1.30E-02 287E-02 88.0%- Ethylbenzene 0.0400 0.254609448 0.01714781 Valves 231 250E-03 5.51E-03 95.0% Xylenes 00400 0.254609448 0.01714781 Other 0 7.50E-03 1.65E-02 ' 0.0% n -Hexane 0.0800 0.509218896 0.03429562 224 TMP 0.0400. 0.254609448 0.01714781 Connectors 1458- 2.10E-04 4.63E-04 81.0% VOC 1 30.5863316 3.23026636 Flanges 317 1.10E-04 2.43E-04 81.0% Benzene 0.0400 1.223453264 0.12921065 Open-Endedlines 0 1.40E-03 3.09E-03 0.0% - Toluene 0.0400 1.223453264 0.12921065 C3+ liquid (light oil) Pump Seals 8 1.30E-02 2.87E-02 .88.0% Ethylbenzene 0.9400 1.223453264 0.12921065 Valves 1038 2.50E-03 5.51E-03 95.0% Xylenes 0.0400 - - 1,223453264 0.12921065 Other 17 7.50E-03 1.65E-02. 0.0% n -Hexane 0.0800 2.446906528 0.25842131 224 TMP 0.0400 1.223453264 0.12921065 Connectors 321 2.10E-04 4.63E-04 81.0% VOC 1 5.218085818 0.80280345 Flanges 68 1.10E-04 2.43E-04 81.0%. Benzene 0.0400 0208723433 0.03211214 Open -Ended Lines 0 1.40E-03 3.09E-03. 0.0% Toluene 0.0400` 0.208723433 0.03211214 NGL (Light Oil) - Pump Seals" 11 1.30E-02 2.87E-02 88.0% Ethylbenzene 0.0400 0.208723433 0.03211214 Valves 114 2.50E-03 5.51E-03 95.0% Xylenes 0.0400 0.208723433 0.03211214 Other 5 7.50E-03 1.65E-02 0.0% n -Hexane 0.0800 0.417446865 0.06422428 ' - - 224 TMP 0.0400 0208723433 0.03211214 Connectors 92 2.10E-04 4.63E-04 81.0% i VOC - 1 1.408059501 0.26048232 Flanges 0 1.10E-04 243E-04 81.0% Benzene 0 0 0 Methanol (Light Oil) Open -Ended Lines 0 1:400-03 3.09E-03 0;0°/ Toluene 0 0 5 Pump Seals. 3 '1:30E-02 2.87E-02 88.0% Ethylbenzene 0 0 ' 0 Valves 29 2.50E-03 5.51E-03 95.0% Xylenes 0 .0 0 Other 2 7.50E-03 1.65E-02 0.0% n -Hexane O 0 0 Connectors 10604 2.00E-04 4.41E-04-. 81.0% VOC 1 77.1070455 8-9596906 Flanges 342 3.90E-04 8.60E-04 El 0% Benzene 0.0400 3.08428182 0.35838762 Open Ended Lines 0 200E-03 4.41E-03` 0.0% Toluene 0.0400 3.08428182 0.30838762 C3+ Gas Pump Seals 0 - 240E-03 5.29E-03 00% Ethylbenzene 00400 3.08428182 0.35838762 Valves 1211 4.50E-03 9.92E-03 "96.0% Xylenes. - 0.0400' 3.08428182. 0.35838762 - - Other 32 '8.80E-03 1.94E-02 0.0% n -Hexane 0.0800 6.16856364 0.71677525 .. - 224 TMP . 0.0400 3.08428182 0.35838762 Table 5.3 Quarterly Monitoring (NSPS 0000a: equivalent( Uncontrolled. Controlled Emissions Summary Table Pollutant - Uncontrolled Emissions Controlled Emissions Source j VOC 128.97 tpy - 15.0 tpy Standard OF: Benzene ' - - 12439 Ib/yr 1484 lb/yr Standard ER Toluene 12439 lb/yr 1484 lb/yr Standard EF: Ethylbenzene 12439 lb/yr 1484 lb/yr Standard ER Xylenes 12439 Ibh/r 1484 Ibtyr Standard EF' n -Hexane 24878 lb/yr 2969 lb/yr Standard ER 224 TMP 12439 - 1484 ethanol Regulatory Applicability 2816 521 Monthly VOC 2540 Based on a 31 day month Review Regulation 3, Part B, Section IILD:2to determine is RACT is. required? Yes Review 40 CFR, Part 60, Subpart KKK and 0000 to determine if applicable to this source? No Review 40 CFR, Part 60, Subpart 0000a to determine if 60.5380 and/or 605385 is applicable? Review Section XVII.F to determine is LDAR is applicable? No Reg. 3 Reg. 6 Reg. 7 Reg. 8 Notes - - EPA -453/R-95-017 Table 2-4 -, EPA-d53/R-95-017 Table 2-4 - 6.219575224 0.74223382 EPA -4531R-95-017 Table 2-4 6.219575224 0.74223382 - EPA -453/R-95-017 Table 24 6.219575224 0.74223382 - EPA -453/R-95-017 Table 2-4 6.219575224 0.74223382 EPA -453/R-95-017 Table 2-4 12.43915045 1.48446763 6.219575224 0.74223382 - 1.408059501 0.26048232 MACT HH is NOT applicable. Source is area source. for MACT NH, but in the event that this source becomes major for HAPs, it will be subject to MACT HH requirements for fugitives,.because NSPS 0000 does not apply. Even though NSPS 0000a applies, that does not currently exempt sources from MACT. NN requirements. - NSPS 0000e has not been adopted by Colorado, so it is federally applicable. Source is.subject to Regulation 7, Section XII.G1 for being a gas plant, which specifies following NSPS KKK. unless subject to 0000 or 0000a. Following this will also satisfy RACT and the requestedcontrol percentages. Since source is federally subject to 0000a, I have indicated that following 0000a..vrill meet the requirementAdditionally, I have indicated in the notes to permit holder that the granted control percentages that are equivalent to NSPS 0000a. Source also -used an emission factor for pumps in heavyoil service.- AP42 doesn't givean emission factor, so I have used 0 as the emission factor. 'Air; Boiler APEN - Form APCD-220 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for boilers, hot oil heaters, process heaters, and similar equipment. If your emission unit does not fall into one of these categories, there may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. Do not complete this form for the following source categories: - Heaters or boilers with a design capacity less than or equal to 5 MMBtu/hour that are fueled solely by natural gas or liquid petroleum gas (LPG). Heaters or boilers with a design capacity less than or equal to 10 MMBtu/hour used solely for heating buildings for personal comfort that is fueled solely by natural gas or liquid petroleum gas (LPG). More information can be found in the APEN exempt/permit exempt checklist: https: / /www.colorado. gov/pacific/cdphe/apen-or-air-permit-exemptions. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 /001 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Kerr McGee Gathering LLC Site Name: Latham Gas Plant Site Location: Section 2, T3N, R66W, Weld County Mailing Address: PO Box 173779 (Include Zip Code) Denver, CO 80217 E -Mail Address2: joel.kenyon@anadarko.com Site Location County: Weld NAICS or SIC Code: 1321 Permit Contact: Joel Kenyon Phone Number: 720-929-6135 'Please use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided. Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 /001 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2- Requested Action ✓❑ NEW permit OR newly -reported emission source -OR - ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment ❑ Change company name ❑ Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership' ❑ Other (describe below) OR- ❑ APEN submittal for update only (Please note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) ❑ APEN submittal for permit exempt/grandfathered source Additional Info & Notes: amine regeneration heater For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Boiler Information General description of equipment and purpose: amine regeneration Manufacturer: TBD Model No.: TBD Company equipment Identification No. (optional): H-80100 For existing sources, operation began on: Serial No.: For new, modified, or reconstructed sources, the projected start-up date is: 10/1/2018 0 Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day days/week Seasonal use percentage: Dec -Feb: Mar -May: June -Aug: Sept -Nov: weeks/year Are you reporting multiple identical boilers on this APEN? ❑Yes Q No If yes, please describe how the fuel usage will be measured for each boiler (i.e., one meter for all boilers or separate meters for each unit): Form APCD-22O - Boiler APEN - Revision 7/2016 A.VelViCOLORADO 2 I Y 1112 mmweu. ey��b,r.�vam.�. Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 /001 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Stack Information WGS84 (-10414, 40.26) 4r r - r "CTI'-: L � Opei-�tors ^S 5 StacklDN® i37,urOt ,' � S' 2 ,r 1i {� ''j'. � -..:^• ,� ,� € ... *.Y.' �. Discharge Peight y � � � �� '�,� � y o�.e Ground�L�evelE d A �r � ( eetj R N .k ( ;Ax: : ... ..r •h �.+� s a�,s r r x�`2rks rG N-i .T , �. k k �Tem�s�< � Y d' Z T < b ,�%'' v'l (�) t�"•.L �.,. .� l ... t 3"'_ ,-, .�. a. � yx�{r � h ..r.ZLM ,,a �'e�`-kr". '7' 7�, , 4 "i fin 3` cf`'�Y'-^ � l°lo� (�at��r q 4,i lZ {Ac 1) A�s� ?..�,yf&. � ,, in.. .t'S�nv. ,S,.��._-a-ASipvh��'�'n._^.Du ma V,` .h�.i�-'�' ' ,.,.' k A _}i`^TYL42y �} fo `�`�� `Y� tlse (� ,� "52 x' ≥`. . amine regen 1 4870 Indicate the direction of the stack outlet: (check one) Li Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑✓ Circular Interior stack diameter (inches): ❑ Square/rectangle Interior stack width (inches): ❑ Other (describe): ❑ Upward with obstructing raincap Interior stack depth (inches): Section 5 - Fuel Consumption Information Design trput Rate (MMBTUIhr)..... Actual'Ahnual Fuel Use4 (SpecifyUni(s) Requested Annual Permit Limify (Specify. Units) ,'.__._ 55 535.3 MMscf/year From what year is the actual annua fuel use data? Fuel consumption values entered above are for: Each Boiler ❑ All Boilers ❑ N/A Indicate the type(s) of fuel used6: ❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑ Field Natural Gas Heating value: BTU/SCF ❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) ❑ Propane (assumed fuel heating value of 2,300 BTU/SCF) ❑ Coal. Heating value: BTU/lb Ash Content: Sulfur Content: ▪ Other (describe): pipeline gas Heating value (give units): 900 BTU/scf 41f you are reporting multiple identical boilers on one APEN, be sure to clarify if the values in this section are on an individual boiler basis, or if the values represent total fuel usage for multiple boilers. sRequested values will become -permit limitations. Requested limit(s) should consider future process growth. Elf fuel heating value is different than the listed assumed value, please provide this information in the "Other" field. Form APCD-22O - Boiler APEN - Revision 7/2016 3oiek.Ny xoimen�no;wmuui TSP (PM) Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 /001 [Leave blank unless APCD has already assigned a permit It and AIRS ID] Section 6- Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? EYes 0 No yes, please equipment If describe the control e ui merit AND state the overall control efficiency (% reduction): ontrol Efficiency eduction in emissions) PM10 PM2,5 Sox NOx CO VOC Other: From what year is the following reported actual annual emissions data? Use -the following tables to report the criteria pollutant emissions from source: the data reported in Section 5 to calculate these emissions. Primary Fuel Type (naturai gas, diesel, '16':'')'''::: PolluEant Uncontrolled Emission (Specify_Units) Errlrss�onca�r Factor ,. Source:•Fedor (AP 42, Mfg etc) :° s ,:, ctualAri 4-4 Emiss►ons 5 ' -t at. �rdA� v�Prta GaE ss o AJI nz Uncontrolled (Tons/year){ Controlled7r (Tons/yegrJ Uncontrolled (Tonslyear� ', 0 Controlled {Tonslyear), natural gas TSP (PM) PMio 0.0075 Ib/MMbtu AP 42 1.79 1.79 PM2,5, 0.0075Ib/M1Mbtu AP -42 1.79 1.79 SOX 0.0006 lb/MMbtu AP 42 de min de min NOx 0.04o(VII u ItO\,n\- 9.64 9.64 CO 0.04 Ib/MMbtu manuf. 9.64 9,64 VOC 0.019 Ib/MMbtu manuf. 4.58 4.58 Other: V 'Requested values will become permit limitations, Requested limit(s) should consider future process growth. 'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Farm APCD-220 - Boiler APEN - Revision 7/2016 4 COLORADO 42,7e tit Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 / 001 [Leave blank unless APCD has already assigned a permit # and AIRS ID] ✓� Check this box if the boiler did not combust a secondary fuel during this reporting period and skip to Section 7. If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total criteria emissions table below: Secondary Fuel Type (#2 diesel, waste Ws oil, .etc) Pollutant J Uncontrolled Emission, Faclol S ecr G!niGs ) f'=+ Emission Factor. Source , (AP 42, Mfg • etc) j } ;r gctrual Annual Emi, slo`ns nsEissiofi a Requeste n�a Permit l7mits), w ,'. ti , Uncontrolled (Tons/year) Controlled'` (T.,ons/year)..: Uncontrolled; (Ts/y onear) Controlled `, (Tons/year) ,,, TSP (PM) PMio PM2,5 SOX NOX CO VOC Other: If multiple fuels were fired during this reporting period, use the following table to report the TOTAL criteria pollutant emissions from the source. Values listed below should be the sum of the reported emissions from the primary and secondary fuels' emissions tables in this Section 6: pollutant��u�� ms's 'k ' }i. 4 -4, , AtYu Atnmial .' p ,, z.Yn \ rt #�K ed nua 'e t „ 8�s� Uncontrolled „ (Tons/year) Controlled/ (Tonsly'ear`) ,, Uncori rolled r . :f(Tons/yedr)a . Controlled , , T (Tans/yeprf), TSP (PM) PM10 PM2.5 SOX NOX CO VOC Other: 5 Requested values will become permit limitations, Requested limit(s) should consider future process growth. Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 7/2016 COLORADO 5 I M� °,2i'mv:mdweu„ Xfi�ih 6 EmM1�onm.tll Permit Number: 17WE0398 MRS ID Number: 123 /9F22 / 001 [Leave blank unless APCD has already assigned a permit tY and AIRS ID] Section 7 - Non -Criteria Pollutant Emissions Information Does the emissions source have any uncontrolled actual emissions of non -criteria pollutants (e.g. HAP- hazardous air pollutant) equal to or greater than 250 lbs/year? 0 Yes ❑ No If yes, use the following table to report the non criteria pollutant (HAP) emissions from source: ncdritrolled dual Emissions CAS Number Chemical Name n-hexane Overall Control Efficiency Uncontro-1 led Emission` Factor (specify"uni s), r, 0.0018 Ib/MMbtu AP -42 controlled actual ' fissions ''(lb 'Annual emission fees will be based on actual control ed emissions reported. If source has not yet started operating, eave blank. Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct, /I - /0 /Signature of Legally Authorized Person (not a vendor or consultant) Date Joel Kenyon HSE Representative Name (please print) Title Check the appropriate box if you want: ❑ Copy of the Preliminary Analysis conducted by the Division 0 Draft permit prior to public notice 0 Draft of the permit prior to issuance (Checking any of these boxes may result in an increased fee and/or processing time) This notice is valid for five (5) years unless a significant change is made, such as an increased production, new equipment, change in fuel type, etc. A revised APEN shall be filed no less than 30 days prior to the expiration date of this APEN form. Send this form along with $152.90 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Telephone: (303) 692-3150 Form APCD-220 - Boiler APEN - Revision 7/2016 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd vCOLORA90 AlaHeim n £4..onm.ni (Zec- Boiler APEN - Form APCD-220 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for boilers, hot oil heaters, process heaters, and similar equipment. If your emission unit does not fall into one of these categories, there may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. Do not complete this form for the following source categories: - Heaters or boilers with a design capacity less than or equal to 5 MMBtu/hour that are fueled solely by natural gas or liquid petroleum gas (LPG). Heaters or boilers with a design capacity less than or equal to 10 MMBtu/hour used solely for heating buildings for personal comfort that is fueled solely by natural gas or liquid petroleum gas (LPG). More information can be found in the APEN exempt/permit exempt checklist: https: / /www.colorado. gov/pacific /cdphe/apen-or-air-permit-exemptions. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 /002_ [Leave blank unless APCD has already assigned a permit N and AIRS ID] Section 1 - Administrative Information Company Name': Kerr McGee Gathering LLC Site Name: Latham Gas Plant Site Location: Section 2, T3N, R67W, Weld County Mailing Address: PO Box 173779 (include Zip Code) Denver, CO 80217 E -Mail Address2: joel.kenyon@anadarko.com Site Location County: Weld NAICS or SIC Code: 1321 Permit Contact: Joel Kenyon Phone Number: 720-929-6135 'Please use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD, Any changes will require additional paperwork. 2Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided, Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 /002 [Leave blank unless APCD has already assigned a permit 1 and AIRS ID] Section 2- Requested Action p NEW permit OR newly -reported emission source -OR - ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment ❑ Change company name ❑ Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership' ❑ Other (describe below) OR- ❑ APEN submittal for update only (Please note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) ❑ APEN submittal for permit exempt/grandfathered source Additional Info a Notes: train 1 molecular sieve regeneration heater 3 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Boiler Information General description of equipment and purpose: molecular sieve regeneration Manufacturer: TBD Model No.: TBD Serial No.: Company equipment Identification No. (optional): T1 mole sieve heater (H-31711) For existing sources, operation began on: For new, modified, or reconstructed sources, the projected start-up date is: El Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day Seasonal use percentage: Dec -Feb: Mar -May: days/week weeks/year June -Aug: Sept -Nov: Are you reporting multiple identical boilers on this APEN? ❑Yes No If yes, please describe how the fuel usage will be measured for each boiler (i.e., one meter for all boilers or separate meters for each unit): Form APCD-22O - Boiler APEN - Revision 7/2016 COLORADO 2 I Mi Depurn mtr,r„t H�]IN 6 LMlenm.l.l Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 /002 [Leave blank unless APCD has already assigned a permit #I and AIRS ID] Section 4 - Stack Information Geographical'Coordinates Lotitade/Longitude or UTM) WGS84 (-104.74, 40.26) ,4'Sh Opergto irk 0. Sta l� )D No "� t;.N.n yrC₹'`�. - ._-.,s., a T§ l"q'xaa X1 Dy har, e }iel ht . x�" ,/q� /above Ground Levu f � r C' 3 Feet xz ' w3 x«K .. a. ' Te . ( ) sM� nt, r�F'� ,. s " a��w�. 1 �Eri y6•"�`�h,`xFix.3 k `r � p ' �� , ��a ateWtieloclt; , AO+� 3� y . s�: "� ,yc ' r . :..,S.:eSr s,:,.>ii5=. .� '� ,sa�F� }°��tv*3'✓'}*e Se Ye roe) ( rto �._%, `s.au"'.$.; T1 mole sieve heater 4870 Indicate the direction of the stack outlet: (check one) ✓❑ Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑✓ Circular Interior stack diameter (inches): ❑ Square/rectangle Interior stack width (inches): ❑ Other (describe): ❑ Upward with obstructing raincap Interior stack depth (inches): Section 5 - Fuel Consumption Information _Design Input Rate (MMBTUhr/).� Actual Annual Fuel Use4 : (Specify Units) 5= tRequested Annual Pet; 'hnits> 2 (Specfy Un ts) 18.36 178.7 MMscf/year From what year is the actual annual fuel use data? Fuel consumption values entered above are for: ❑✓ Each Boiler ❑ All Boilers ❑ N/A Indicate the type(s) of fuel used: LI Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑ Field Natural Gas Heating value: BTU/SCF ❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) ❑ Propane ❑ Coal l J Other (describe): (assumed fuel heating value of 2,300 BTU/SCF) Heating value: pipeline gas BTU/lb Ash Content: Sulfur Content: Heating value (give units): 900 'If you are reporting multiple identical boilers on one APEN, be sure to clarify if the values in this section are on an individual boiler basis, or if the values represent total fuel usage for multiple boilers, • 'Requested values will become permit limitations. Requested limit(s) should consider future process growth, 6if fuel heating value is different than the listed assumed value, please provide this information in the "Other" field, Form APCD-220 - Boiler APEN - Revision 7/2016 3 I .COLORADO Geparmmnla Puhllc Heal.Envilonm.nl TSP (PM) Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 /002 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6- Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? ElYes El No If yes, please describe the control equipment AND state the overall control efficiency (% reduction): Overall Control Efficiency ;(% reduction m emisspns) PM10 PM2,5 SO„ NO, CO VOC Other: From what year is the following reported actual annual emissions data? Use the following tables to report the criteria pollutant emissions from source: culate these emissions. v V Primary Fuel Type (naturalgas'i 2 diesel, ''''''..1',":';'.8.)..':'''.:,:.,S _ Pollutant lJncontrolled Emission Factor ecr Units ( P fy ., ) -Emission Facor', Source'. AP 42, M ( f8• '� ',yv �r% ' Actual Annual Erns s.,i,o ` � '� r• f n { �Req QsOa��PeTmrt ° ' , * to ° ;L� .,." �t t ' Uncontrolled Tonsl edr . (,. Y ) Controlled7r (ons/year) .. T,, Uncontrolled, (Tons/year) . ; Controlled (Tonslyear) natural gas TSP (PM) PM10 0.0075 lb/MMbtu AP -42 de min de min PM2,5 0.0075 lb/MMbtu AP -42 de min de min SO„ 0.0006 lb/MMbtu AP -42 de min de min NO„ t ,011 lb/MMbtu avoglukk - 3.22 ' 3.22 .: CO 0.04 lb/MMbtu manuf. 3,22 3.22 VOC 0.019 lb/MMbtu manuf. 1.53 1.53 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth, 'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-22O - Boiler APEN - Revision 7/2016 4 I c oI OR ADO wcue nmm n ssmtnnm.ni Permit Number: 17WE0398 [Leave blank unless APCD has already assigned a permit I/ and AIRS ID] 0✓ Check this box if the boiler did not combust a secondary fuel during this reporting period and skip to Section 7. If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total criteria emissions table below: Secondary Tue( Type (#2 diesel waste`O1, .. etc•.) Pollutant Uncontrolled Emts.on Factor (Specify l/�i�ts) { mtssron Factor Source.: qp 4z M ( fs etc) .... 1P T•tygat. ri" R4 ffS�r, F tiydr '5 tx p .y cE�al A nual miss' ns ' yr° K� �N4e t'f "F *` ; a i mt �' rm Obi � �s Etaaisa°1 �+tZ�$1 Uncontrolled (Tonslyear):: Controlled ' (Tons year) Uncontrolled ' (Tons/year) Controlled (Tanslyear) TSP (PM) PM, o PM2.5 SOC NO, CO VOC Other: AIRS ID Number: 123 /9F22 / 002 If multiple fuels were fired during this reporting period, use the following table to report the TOTAL criteria pollutant emissions from the source. Values listed below should be the sum of the reported emissions from the primary and secondary fuels' emissions tables in this Section 6: - Pollutant:: ✓i -.' i 4, C Yf Y --Y � , s f 6 , :c .gal�Annl ,l rn�s5) Ps K v w t -sY 3vrgy^t u �.'` '' L4 1...'r d-t�' - iested At ia�a Pgr ' a z m� ion LirYi i{ } c *w� � ton' 4 i � � Uncontrolled (Tons/year) . Controlled : ((Tonslyear) Uncontrolled (Tons.. Ye ) . , Controlled ;:,'(Tops /year) TSP (PM) PM1a PM2.5 SOC NO, CO VOC Other: 5 Requested values will become permit limitations, Requested limit(s) should consider future process growth. 'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 7/2016 5 I g COLe.RADD `i �H�u faweuo IN 6 £nviionlnrnl Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 / 002 [Leave blank unless APCD has already assigned a permit if and AIRS ID] Section 7 - Non -Criteria Pollutant Emissions Information Does the emissions source have any uncontrolled actual emissions of non -criteria Yes No pollutants (e,g. HAP- hazardous air pollutant) equal to or greater than 250 lbs/year? If yes, use the following table to report the non criteria pollutant (HAP) emissions from source: Uncontrolled Uncontrolled_ EmissionFactor Actual Emission Source , Emissions' Factor (AP 4z, Mfg, e[c) (specr`fy units).. (lbs/year). CAS Number n -hexane verail Control Efficiency 0.0018 lb/MMbtu AP -42 Controlled Actual Emissions (IbsJyear).`' 'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. itu 7) e of Legally Authorized Person (not a vendor or consultant) Joel Kenyon Name (please print) 1- i ig Date HSE Representative Title Check the appropriate box if you want: ❑ Copy of the Preliminary Analysis conducted by the Division Draft permit prior to public notice ❑✓ Draft of the permit prior to issuance (Checking any of these boxes may result in an increased fee and/or processing time) This notice is valid for five (5) years unless a significant change is made, such as an increased production, new equipment, change in fuel type, etc. A revised APEN shall be filed no less than 30 days prior to the expiration date of this APEN form. Send this form along with $152.90 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Telephone: .(303) 692-3150 Form APCD-22O - Boiler APEN - Revision 7/2016 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: https: //www.colorado.gov/cdphe /apcd CDLOKADO 6 I 4101bentNwblle � H�IUibrnvnonmrnl (c)N-e_c_ 1(k`ilIc6 Boiler APEN - Form APCD-220 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for boilers, hot oil heaters, process heaters, and similar equipment. If your emission unit does not fall into one of these categories, there may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. Do not complete this form for the following source categories: - Heaters or boilers with a design capacity less than or equal to 5 MMBtu/hour that are fueled solely by natural gas or liquid petroleum gas (LPG). Heaters or boilers with a design capacity less than or equal to 10 MMBtu/hour used solely for heating buildings for personal comfort that is fueled solely by natural gas or liquid petroleum gas (LPG). More information can be found in the APEN exempt/permit exempt checklist: https: / /www.colorado. gov/pacific/cdphe/apen-or-air-permit-exemptions. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 /003 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name: Site Name: Site Location: Kerr McGee Gathering LLC Latham Gas Plant Site Location Section 2, T3N, R66W, Weld County County: Weld Mailing Address: PO Box 173779 (Include Zip Code) Denver, CO 80217 E -Mail Address2: joel.kenyon@anadarko.com NAICS or SIC Code: 1321 Permit Contact: Joel Kenyon Phone Number: 720-929-6135 'Please use the full, legal company name registered with the Colorado Secretary of State, This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided. Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 / 003 [Leave blank unless APCD has already assigned a permit ft and AIRS ID] Section 2- Requested Action NEW permit OR newly -reported emission source -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment O Change company name O Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership' ❑ Other (describe below) -OR- ❑ APEN submittal for update only (Please note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) APEN submittal for permit exempt/grandfathered source O Additional Info a Notes: train 2 molecular sieve regeneration heater 'For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Boiler Information General description of equipment and purpose: molecular sieve regeneration Manufacturer: TBD Model No.: TBD Serial No.: Company equipment Identification No. (optional): T2 mole sieve heater (H-32711) For existing sources, operation began on: For new, modified, or reconstructed sources, the projected start-up date is: ❑✓ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day Seasonal use percentage: Dec -Feb: Mar -May: days/week weeks/year June -Aug: Sept -Nov: Are you reporting multiple identical boilers on this APEN? ❑Yes E No If yes, please describe how the fuel usage will be measured for each boiler (i.e., one meter for all boilers or separate meters for each unit): Form APCD-220 - Boiler APEN - Revision 712016 2 I ��COLORD AO x.nN6£ .=. ❑✓ Upward ❑ Horizontal Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 / 003 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Stack Information eographical Coordinates Latrtu (e/LopgitWde or UTM) WGS84 (-104.74, 40.26) , ,. erator'tea $ Suck lDs to r�.., F y �'� zK' �t ^ � ,�R; - .� Dist 'a 7-lel�hb�r 'y{ f:-Above Ground Lekel> -' tp (1 eel}} t ..3r:.z�,..,.. u .A{� Tern P s`r � y z(s` F z ' ce i Ytr .. , ` 'e�' } �(hl'y'C�Klt-/+� .� -M s Flov Ra te k r c 3 �fiN) 4 H it "�n ' . Y'� r .,` cr tjh 3 eldc�t t , t/ b s ,::1 . ....-.. Indicate the direction of the stack outlet: (check one) ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) O Circular Interior stack diameter (inches): ❑ Square/rectangle Interior stack width (inches): ❑ Other (describe): ❑ Upward with obstructing raincap Interior stack depth (inches): Section 5 - Fuel Consumption Information Design input Ra te '"(MMPTU/hi- Actual Annual Fuel Use4 (Specify Units) Requested Annual Permit Limit ;(Specify i)riits) 18.36 - 178.7 MMscf/year From what year is the actual annua fuel use data? Fuel consumption values entered above are for: 0 Each Boiler 00 All Boilers ❑ N/A Indicate the type(s) of fuel used6: 0 Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑ Field Natural Gas Heating value: BTU/SCF ❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) ❑ Propane (assumed fuel heating value of 2,300 BTU/SCF) ❑ Coal Heating value: BTU/lb Ash Content: Sulfur Content: 0 Other (describe): pipeline gas Heating value (give units): 900 Alf you are reporting multiple identical boilers cal one APEN, be sure to clarify if the values in this section are on an individual boiler basis, or if the values represent total fuel usage for multiple boilers. 5Requested values will become permit limitations. Requested limit(s) should consider future process growth, 61f fuel heating value is different than the listed assumed value, please provide this information in the "Other" field. Form APCD-220 - Boiler APEN - Revision 7/2016 3 I �COLOkAbo ;„.ewe `MZ TSP (PM) Permit Number: 17WE0 39$ AIRS ID Number: 123 19F22 /003 [Leave blank unless APCD has already assigned a permit p and AIRS ID) Section 6- Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form, Is any emission control equipment or practice used to reduce emissions? [Yes 0✓ No If yes, please describe the control equipment AND state the overall control efficiency (% reduction): verall Control Efficiency (o'reauctron m emissions) PM10 PM2,5 SO, NO, CO VOC Other: From what year is the following reported actual annual emissions data? Use the following tables to report the criteria pollutant emissions from source: ssions, i Vic ulc uu Y Pnma Fuel ` �' Type ( natural as #2 diesel, 'etc:) pollutant l)ncontrailed� Emtsi0 Factor (Specrfy,llorts) :_ Emission Factor ` - =.Source'; Ap 42,:M t fs - etc r;. '� '� AciyaalkAnnual ErpasS)on; a,=kcx x�', ,�`i ��s' h ri fie se %4,'''' ,hit f53 �,missaon�l_�Xm(s��y,6�: a 1O, mss.•: Uncontrolled Tons/ ear, Controlled' .; (Top,ilyear) .: Uncontrolled : (Tonslye4r) Controlled ,' (Tons/''''' :. natural gas TSP (PM) PM10 0.0075 Ib/MMbtu AP -42 de min de min PM2,5 0.0075 Ib/MMbtu AP -42 de min de min SO,, 0.0006 lb/MMbtu AP -42 de min de min NO,, o ° it hb/MMbtu NlG+\l,(f\. 3.22 3.22 CO 0.04 lb/MMbtu manuf. 322 3.22 VOC 0.019 Ib/MMbtu manuf, 1.53 1.53 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth, 'Annual emission fees will be based on actual controlled emissions reported, If source has not yet started operating, leave blank. Form APCD-220 • Boiler APEN - Revision 7/2016 COLORADO 4 I �� oepemnemd wEue VV HwIN hT.vlm�,mrl�l Permit Number: 17WE0398 [Leave blank unless APCD has already assigned a permit # and AIRS ID] ❑✓ Check this box if the boiler did not combust a secondary fuel during this reporting period and skip to Section 7. If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total criteria AIRS ID Number: 123 /9F22 / 003 sions table below: Secondary EueI:T,.ype ". (#2 diesel, waste.oil, efic.) Pollutant Uncontolled ,•••,_,,,:•;.7.•-••'1,•-„.:-:•:',...:-...'-:.f4017...,,,•::'�x Facto( (specrfy Uin s) Emission. , Source,, AP 4Z �' Mfg '..etc)._ ..... Aat al Annual E Zssions �� x, 4y ----- Pe's" rl al �,l� t1 A It,S ,��;� t-�,.��'��, �. Uncontrolled Tonsl ear ( y.):.; Controlled? Tans/ ear (.,n .y .).. Uncontrolled'. (Tonslyear). .:. Controlled ,,, (Tonslyear): TSP (PM) PM10 PM2.5 SOX NO„ CO VOC Other; If multiple fuels were fired during this reporting period, use the following table to report the TOTAL criteria pollutant emissions from the source. Values listed below should be the sum of the reported emissions from the primary and secondary fuels' emissions tables in this Section 6: utant Poll• -:,h.r 2nn. x 2 4 b r IR i3 �sa°``s� ,� -4.--i � cE t ue to n> d e lEw Uncontrolled .Tons/y"ea`r) Controlle(4f w•(Tons year) ;Unconttifitied = (TonsGyea), Controlled (Tans/year), TSP (PM) PMio PM2.5 SOX NO, CO VOC Other: 5 Requested values will become permit limitations, Requested limit(s) should consider future process growth, Annual emission fees will be based on actual controlled emissions reported, If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 7/2016 //y�{ COLORADO 5 I a y xw�m a rnr.,n��ni n -hexane Permit Number: 17WE0398 AIRS ID Number: 123 /9F22 / 003 [Leave blank unless APCD has already assigned a permit ft and AIRS ID] Section 7 - Non -Criteria Pollutant Emissions Information Does the emissions source have any uncontrolled actual emissions of non -criteria pollutants (e.g. HAP- hazardous air pollutant) equal to or greater than 250 lbs/year? ['Yes ® No If yes, use the following table to report the non -criteria pollutant (HAP) emissions from source: Uncontrolled Emission Factor (specify units Overall control Efficiency 0.0018 Ib/MMbtu AP -42 ontrohed; Actual missions? (ibs/year) Annual emission fees will be based on actual controlled emissions reported, If source has not yet started operating, eave blank. Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. ignature of Legally Authorized Person (not a vendor or consultant) Joel Kenyon Date HSE Representative Name (please print) Title Check the appropriate box if you want: ❑ Copy of the Preliminary Analysis conducted by the Division Draft permit prior to public notice 0 Draft of the permit prior to issuance (Checking any of these boxes may result in an increased fee and/or processing time) This notice is valid for five (5) years unless a significant change is made, such as an increased production, new equipment, change in fuel type, etc. A revised APEN shall be filed no less than 30 days prior to the expiration date of this APEN form. Send this form along with $152.90 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Telephone: (303) 692-3150 Form APCD-220 - Boiler APEN - Revision 7/2016 . For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 6921-3148 Or visit the APCD website at: https://www.colorado.Rov/cdphe/apcd 6 I AVCOLORADO '=uvalimni AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — Amine Sweetening Unit' - Permit Number: 111k1 E Q 3618' Facility Equipment ID: [Leave blank unless APCD has already assigned a pennit # & AIRS ID] Emission Source AIRS ID: 12 3 / F22. / 0 G4 - [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] Section 01— Administrative Information Company Name: Kerr McGee Gathering Source Name: DJ Gas Plant ' LG'f�Gwt �jc5 Source Location: Section 2, T3N, R67W, Weld County Piste Mailing Address: PO Box 173779t Denver Person To Contact: Joel Kenyon E-mail Address: NAICS, or SIC Code: 1321 County: Weld Elevation: 4870 Feet ZIP Code: 80217 Phone Number: 720-929-6135 joel.kenyon@anadarko.com Fax Number: Section 03 — General Information For existing sources, operation began on: Normal Hours of Source Operation: / / Section 02 — Requested Action (Check applicable request boxes) IZI Request for NEW permit or newly reported emission source ❑ Request MODIFICATION to existing permit (check each box below that applies) O Change process or equipment ❑ Change company name ❑ Change permit limit ❑ Transfer of ownership ❑ Other Request to limit HAPs with a Federally enforceable limit on PTE O Request APEN update only (check the box below that applies) O Revision to actual calendar year emissions for emission inventory Update 5 -Year APEN term without change to permit limits or previously reported emissions Addl. Info. & Notes: For new or reconstructed sources, the projected startup date is: 10 / 01 / 2018 24 hours/day 7 days/week 52 weeks/year General description of equipment and purpose: amine unit with 2 contactors, one reboiler, and one reboiler heater (reported on a separate APEN) ► Will this equipment be operated in any NAAQS nonattainment area? (www.colorado.gov/cdphe/attainment) ► Does this facility have a design capacity less than 2 long tons/day of H2S in the acid gas? Provide documentation. Section 04 — Amine Sweetening Unit Equipment Information Manufacturer: N/A Model: N/A Reboiler Rating: 44.8 MMBtu/hr Amine Type: O MEA Amine Pump Make & Model: Sweet Gas Throughput: Design Capacity: [ 53 MMSCF/day Serial No.: TBD Absorber Column Stages: 20 DEA O TEA stages ® MDEA ❑ DGA # of Pumps: 3 Inlet Gas: Pressure: 1003 Rich Amine Feed: Pressure: 1000 Lean Amine Stream: Pressure: 1150 wt. % amine: 45 Sour Gas Input: Pressure: 1000 Requested2: Calendar year actual: psig Temperature: --100- °F psia Temperature: 151 psia Temperature: 123 Mole loading H2S: neg. psia Temperature: 99.8 153 °F Flowrate: °F Flowrate: Mole loading CO2: °F Flowrate: NGL Input: Pressure: psia Temperature: °F Flowrate: Flash Tank: Pressure: 60 psia Temperature: 152 °F O None 'You will be charged an additional APEN fee if APEN is filled out incorrectly or information is missing and requires re -submittal. 2Requested values will become permit limitations. MMSCF/yr. MMSCF/yr. - 298 gal/min 300 gal/min 75 MMSCF/day gal/min Additional Information Required: ® Attach a process flow diagram ® Attach the simulation model inputs & emission report ® Attach composition reports for the rich amine feed, sour gas feed, NGL feed, & outlet stream (emissions) ® Attach the extended gas analysis (including BTEX & n -Hexane, H2S, CO2, 2,2,4 Trimethylpentane) ▪ Yes O No O Don't know O Yes ® No O Don't know Colorado Department of Public Health and Environment Air Pollution Control Division (APCD) This notice is valid for five (5) years. Submit a revised APEN prior to expiration of five-year term, or when a significant change is made (increase production, new equipment, change in fuel type, etc). Mail this form along with a check for $152.90 to Colorado Department of Public Health & Environtheath _, APCD-s5-B1.- . ,n-, , 4P8 4b, 4b, 4300 Cherry Creek Drive South c Denver, CO 80246-1530 .1 ,, For guidance on how to complete this APEN f tjleey Air Pollution Control Division: (3 33-)%92-3150 Small Business Assistance Program (SBAP): (303) 692-3148 or (303) 692-3175 APEN forms: www.colorado.gov/cdphe/oilgaspermits Application status: www.colorado.gov/cdphe/permitstatus ® Check box to request copy of draft permit prior to issuance. ® Check box to request copy of draft permit prior to public notice. FORM APCD-206 361631 Page 1 of 2 Amine APEN.doc AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — Amine Sweetening Unit' - Permit Number: Emission Source AIRS ID: / Section 05 — Stack Information (Combustion stacks must be listed here) Operator Stack ID No. Stack Base Elevation (feet) Stack Discharge Height Above Ground Level (feet) Temp. (°F) Flow Rate (ACFM) Velocity (ft/sec) Moisture (%) Al 4870 Section 06 —Stack (Source, if no combustion) Location (Datum & either Lat/Long or UTM) Horizontal Datum (NAD27, NAD83, WGS84) UTM Zone (12 or 13) UTM Easting or Longitude (meters or degrees) UTM Northing or Latitude (meters or degrees) Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) WGS84 (-104.74, 40.26) map Direction of stack outlet (check one): ® Vertical ❑ Vertical with obstructing raincap Exhaust Opening Shape & Size (check one): ❑ Circular: Inner Diameter (inches) = ❑ Horizontal O Down ❑ Other: Length (inches) = ❑ Other (Describe): Width (inches) = Section 07 — Control Device Information (Indicate if a control device controls the flash tank and/or regenerator emissions) ■ VRU used for control of: Combustion Device used for control of: Still vent Rating: 27 MMBtu/hr Size: Make/Model: Type: recuperative Make/Model/Serial #: TBD Requested VOC & HAP Control Efficiency: % VOC & HAP Control Efficiency: Requested: 99 % Manufacturer Guaranteed: 99 % Annual time that VRU is bypassed (emissions vented): % Minimum temp. to achieve requested control: 1400 °F Waste gas heat content: 5 Btu/scf Constant pilot light? • Yes ■ No Pilot burner rating: MMBtu/hr / Describe Any Other: Flash tank vapors will be routed to a low-pressure gas gathering pipeline. In the event that vapors cannot be routed to pipeline, vapors will be routed to the process flare. Section 08 — Emissions Inventory Information & Emission Control Information ® Emission Factor Documentation attached Pollutant n -Hexane Control Device Description Primary Secondary Data year for actual calendar yr. emissions below & gas throughput above (e.g. 2007): Control Efficiency (% Reduction) Emission Factor Actual Calendar Year Emissions2 Requested Permitted Emissions3 Uncontrolled Basis Units lb /►n+Ast lb( t..A045ct (e/w►+NSGk- o.b13 i6 / ivAv 5c4 Uncontrolled (Tons/Year) Controlled (Tons/Year) Uncontrolled (Tons/Year) Controlled (Tons/Year) 3?,o - y 5.0 .O 0.0 Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. 'You will be charged an additional APEN fee if APEN is filled out incorrectly or information is missing and requires re -submittal. z Amoral emission fees will be based on actual emissions reported here. If left blank, annual emission fees will be based on requested emissions. } Estimation Method or Emission Factor Source 90 v4 Modei,2 Qvu n4.04,1 Dos) Maetci Do u i4+orl e( Section 09 —April ' . nt Certification - I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. WO 7- Signa►,f"- o Person Legally Authorized to Supply Data Date Joel Kenyon Name of Legally Authorized Person (Please print) Title HSE Representative Page 2 of 2 Amine APEN.doc General APEN - Form APCD-200 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. There may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, etc.). A list of specialty APENs is available on the Air Pollution Control Division (APCD) website at: www.colorado.Rov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 11 hir-0 3 ggr AIRS ID Number: 12 3 Ii(F22/ Oa 5 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Kerr McGee Gathering Site Name: DJ Gas Plant L A\ w\ S 11c„A Site Location: Section 2, T3N, R66W, Weld County Z Mailing Address: (Include Zip Code) PO Box 173779 Portable Source Home Base: Denver, CO 80217 Site Location County: Weld NAICS or SIC Code: 1321 Permit Contact: Joel Kenyon Phone Number: 720-929-6135 E -Mail Address2: joel.kenyon@anadarko.com Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided. 361632 I Form APCD-200 - General APEN - Revision 1/2017 1 I COLORADO Hw4AbyAVnn+A9nt Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2- Requested Action ❑✓ NEW permit OR newly -reported emission source (check one below) ❑✓ STATIONARY source ❑ PORTABLE source -OR - ❑ MODIFICATION to existing permit (check each box below that applies) ❑. Change fuel or equipment ❑ Change company name ❑ Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership3 ❑ Other (describe below) -OR - ❑ APEN submittal for update only (Blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) ❑ APEN submittal for permit exempt/grandfathered source Additional Info Et Notes: DJ Gas Plant This APEN reflects a proposed process flare at the proposed 3 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Information General description of equipment and purpose: Air -assisted process flare Manufacturer: TDB �I 'r Model No.: Company equipment Identification No. (optional): :.a For existing sources, operation began on: TBD Fl Serial No.: TBD For new or reconstructed sources, the projected start-up date is: 10/01/2018 ❑✓ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day days/week weeks/year Seasonal use percentage: Dec -Feb: 25 Mar -May: 25 Jun -Aug: 25 Sep -Nov: 25 Form APCD-200 - General APEN - Revision 1/2017 2 I COLORADO. DcvmocntofPIN. 1.1.011 6 F+mronmml Permit Number: AIRS ID Number: total combusted gas [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Processing/Manufacturing Information a Material Use ❑ Check box if this information is not applicable to source or process From what year is the actual annual amount? Design Process Rate (Specify Units) Actual Annual Amount (Specify Units) Requested Annual Permit Limit4 (Specify Units) .i Material: Consumption:' 85 MMscf/yr 85 MMscf/yr I oi cycle, I- 3vnwith-A l.? mrdtsc (t r 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) WGS84 (-104.74, 40.26) ❑ Check box if the following information is not applicable to the source because emissions will not be emitted from a stack. If this is the case, the rest of this section may remain blank. F- �Operato Stack ID No £ r*s''`` ,,, e - .n- Discharge Height �emp; bile'Ground Lever m {Feet i '•5n kL c § •� � . - n ' Flow Rafe, , {�CFM� tk'". r-�'g�"•' ` 4 ' Velocity (f sec .. !,.- 60.18 compl. F-1 L `l 110 feet Indicate the direction of t`:stack outlet: (check one) ;i 0 Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑✓ Circular Interior stack diameter (inches): ❑ Square/rectangle Interior stack width (inches): ❑ Other (describe): 0 Upward with obstructing raincap Interior stack depth (inches): Form APCD-200 - General APEN - Revision 1/2017 3 I COLORADO. [bpamnenaafPubUr. E1alla t.Tnrironment Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Combustion Equipment rt Fuel Consumption Information ❑ Check box if this information is not applicable to the source (e.g. there is no fuel -burning equipment associated with this emission source) Design Input Rate (MMBTU/hr) Actual Annual Fuel Use (Specify Units) Requested Annual Permit Limit4 (Specify Units) 12.44 C66. 7 ' MMscf/yr From what year is the actual annual fuel use data? Indicate the type of fuel used5: ny ipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑ Field Natural Gas Heating value: BTU/SCF ❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) ❑ Propane (assumed fuel heating value of 2,300 BTU/SCF) ❑ Coal Heating value: BTU/lb Ash Content: Sulfur Content: {p�� Other (describe): Q I ?e(f)0 b4c7 Heating value (give units): Ql� G U+t+/5c7 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth. s If fuel heating value is different than the listed assumed value, provide this information in the "Other" field. Section 7 - Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? O Yes ❑ No tea ontrolequipment AND state the overall control efficiency (% reduction): Pollutant Contrgq Equipment Detcription Overall Collection Efficiency Overall Control Efficiency (% reduction in emissions) TSP (PM) Ikli r,i PM10 I." :y PM2s ,t:a ' r. ,, ..7 SO. NO. CO VOC combustion -95D/0 q `a °i'0 ci 41,7, 9570 Other: Form APCD-200 - General APEN - Revision 1/2017 4I COLORADO. DepartnencoMBIlr. Hwls4tammonmmt Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 (continued) From what year is the following reported actual annual emissions data? Use the following table to report the criteria pollutant emissions from source: Use the data reported in Sections 4 and 6 to calculate these emissions. Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42 Mfg. etc) A tua A al r ��.- � ��.�,� Ems _-.₹,. Requested mission ... ---s- .,� at(>4mit -�.* Uncontrolled (Tons/year) Controlled° (Tons/year) Uncontrolled (Tons/year) Controlled (Tons/year) TSP (PM) PMto (�•O0� I Ib1 —42e D. 3 C. 3 PM2.5 0.00 5,7 'i%MR4fa;f AP -42©' 6 3 0 _. 3 sox 1.6E-3 lb/hr m.b-g,ocxH2s'""r. 0 NOx 0.068 Ib/MMbtu AP -42 @ 1275 btu/scf ✓ , 8 . CO 0.31 !b/MMbtu AP -42 @ 1275 btu/scf 14 . 1 7 . cO voc IT T `b 3z 4/914SCE ,Mass balance ZZO 7 '. ?, 15. 5 Other: 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Section 8 - Non -Criteria Pollutant Emissions Information Does the emissions source have any uncontrolled actual emissions of non -criteria pollutants (e.g. HAP- hazardous air pollutant) emissions equal to or greater than 250 lbs/year? O Yes ✓❑ No If yes, use the following table to report the non -criteria pollutant (HAP) emissions from source: CAS Number' Chemical I Name C - = Overall. ! Control 1 Uncontrolled Emission Factor. i Efficiency (AP -42, (specify units) Emission Factor Source Mfg. etc) Uncontrolled Actual Emissions (lbs/year) Controlled Actual Emissions (lbs/year) C1 6 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-200 - General APEN - Revision 1/2017 51 COLORADO ocparmcmotaaeuk H,Vb4£ranronm,.ni. Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 9 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. Sig of Legally Authorized Person (not a vendor or consultant) Date ature Joel Kenyon HSE Representative Name (print) Title Check the appropriate box to request a copy of the: ❑✓ Draft permit prior to issuance E Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. 'a Send this form along with $1.2.90 to: Colorado Department of Public Health and Environment Air Pollution ContrOil Division APCD-SS-B1 ICJ 4300 Cherry Creek•Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment Telephone: (303) 692-3150 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-200 - General APEN - Revision 1/2017 6 I COLORADO DepartmentofPuhtic H.14141.4rtnnntml •"` slt( Fugitive Component Leak Emissions APEN - Form APCD-203 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for fugitive component leak emissions. If your emission source does not fall into this category, there may be a different specialty APEN available for your operation (e.g. natural gas venting, condensate tanks, paint booths, etc.). In addition, the General APEN (Form APCD- 200) is available if the specialty APEN options do not meet your reporting needs. A list of specialty APENs is available on the Air Pollution Control Division (APCD) website at www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 17WE0398 AIRS ID Number: 123 / 9F22 / 00(P [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name1: Kerr McGee Gathering Site Name: Latham Gas Plant Site Location: Section 2, T3N, R66W, Weld County Mailing Address: •-• Box 173779 (Include Zip Code) Denver, CO Permit Contact: Joel Kenyon E -Mail Address2: joel.kenyon@anadarko.com Site Location Weld County: NAICS or SIC Code: 1321 Phone Number: 720-929-6135 I Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided. Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision 7/2017 COLORADO I NutlnL Fn=mt Permit Number: 17W E0398 AIRS ID Number: 123 / 9F22 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Regulatory Information What is the date that the equipment commenced construction? Will this equipment be operated in any NAAQS nonattainment area?5 ❑✓ Yes ❑ No Will this equipment be located at a stationary source that is considered a ❑ Yes (] No Major Source of Hazardous Air Pollutant (HAP) emissions? Are there wet seal centrifugal compressors or reciprocating compressors 0 Yes ❑ No located at this facility? Is this equipment subject to 40 CFR Part 60, Subpart KKK? ❑ Yes Q No Is this equipment subject to 40 CFR Part 60, Subpart OOOO? ❑ Yes 0 No Is this equipment subject to 40 CFR Part 60, Subpart OOOOa? ✓❑ Yes ❑ No Is this equipment subject to 40 CFR Part 63, Subpart HH? ❑✓ Yes ❑ No Is this equipment subject to Colorado Regulation No. 7, Section XII.G? 0 Yes ❑ No Is this equipment subject to Colorado Regulation No. 7, Section XVII.F? ❑ Yes 0 No Is this equipment subject to Colorado Regulation No. 7, Section XVII.B.3? ❑ Yes ❑✓ No 5 See http://www.colorado.Rov/cdphe/state-implementation-plans-sips for which areas are designated as attainment/non- attainment. Section 5 - Stream Constituents 2 The required representative gas and liquid extended analysis (including BTEX) to support the data below has been attached to this APEN form. Use the following table to report the VOC and HAP weight % content of each applicable stream. Gas 22 enzene.; 4 4 4 8 4 4 Heavy Oil (or Heavy Liquid) 100 4 4 4 4 8 4 Light Oil (or Light Liquid) 100 4 4 4 4 8 4 Water/Oil 100 4 4 4 4 8 4 Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision 7/2017 Ay COLORADO 3 I ',MI Permit Number: 17WE0398 AIRS ID Number: 123 / 9F22 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Emission Factor Information Select which emission factors were used to estimate emissions below. If none apply, use the table below to identify the emission factors used to estimate emissions. Include the units related to the emission factor. 0 Table 2-4 was used to estimate emissions7. ❑ Table 2-8 (< 10,000ppmv) was used to estimate emissions7. Use the following table to report the component count used to calculate emissions. The component counts listed in the following table are representative of: 0 Estimated Component Count ❑ Actual Component Count conducted on the following date: Count8 1684 67 11806 908 rtent Emission Factor Units Count8 3953 17 468 9 Emission Factor Units Count8 2260 385 11 1412 24 Emission Factor Units '�Watie�i Count8 Emission Factor Units 7 Table 2-4 and Table 2-8 are found in U.S. EPA's 1995 Protocol for Equipment Leak Emission Estimates (Document EPA -453/R- 95-017). 8 The count shall be the actual or estimated number of components in each type of service that is used to calculate the "Actual Calendar Year Emissions" below. 9 The Other equipment type should be applied for any equipment other than connectors, flanges, open-ended lines, pump seals, or valves. Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision 7/2017 5 I ��coLORAoo �f«Ff�.;w N Permit Number: 17WE0398 AIRS ID Number: 123 / 9F22 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 10 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. •r r ,:"f 10/20/2017 Signature of Legally Authorized Person (not a vendor or consultant) Date Joel Kenyon HSE Representative Name (print) Title Check the appropriate box to request a copy of the: ❑✓ Draft permit prior to issuance E Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Send this form along with $152.90 to: For more information or assistance call: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment Telephone: (303) 692-3150 Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision 7/2017 ®®ir4zrecoLog Aoo 7 I ≥rou"nou'voN Hello