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Home My WebLink About20193760.tiffa COLORADO Department of Public Health b Environment Nick Holland Nick. holland®curetonmidstream.com August 14, 2019 Ref: Permit No: 19WE0081 SUBJECT: Draft Permit and Related Public Notice Dear Nick Holland: RECEIVED AUG 1 9 FA WELD COUNTY COMMISSIONERS The Air Pollution Control Division has prepared a public comment package for the Cureton Front Range LLC - Hookside Gas Plant. The thirty (30) day public notice period will begin on August 22, 2019. This public notice period is being provided in accordance with the Colorado Air Pollution Prevention and Control Act and Regulation No. 3, Part B, Section III.C. For thirty (30) days from the beginning of the notice period, copies will be available for public inspection at the respective county clerk's office(s). During the thirty -day period, please review your permit and call your permit engineer with any questions or concerns you may have. This application is complete and in proper form. It meets the requirements of the Colorado Air Quality Control Commission's Regulation No. 3, Part B, Section III.B. Sincerely, Christian Lesniak Stationary Sources Air Pollution Control Division Enclosures 4300 Cherry Creek Drive S., Denver, CO 80246-1530 P 303-692-2000 www.colorado.gov/cdphe Public (...view Jared Polis, Governor I Jill Hunsaker Ryan, MPH, Executive Director c -c-: PLurP),i-ICJT),OCpCJen). c,staca 19 PC4)(u"OrItER'ICi-if Cis) V2. 2019-3760 a COLORADO Department of Public Health ft Environment Weld County - Clerk to the Board 1150 O St PO Box 758 Greeley, CO 80632 August 14, 2019 Dear Sir or Madam: On August 22, 2019, the Air Pollution Control Division will begin a 30 -day public notice period for Cureton Front Range LLC - Hookside 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 Et 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 Jared Polls, Governor I Jill Hunsaker Ryan, MPH, Executive Director Colorado Air Permitting Project PRELIMINARY ANALYSIS - PROJECT SUMMARY Project Details Review Engineer: Christian Lesniak Package #: 392390 Received Date: 1/22/2019 Review Start Date: 3/5/2019 Section 01 - Facility Information Company Name: Cureton Front Range LLC County AIRS ID: 123 Quadrant Section Township Range 30 oN Plant AIRS ID: Facility Name: Physical Address/Location: County: Type of Facility: What industry segment? Oil & Natural Gas Production & Processing Is this facility located in a NAAQS non -attainment area? A020 Hookside Gas Plant Section 30, Township 9N, Range 60W Weld County Natural Gas Processing Plant If yes, for what pollutant? Carbon Monoxide (CO) Section 02 - Emissions Units In Permit Application No Particulate Matter (PM) I I Ozone (NOx & VOC) AIRs Point # Emissions Source Type Equipment Name Emissions Control? Permit # Issuance # Self Cert Required? Action Engineering Remarks 001 Amine Unit Amine' 18WE0081 Permit Initial Issuance 002 Amine Unit Amine2 18WE0081 Yes Permit Initial Issuance 003 Amine Unit Amine3 18WE0081 Yes Permit Initial Issuance 004 Dehydrator 18WE0081 Yes Permit Initial Issuance Dehydrator TE 18WE0081 A Yes Permit Initial Issuance Condensate Tank TY 18WE0081 1 Yes Permit Initial Issuance 007 Produced Water Tank TK2 - TK6 1.8WE0081 1. Permit Initial Issuance 008 NG Heater HTR2 18WE0081 L.) Permit Initial Issuance -,pine Reboiler 009 NG Heater HTR3 No 18WE0081 Permit Initial Issuance Stabilizer Heater NG Heater 18WE0081 Yei Permit Initial Issuance Mol Sieve Regen Gas Heater NG Heater 18WE00S1 Yes Permit Initial Issuance Amine Reboiler NG Heater 18WE0081 Yes Permit Initial Issuance Stabilizer Heater Maintenance Blowdo:vru rtit,; ire;, 18WE0081 Yes Permit Initia Issuance Fugitive Component Leaks 18WE0081 Permit Initia' Issuance Other (Explain) Methanol Tank - No emission limit. APEN reportable because of HAPs, therefore permit required Liquid Loading LOAD4 Yes 18WE0081 Permit Initia Issuance NGL loadout Liquid Loading LOAD3 Yes 18WE0081 Permit Initial Issuance liquid loading - mixed liquids Liquid Loading LOAD2 Yes 18WE0081 Permit Initia Issuance liquid loading - mixed liquids Condensate Tank TK8 - TK9 18WE0081 1 Permit Initial Issuance Condensate Tank TK10 - TK11 18WE0081 1 Permit Initial Issuance Section 03 - Description of Project Point 013 is a heater below 10 MMSCFD and is exempt Point 016 is Point 017 is a methanol tank that is reportable for HAPs (methanol), and therefore needs a permit, though it is below reporting thresholds for VOC alone Colorado Air Permitting Project Section 04 - Public Comment Requirements Is Public Comment Required? Yes If yes, why? Requesting Synthetic Minor Permit Section 05 - Ambient Air Impact Analysis Requirement. Was a quantitative modeling analysis required? No 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 (PSD) Title V Operating Permits (OP) Non -Attainment New Source Review (NANSR) Yes 5O2 NOx CO VOC PM2.5 PM10 TSP HAPs Is this stationary source a major source? If yes, explain what programs and which pollutants here SO2 Prevention of Significant Deterioration (PSD) Title V Operating Permits (OP) Non -Attainment New Source Review (NANSR) NOx perseumej • • CO VOC PM2.5 PM10 TSP HAPs ■ Amine Sweetening Unit Emissions Inventory 001 Amine Unit Facility AIRS ID: 123 County A020 Plant Point Section 02 - Equipment Description Details Amine Unit Information Amine Unit Type: Make: Model: Serial Number: Design Capacity: Recirculation Pump Information Number of Pumps Make: Model: Design/Max Recirculation Rate: Amine Unit Equipment Flash Tank Regenerator Heat Source AIRS ID Amine Unit Equipment Description 3XX: Wx, it'i ,X�xy atf% xau, x. Cga :54xl.:xx%O t v' fI XXW t_•l�Il'xnl. . ta ND T3O TSD 200 2 TBD TBD 600 MMscf/day gallons/minute flash tank, and amine regeneration heat source from HTR-S (AIRS Point 011) One (1) Methytdiethanolamine (MDEA) natural gas sweetening unit (Make: TBD, Model: TBD, Serial Number: TBD) with a design capacity of 200 MMscf per day. This emissions unit is equipped with 2 (Make: TBD, Model: TBD) amine pump with a design capacity of 600 gallons per minute. This natural gas sweetening unit is equipped with a still vent, flash tank, and amine regeneration heat source (AIRS Point 011). Emission Control Device Description: Emissions from the still vent are routed to the Thermal Oxidizer. Emissions from the flash tank are routed directly to the closed -loop system. Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Amine Unit Still Vent and Flash Tank (if present) Requested Permit Limit Throughput = 73,000.0 MMscf per year MMscf per year Requested Monthly Throughput = 6200 MMscf per month Potential to Emit (PTE) Throughput = Secondary Emissions - Combustion Device(s) for Air Pollution Control Still Vent Control Primary control device: Primary control device operation: Secondary control device: Secondary control device operation: Still Vent Gas Heating Value: Still Vent Waste Gas Vent Rate: Flash tank Control Primary control device: Primary control device operation: Secondary control device: Secondary control device operation: Flash Tank Gas Heating Value Flash Tank Waste Gas Vent Rate: 73,000 0 hr/yr 13.460 Btu/scf 496E-00 MMSCFD 1 0 hr/yr 1264.36 Btu/scf 2.17E-01 MMSCFD 9835 Control Efficiency Control Efficiency % 100% Control Efficiency % Control Efficiency% Requested TO Temp Requested TO Temp Requested TO Temp Requested TO Temp Degrees F Degrees F Degrees F Degrees F Waste Gas Combusted: Still Vent Primary Control: 7,:=1.0,2 MMscf/yr Still Vent Secondary Control: 0.0 MMscf/yr Waste Gas Combusted: Flash Tank Primary Control: Flash Tank Secondary Control: 0.0 MMscf/yr 0.0 MMscf/yr Primary Control Device Pilot f o!•I Use Rate. Assist Gas Rate: Pilot Fuel Gas Heating Value: Assist Gas Heating Value: Pilot & Assist Gas Heating Value: Assist Gas MW: Assist Gas VOC weight %: Thermal Oxidiser scfh 21004.56621 scfh Btu/scf 1030 Btu/scf 1030.0 Btu/scf 0.0 MMscf/yr 134.0 MMscf/yr Secondary Control Device Pilot Fuel Use Rate: Assist Gas Rate: Pilot Fuel Gas Heating Value: Assist Gas Heating Value: Pilot & Assist Gas Heating Value: Not applicable scfh scfh Btu/scf Btu/scf 0.0 Btu/scf 0.0 MMscf/yr 0.0 MMscf/yr How Will Source Demonstrate Compliance? Process Parameter Inlet Sour Gas Thro : h Still Vent Waste Gas to Thermal Oxidizer Flash Tank Waste Gas to closed -loo iv1F4 c::. Requested Permit Process Limits Combustion of Pilot and Su y• lemental Fuel at Thermal Oxidizer Lean Amine Recirculation Rate Section 04 - Emissions Factors & Methodologies Amine Unit Source estimated emissions in Promar based an a projected Inlet gas composition Input Parameters Inlet Gas Pressure Inlet Gas Temperature Requested Lean Amine Recirculation Rate Lean Amine Weight % Flash Tank Pressure Flash Tank Temperature Inlet H2S Concentration Inlet VOC Concentration 1000 59.3 $00 50.2 65 too 0.0401 25.03 16.68 Ib/Ibmol 0.45 % Annual Limit (MMscf/yr) 73000 psig 'F gpm psia 'F Wt 14 wt% Monthly Limit (31 day) (MMscf/month) Gallons Per Minute Metered Parameters Notes on Meted : Amine Sweetening Unit Emissions Inventory STILL VENT Control Scenano Primary Secondary Pollutant Uncontrolled (lb/hr) Controlled (lb/hr) Controlled (lb/hr) VOC 38.447 0.76894 0 Benzene 11.2920 0.22584 0 Toluene 5.665 0.1133 0 Ethylbenzene 0.735 0.0147 0 Xylenes L664 0.03328 0 n -Hexane 0.082 0.00164 0 224-TMP 7.4153E-06 L48306E-07 0 Hz5 0.726937 0.01453874 0 Methanol 0 0 0 FLASH TANK Control Scenario Primary Secondary Pollutant Uncontrolled (lb/hr) Controlled (lb/hr) Controlled (lb/hr) VOC 10L368 0 0 Benzene 0.4026 0 0 Toluene 0.147221 0 0 Ethylbenzene 0.0162787 0 0 Xylenes 0.02313777 0 0 n -Hexane 0.428668 0 0 224-TMP 8.49701E-05 0 0 H7S 0-00101973 0 0 Methanol 0 0 0 SOx Emission Calculations: Molecular Weight of 502 64.066 Ib/Ibmol Molecular Weight of His 34.08088 lb/Ibmol SOx Emissions (Still Vent) 6.0 tpy SOx Emissions (Flash Tank) 0 tpy Requested Buffer (%): 0.018907509 Emission Factors Amine Unit Pollutant Uncontrolled Controlled (lb/MMscf) (lb/MMscf) Emission Factor Source (Sour Gas Throughput) (Sour Gas Throughput) VOC 16.79 0.10 Benzene L4033562 0.027100E Toluene 0.69746652 0.013596 Ethylbenzene 0.090153444 0.00176-1 r-a:\.;,;i:, Xylene 0.202456532 0,003993E i'rotrb+? n -Hexane 0.06128016 0.0001968 ::'r4'k` 224 TMP 1.10862E-05 1.77967E-08 'mfr' H25 0.087354908 0.001744649 '•:tr.r Methanol '•70.1: - Pollutant Still Vent Primary Control Device Uncontrolled Uncontrolled (lb/MMBtu) (lb/MMscf) Emission Factor Sett n* (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.1003 PM2.S 0.1003 SOx 6.6131 NOx L3191 Manufacturer Manufacturer CO 1.1037 Pollutant Still Vent Secondary Control Device Emission Factor Source Uncontrolled Uncontrolled (lb/MMBtu) (lb/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0000 PM2.5 0.0000 SOx 0.0000 NOx 0.0000 CO 0.0000 Pollutant Flash Tank Primary Control Device Emission Factor Source Uncontrolled Uncontrolled (lb/MMBtu) (lb/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0000 PM2.5 0.0000 SOx 0.0000 NOx 0.0000 CO 0.0000 Pollutant Flash Tank Secondary Control Device Emission Factor Source Uncontrolled Uncontrolled (lb/MMBtu) (lb/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0000 PM2.S 0.0000 SOx 0.0000 NOx 0.0000 CO 0.0000 Supplemental Fuel to Still Vent Primary Control Cmiv.:ion Fat to: So tr. c Uncontrolled Uncontrolled Pollutant (Ib/MMBtu) (Ib/MM5cf) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0075 7.6745 4J44 Ts* 1.4-Zinkit. /PhM4..; i‘ri Jr: -_-- .. S.; i%4'.r'rrtt.:*: Manufacturer Manufacturer Mass Balance PM2.5 0.0075 7.6745 SOx 0.0006 0.6059 NOx 0.098e 100.9400 CO 0.0820 84.4600 VOC 0.0054 3.9609 Supplemental Fuel to Still Vent Secondary Control _ Emission Factor Source Uncontrolled Uncontrolled Pollutant (lb/MMBtu) (lb/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0000 PM2.5 0.0000 SOx 0.0000 NOx 0.0000 CO 0.0000 VOC 0.0000 C3 C4 C5 C6 C7 C8 C9 C10 Total VOC 13.95 3.95 0.802805 0.35 0.04 19.36 3.58E -OS 6.83E-06 38.447 77.40 19.05 3.51 0.68 0.13 0.60 0.00 0.00 101.368 Amine Sweetening Unit Emissions Inventory Section 05 - Emissions Inventory Requested Permit Monthly Emission Limits Process Parameter Pollutant PM10 (lbs/month) PM2.5 (lbs/month) SOx (lbs/month) H25 (lbs/month) NOx (lbs/month) CO (lbs/month) VOC (lbs/month) Still Vent Waste Gas to Thermal Oxidizer 15 203 Supplemental Fuel Sent to Thermal Oxidizer 120 1577 Still Vent Waste Gas to Thermal Oxidizer and Su • • emental Fuel Sent to Thermal Oxidizer 135 0 a 0 1780 r 0 G 0 u 0 ¶i 0 o a Cr I) Flash Tank Waste Gas to cbsed-loo • • m 0 0 Requested Permit Annual Emission Limits Pollutant Process Parameter Still Vent Waste Gas to Thermal Oxidizer Supplemental Fuel Sent to Thermal Oxidizer Still Vent Waste Gas to Thermal Oxidizer and Supplemental Fuel Sent to Thermal Oxidizer Total PM10 (tons/year) 0.8 PM2.5 (tons/year) SO* (tons/year) H2 S NOx (tons/year) (tons/year) CO (tons/year) VOC (tons/year) Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.S 5Ox 1115 NOx CO VOC 0.8 0.8 0.3 0.3 0.3 us 0.8 0.8 0.8 0.8 0.8 135 6.0 6.0 6.0 6.0 6.0 1026 3.2 3.2 0.1 3.2 0.1 11 10.5 10.5 10.5 10.5 10.5 1780 8.8 8.8 8.8 8.8 8.8 1490 612.8 612.8 3.7 612.8 3.7 634 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (Ibs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene Toluene Ethylbenzene Xylene n -Hexane 224 TMP H;S Methanol 102415 102.145 14'? 10234S 1973 50915 50915 993 50915 993 6581 6581 129 6581 129 1477'; 14779 292 14779 292 4473 4473 14 4473 14 1 1 0 1 0 6377 127 6377 127 6377 0 0 0 0 0 ction 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit 40 CFR, Part 60, Subpart LLL You have indicated that this facility is not subject to NSPS LLL 40 CFR, Part 60, Subpart OOOO You have indicated that this facility is not subject to NSPS OOOO. 40CFR, Part 60, Subpart 0000a Facility is subject to NSPSt000a - Recordkeeping and Reporting Requirements per 60.5423a(c) (See regulatory applicability worksheet for detailed analysis) Amine Sweetening Unit Emissions Inventory Section 07 - Initial and Periodic Sampling and Testing Requirements Sampling Stream Has source provided a site -specific sample within the last year? Is Periodic Sampling Needed? Is Initial Sampling Needed? Composition? Heat Content? Conclusion Inlet (Sour) Gas Yes Yes Yes No Periodic and initial sampling is required for gas composition. Still Vent Waste Gas fr : Yes Yes Yes Yes Periodic and Initial sampling is required for gas composition and heat content. Flash Tank Waste Gas N ' No No No No No sampling is required Supplemental Fuel to Thermal Oxidizer fes No N/A Yes Periodic sampling is required for gas heat content only Supplemental Fuel to Not applicable ht allo No N/A No No sampling is required Testing Still Vent Control Control Device Is this an enclosed combustor or thermal oxidizer? (Can this control device be tested?) Requested Control % Requested Minimum Combustion Chamber Temperature Thermal oxidizer with requested minimum combustion chamber temp below 1400 F? Has a control percentage greater than 95% been requested for a testable combustion device? Conclusion Primary Control Thermal Oxidizer , _ ,. This Thermal Oxidizer must be stack tested to determine its control efficiency at the requested minimum chamber temperature of N/A Secondary Control Not applicable No stack testing is required Flash Tank Control Primary Control dosed -loop system .. 10O ti N/A ',o No No stack testing is required Secondary Control Not applicable 0% N/A No No No stack testing is required Section 08 - Technical Analysis Notes Secondary emissions for all amine unit still vents counted on AIRs Point001 (AMINE 1) by source. I am splitting up the waste gas throughputs and subsequent secondary emissions to each unit tam including all supplemental fuel as a process under Amine Unit 1 (Point 001). In doing this, I will require metering and sampling of each waste gas stream, and as a compliance demonstration, the operator will have to calculate secondary emissions for the supplemental fuel stream on this unit. Each amine unit will be metered separately in order to calculate VOC and H2S emissions per unit Fuel to the thermal oxidizer will also be metered. 'I've calculated emissions of VOC from the combustion of supplemental fuel (i.e. "supplemental fuel to thermal oxidizer") using a mass balances that assumes 98% destruction of VOC This calculation is as follows and is based on residue gas composition as predicted in the facility ProMax model run 10/18/18 and as included in the application supporting materials: (VOC wt fraction) x (MW gas) x (1/379lbmol/scf) x (101'6scf/MMscf) x (184.0 MMscf/yr assist flow) x (1-98% Requested DRE) Source claimed 600 gpm lean amine recirculation rate in initial submittal, and corrected to 800 gpm during draft comments. Source also calculated slightly higher emissions for allsecondary emissions, but after speaking with source, this represents adding secondary emissions from Amine3 to this unit I have calculated those emissions on Amine3 and am not adding them to this point - They are below permitting thresholds on that unit. I have not been able to get the same emission factors as source for process 01 and process 02, despite agreeing on emission limits. It is possible that the other numbers represent a different waste gas heat content for the still vent. I am defaulting to my calculations. Section 09 - Inventory 5CC Coding and Emissions Factors AIRS Point X re 1 Process X 01 Pollutant PM10 PM2.5 SOx H15 NON VOC CO Benzene Toluene Ethylbenzene Xylene n• Hexane 224 TMP Methanol Uncontrolled Emissions Factor Control % 0.0 0.022 0.0 0.166 0.0 0.087 98.0 0.287 0.0 16.8 99.4 0.240 0.0 L403 98.1 0.697 98.1 0.090 98.0 0.202 98.0 0.061 99.7 0.000 99.8 0.000 #DIV/0! Units lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf Amine Sweetening Unit Regulatory Analysis Worksheet Colorado Regulation 3 Parts A and B - APEN and Permit ReQuirements Source is in the Attainment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.3)? Yes Yes Source requires a permit NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOx greater than S TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.2)? You have indicated that source is in the Attainment Area NSPS Analysis 1. Is the sweetening unit located at an onshore natural gas processing plant that processes natural gas produced from either onshore or offshore wells? Yes Source is subject to NSPS - Continue to determine applicable sections 40 CFR, Part 60, Subpart LLL, Standards of Performance for SO2 Emissions from Onshore Natural Gas Processing 1. Did construction or modification (see definitions 40 CFR 60.2) of the sweetening unit commence after January 20, 1984 and on or before August 23, 2011 (60.640(d))? 2. Does facility have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) (60.640(b))? 3. You have indicated that this facility is not subject to NSPS ILL. Subpart A, General Provisions §60.642 - Standards for sulfur dioxide §60.646 - Monitoring of emissions and operations §60.647 - Recordkeeping and reporting requirements 40 CFR, Part 60, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution 1. Did construction, modification or reconstruction (see definitions 40 CFR 60.2) of the sweetening unit commence after August 23, 2011 and on or before September 18, 2015? 2. Does facility have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) (60.5365(g)(3))? You have indicated that this facility is not subject to NSPS OOOO. Subpart A, General Provisions per §60.5425 Table 3 §60.5405 - Standards for sulfur dioxide §60.5407 - Monitoring of emissions and operations § 60.5423 - Notification, Recordkeeping and reporting requirements 40 CFR, Part 60, Subpart OOOOa, Standards of Performance for Crude Oil and Natural Gas Facilities 1. Did construction, modification or reconstruction (see definitions 40 CFR 60.2) of the sweetening unit commence after September 18, 2015? 2. Does facility have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) (60.5365a(g)(3))? Facility is subject to NSPS OOOOa - Recordkeeping and Reporting Requirements per 60.5423a(c) Subpart A, General Provisions per §60.5425a Table 3 §60.5405a - Standards for sulfur dioxide Do Not Apply §60.5407a - Monitoring of emissions and operations Do Not Apply §60.5423a(c) - Recordkeeping and reporting requirements Colorado Regulation 3 Parts B, Section III.D.2.a - RAG _ Site is in attainment and not subject to RACT Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations. and Air Quality Control Commission regulations. This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law. regulation. or any other legally binding requirement and is not legally enforceable. in the event of any conflict between the language of this document and the language of the Clean Air Act„ its implementing regulations, and Air Quality Control Commission regulations, the language of the statute or regulation will control. The use of non -mandatory language such as "recommend," -may," "should, " and "can, " is intended to describe APCD interpretations and recommendations. Mandatory terminology such as "must" and 'required" are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself Amine Sweetening Unit Emissions Inventory 002 Amine Unit Facility AIRs ID: County At120 Plant 002 Point Section 02 - Equipment Description Details Amine Unit Information Amine Unit Type: Make: Model: Serial Number: Design Capacity: Recirculation Pump Information Number of Pumps Make: Model: Design/Max Recirculation Rate: Amine Unit Equipment Flash Tank Regenerator Heat Source AIRS ID 2 MMscf/day TED TBD 250 allons/minute , flash tank, and amine regeneration heat source from HTR-2 (AIRS Point 0108 One (1) Methyldietha nola mine (MDEA) natural gas sweetening unit (Make: TBD, Model: TBD, Serial Number: TBD) with a design capacity of 60 MMscf per day. This emissions unit is equipped with 2 (Make: TBD, Model: TBD) Amine Unit Equipment Description amine pump with a design capacity of 250 gallons per minute. This natural gas sweetening unit is equipped with a still vent, flash tank, and amine regeneration heat source (AIRS Point 008). Emission Control Device Description: Emissions from the still vent are routed to the Thermal Oxidizer. Emissions from the flash tank are routed directly to the closed loop system. Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Amine Unit Still Vent and Flash Tank (if present) Requested Permit limit Throughput = 21,900.0 Potential to Emit (PTE) Throughput = MMscf per year MMscf per year Requested Monthly Throughput = 1860 MMscf per month Secondary Emissions - Combustion Device(s) for Air Pollution Control Still Vent Control Primary control device: Primary control device operation: Secondary control device: Secondary control device operation: Still Vent Gas Heating Value: Still Vent Waste Gas Vent Rate: Flash tank Control Primary control device: Primary control device operation: Secondary control device: Secondary control device operation: Flash Tank Gas Heating Value Flash Tank Waste Gas Vent Rate: Vflf,ctskiG9}t,:x.} ytPSTq 21,900 hr/yr 11.25 Btu/scf i.80f+00 MMSCFD Thermal ;anhYr hr/yr 1183.37 Btu/scf 8.09E-02 MMSCFD 98% Control Efficiency % Requested TO Temp Control Efficiency % Requested TO Temp 10(1x. Control Efficiency `,5 Requested TO Temp Control Efficiency % Requested TO Temp Degrees F Degrees F Degrees F Degrees F Waste Gas Combusted: Still Vent Primary Control: Still Vent Secondary Control: Waste Gas Combusted: Flash Tank Primary Control: Flash Tank Secondary Control: >3., MMscf/yr fh.0 MMscf/yr MMscf/yr 0.(J MMscf/yr Primary Control Device Pilot Fuel Use Rate: Assist Gas Rate: Pilot Fuel Gas Heating Value: Assist Gas Heating Value: Pilot & Assist Gas Heating Value: scfh 184 scfh Btu/scf 10:30 Btu/scf 1030.0 Btu/scf 0.0 MMscf/yr 1.6 MMscf/yr Secondary Control Device Pilot F uel Use Pate: Assist Gas Rate. Pilot Fuel Gas Heating Value: Assist Gas Heating Value: Pilot & Assist Gas Heating Value: Not applicable scfh scfh Btu/scf Btu/scf 0 C Btu/scf 0.0 MMscf/yr 0.0 MMscf/yr How Will Source Demonstrate Compliance? Requested Permit Process Limits Process Parameter Annual Limit (MMscf/yr) Monthly Limit (31 day) (MMscf/month) Metered Parameters Inlet Sour Gas Throu : h • ut Still Vent Waste Gas to Thermal Oxidizer Combustion of Pilot and Supplemental Fuel at Thermal Oxidizer 21900 6158.7 Section 04 - Emissions Factors & Methodologies Amine Unit Source estimated emissions in Pramax based on a projected inlet gas :composition Input Parameters Inlet Gas Pressure Inlet Gas Temperature Requested Lean Amine Recirculation Rate Lean Amine Weight % flash Tank Pressure Flash Tank Temperature Inlet H2S Concentration Inlet VOC Concentration 2S0 501, 65 148.5 0.0001 25.03 psig 'F gp m psia SF wt % wt % 0 Amine Sweetening Unit Emissions Inventory STILL VENT Control Scenano Primary Secondary Pollutant Uncontrolled (Ib/hr) Controlled (lb/hr) Controlled (lb/hr) VOC 129473 0.25806 0 Benzene 4.3314 0.0986272 0 Toluene :24689 0.0249378 0 Ethylbenzene 0.00824523 0.000164905 0 Xylenes 0.0482842 0.000965684 0 n -Hexane 0.0651733 0.001303466 0 224-TMP 0.000198312 3.96624E-06 0 H15 0 0 0 Methanol 0 0 0 FLASH TANK Control Scenario Primar Seconda Pollutant Uncontrolled (lb/hr) Controlled (lb/hr) Controlled (Ib/hr) VOC 51.133 0 0 Benzene 0.3733 0 0 Toluene 0.0801439 0 0 Ethylbenzene 0.00059[564 0 0 Xylenes 0.002513328 0 0 n -Hexane 0.665839 0 0 224 -IMP 0.00378514 0 H,S 0 0 0 Methanol n 0 0 SOx Emission Calculations: Molecular Weight of SO) 64.066 Ib/Ibmol Molecular Weight of H2S 34.08088 Ib/Ibmol SOx Emissions (Still Vent) 0 tpy SOx Emissions (Flash Tank) 0 tpy Requested Buffer (%): Emission Factors Amine Unit Pollutant Uncontrolled Controlled (lb/MMscf) (lb/MMscf) Emission Factor Source (Sour Gas Throughput) (Sour Gas Throughput) VOC 25.61 0.10 if: akta x Benzene 2.1218796 0.03945088 ProMn"X Toluene 0.53081356 0.0099751.2 Profk:rt Ethylbenzene 0.003534318 6.59618E-05 ProMax Xylene 0.020319211 0.000336274 I•roMa;t n -Hexane 0.29240492 0.000521386 Pre:'::•x 224 TMP 0.001593381 1.5865E-06 H=S 0 0 Methanol Pollutant Still Vent Primary Control Device Uncontrolled Uncontrolled (lb/MMBtu) (lb/MMscf) Emission Factor Source (Waste Heat Combusted) (Waste Gas Combusted) PM 10 0.08..; Manufacturer Manufacturer PM2.5 0.0838 SOx 0.0000 NOx 1.1025 CO 0.9225 Pollutant Still Vent Secondary Control Device Emission Factor Source Uncontrolled Uncontrolled (lb/MMBtu) (lb/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0000 PM2.5 0.0000 SOx 0.0000 NOx 0.0000 CO 0.0000 Pollutant Flash Tank Primary :ontrol Device Emission Factor Source Uncontrolled Uncontrolled (lb/MMBtu) (lb/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0000 PMZ.5 0.0000 SOx 0.0000 NOx 0.0000 CO 0.0000 Pollutant Flash Tank Secondary Control Device Emission Factor Source Uncontrolled Uncontrolled (lb/MMBtu) (lb/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0000 PM2.5 0.0000 SOx 0.0000 NOx 0.0000 CO 0.0000 Pollutant Supplemental Fuel to Still Vent Primary Control Eniv,s;on F ?t for A,ur'.r Uncontrolled Uncontrolled (lb/MMBtu) (lb/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) PM 10 0.0000 PM2.5 0.0000 SOx 0.0000 NOx 0.0000 CO 0.0000 VOC »00 Supplemental Fuel to Still Vent Secondary Control Emission Factor Source Uncontrolled Uncontrolled Pollutant (lb/MMBtu) (lb/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0000 PM2.5 0.0000 SOx 0.0000 NOx 0.0000 CO 0.0000 VOC 0.0000 C3 C4 C5 C6 C7 C8 C9 C10 Total VOC 4.23 2.12 0.2548908 0.07 0.00 6.24 0.00E+00 0.00E+00 12.903 32.81 14.51 2.68 0 67 0.01 0.47 0.00 0.00 51.133 Amine Sweetening Unit Emissions Inventory Section 05 - Emissions Inventory Requested Permit Monthly Emission Limits Process Parameter Pollutant PM10 (lbs/month) PM2.5 (lbs/month) SOx (lbs/month) He (lbs/month) NOx (lbs/month) CO (lbs/month) VOC (lbs/month) Still Vent Waste Gas to Thermal Oxidizer 4 i:9 4 VI 0 C_7 0 Cr, 61 63 51 61 1 i2 /r Supplemental Fuel Sent to Thermal Oxidizer 0 CY1 0 (0 0 10 1 CO 0 CC 0 0. Still Vent Waste Gas to Thermal Oxidizer and Su :d• emental Fuel Sent to Thermal Oxidizer 4.69 4.69 0.00 0.00 61.63 51.61 192.00 Flash Tank Waste Gas to closeddoo • s • m 0.00 0.00 0.00 0.00 0.00 0.00 f 00 Total Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 SOx H7S NOx CO VOC 0.0 0.0 0.0 0.0 0.0 5 0.0 0.0 0.0 0.0 0.0 5 0.0 0.0 0.0 0.0 0.0 0 0.0 0.0 0.0 0.0 0.00 0 0.4 0.4 0.4 0.4 0.4 62 0.3 0.3 0.3 0.3 0.3 52 280.5 230.5 1.1 280.5 L I 192 Hazardous Air Pollutants Potential to Emit Uncontrolled (bs/year) Actual Emissions Uncontrolled Controlled (bs/year) (bs/year) Requested Permit Limits Uncontrolled Controlled (bs/year) (bs/year) Benzene 46469 46469 864 46469 86-1 Toluene 11625 11625 213 11625 213 Ethybenzene 77 77 1 77 1 Xykne 445 445 8 445 3 n -Hexane 6404 6404 11 6404 11 2241MP 35 35 0 35 0 H=5 0 0 0 0 0 Methanol 0 0 0 0 0 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit 40CFR, Part 60, Subpart LLL You have indicated that this facility is not subject to NSPS LLL 40 CFR, Part 60, Subpart 0000 You have indicated that this facility is not subject to NSPS 0000. 40 CFR, Part 60, Subpart 0000a Facility is subject to NSPS 0O00a - Recordkeeping and Reporting Requirement per 60.5423a(c) (See regulatory applicability worksheet for detailed analysis) Amine Sweetening Unit Emissions Inventory Section 07 - Initial and Periodic Sampling and Testing Requirements Samplin Stream Has source provided a site -specific sample within the last year? Is Periodic Sampling Needed? Is Initial Sampling Needed? Composition? Heat Content? Conclusion Inlet (Sour) Gas r; , Yes Yes Yes No Periodic and initial sampling is required for gas composition. Still Vent Waste Gas lies Yes Yes Yes Periodic and initial sampling is required for gas composition and heat content. Flash Tank Waste Gas '!o No No No No sampling is required Supplemental Fuel to Thermal Oxidizer 'es Yes N/A Yes Periodic and initial sampling is required for gas heat content only Supplemental Fuel to Not applicable t'sv 'io No N/A No No sampling is required Testin Still Vent Control Control Device Is this an enclosed combustor or thermal oxidizer? (Can this control device be tested?) Requested Control % Requested Minimum Combustion Chamber Temperature Thermal oxidizer with requested minimum combustion chamber temp below 1400 F? Has a control percentage greater than 95% been requested for a testable combustion device? Conclusion Primary Control Thermal Oxidizer 98'5 . .. - This Thermal Oxidizer must be stack tested to determine its control efficiency at the requested minimum chamber temperature of N/A Secondary Control Not applicable N/A No No stack testing is required Flash Tank Control Primary Control dosed -loop system No 10O% N/A No No No stack testing is required Secondary Control Not applicable No . , N/A No No _ No stack testing is required Section 08 - Technical Analysis Notes Secondary emissions for all amine unit still vents counted on Allis Point0O1 (AMINE 1). Source claims that the inlet stream to Amine2 does not contain H2S. Testing should back this up, but I am removing H2S per source claim. tam requiring semi-annual testing of the waste gas stream. My priority is monthly testing for the largest amine unit, and given that the operator has accepted an individual meter on each unit, I believe this is proportional. Waste gas metering shall be summed on a monthly basis. There was a small discrepancy with waste gas throughput claculated by source, but source indicated that since my throughput was higher, they will accept 658.7 rather than 658.4 mmscf/yr of waste gas. .. .. w . , < < x .V%:.U'.W vu..?JS% - x >i.tuw:00..1X .. fxS ).0 • . nXw X%..X C.YSx .fx. %FQ Y.X •[..Y. xJ..,%. Y./.S. i. .SF .. \nx%:X+.Y.Y.XX xx. f% R%.. ..K ).%. WX%x .w( T..(<S A 4 . % K_:t. T n. c nR::... 1 nnL 1 n �i ILr.AAII I.R. Nwi CM.VNA+1%il pf NI,:: .. g 1 .. .2,( ,f .. rx�. ')'. J' � � ' � � o. ..x. v .Y'i .ry F. �L Ic • .xSz zcQ/ t. Y »X' ii K8:(X]GCF.i xsJLu lc�M1 is .. :'. Y.:U : X'..: n.S Y..:> YBr. iJb"� O'% .AhY.k X(:. R� � -X �.Xxx' fiS%'n'x%HX%:2YSa:fY. /..C_I`Jl' %'+f%>. < %/Y>iFJ K3X ). "'I:YF..i]f 'R.. -l. r.•.[% SLh. YA`: ]: 1{inA.11\.111 P..RAtttii2�11K.�].1A%:C:M1..R%R36SUT:C%CLS%XXJ.n%%F.YLW. %.U.Y.�\�f Y. .<]XY. .%n..Y.:4 %x X..%n.i `f '[3� i'.k. Y R2 X _<. %Y .d �$MC %Y.K'rLa'% .<p. 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XI "X<X>:k%%{C'.�j.:%Y%%'k%%F%X%%f0XJ%ix%xkD[.C.::I:C.L fY x]:Y%R: :: iY n..lL:':L.fK%T• •%>Yk ��tn>f�':gx•vA�ak%2,x.p%:.i<0.}�.P.al'%JUIT..XFXXY.SyX Y.XkS V..%.'fY.Y.>.>%1U:x"%%:O.£: Y.YY.%Y. ]]Y.%Y.:�>:xYY:.v�.iQ u.k<ilY.% x2ie:.]x..e,+.�.'- r, x. xxv%n 'wxkn: x» .t u2vxofa— •s # � yfRSk 1 j .. •4]�'. b ...^' Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 002 Process* 01 SCC Code Pollutant PM10 PM2.S SOx H25 NOx VOC CO Benzene Toluene Ethylbenzene Xylene n -Hexane 224 TMP Methanol Uncontrolled Emissions Factor Control % 0.003 0.0 0.003 0.0 0.000 0.0 0.000 #DIV/0! 0.033 0.0 25.6 99.6 0.028 0.0 2.122 '^.1 0.531 98.I 0.004 98.1 0.020 98.1 0.292 99.8 0.002 99.9 0.000 uDIV/0! Units lb/MMscf lb/MMscf Ib/MMscf lb/MMscf lb/MMscf Ib/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf Amine Sweetening Unit Regulatory Analysis Worksheet Colorado Regulation 3 Parts A and B - APEN and Permit Requirements Source is in the Attainment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Are total facility uncontrolled VOC emissions greater than S TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.3)? Source requires a permit NON -ATTAINMENT 1 Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.2)? You have indicated that source is in the Attainment Area NSPS Analysis 1. Is the sweetening unit located at an onshore natural gas processing plant that processes natural gas produced from either onshore or offshore wells? Yes Source is subject to NSPS - Continue to determine applicable sections 40 CFR, Part 60, Subpart LLL, Standards of Performance for SO2 Emissions from Onshore Natural Gas Processing 1. Did construction or modification (see definitions 40 CFR 60.2) of the sweetening unit commence after January 20, 1984 and on or before August 23, 2011 (60.640(d))? 2. Does facility have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) (60.640(b))? 3. You have indicated that this facility is not subject to NSPS LLL. Subpart A, General Provisions §60.642 - Standards for sulfur dioxide §60.646 - Monitoring of emissions and operations §60.647 - Recordkeeping and reporting requirements 40 CFR, Part 60, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution 1. Did construction, modification or reconstruction (see definitions 40 CFR 60.2) of the sweetening unit commence after August 23, 2011 and on or before September 18, 2015? 2. Does facility have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) (60.5365(g)(3))? You have indicated that this facility is not subject to NSPS OOOO. Subpart A, General Provisions per §60.5425 Table 3 §60.5405 - Standards for sulfur dioxide §60.5407 - Monitoring of emissions and operations § 60.5423 - Notification, Recordkeeping and reporting requirements 40 CFR, Part 60, Subpart OOOOa, Standards of Performance for Crude Oil and Natural Gas Facilities 1. Did construction, modification or reconstruction (see definitions 40 CFR 60.2) of the sweetening unit commence after September 18, 2015? 2. Does facility have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) (60.5365a(g)(3))? Facility is subject to NSPS 0000a - Recordkeeping and Reporting Requirements per 60.5423a(c) Subpart A, General Provisions per §60.5425a Table 3 §60.5405a - Standards for sulfur dioxide Do Not Apply §60.5407a - Monitoring of emissions and operations Do Not Apply §60.5423a(c) - Recordkeeping and reporting requirements Colorado Regulation 3 Parts B, Section III.D.2.a - RACT Site is in attainment and not subject to RACT Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations, and Air Quality Control Commission regulations. This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law, regulation. or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act„ its implementing regulations. and Air Quality Control Commission regulations. the language of the statute or regulation will control. The use of non -mandatory language such as "recommend," "may," "should, " and "can, " is intended to describe APCD interpretations and recommendations. Mandatory terminology such as "must" and "required" are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations. but this document does not establish legally binding requirements in and of itself. Amine Sweetening Unit Emissions Inventory 003 Amine Unit Facility AIRs ID: .123 County *020 Plant 003 Po in t Section 02 - Equipment Description Details Amine Unit Information Amine Unit Type: Make: Model: Serial Number: Design Capacity: Recirculation Pump Information Number of Pumps Make: Model: Design/Max Recirculation Rate: Amine Unit Equipment Flash Tank Regenerator Heat Source AIRS ID Amine Unit Equipment Description Emission Control Device Description: .:'i1tw`�.ii'i �tKtff fifty!al!R-iti[�1�.�Q�i`ktvtngiwv'.'ircm 1mv:-rs?6vn T90 Tao BD 20 2 Tito T210 100 'FfXdfT.E'at:fi+i1 a 'tik^.'hX'isk 013 MMscf/day gallons/minute , flash tank, and amine regeneration heat source from HTR-7 (AIRS Point 013) APEN exempt One (1) Methytdiethanolamine (MDEA) natural gas sweetening unit (Make: TBD, Model: TBD, Serial Number: TBD) with a design capacity of 20 MMscf per day. This emissions unit is equipped with 2 (Make: TBD, Model: TBD) amine pump with a design capacity of 100 gallons per minute. This natural gas sweetening unit is equipped with a still vent flash tank, and amine regeneration heat source (MRS Point 013). Emissions from the still vent are routed to the Thermal Oxidizer. Emissions from the flash tank are muted directly to the closed -loop system. Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Amine Unit Still Vent and Flash Tank (if present) Requested Permit Limit Throughput = .34`0.0 MMscf per year MMscf per year Requested Monthly Throughput = 620 MMscf per month Potential to Emit (PTE) Throughput = Secondary Emissions - Combustion Device(s) for Air Pollution Control Still Vent Control Primary control device: Primary control device operation: Secondary control device: Secondary control device operation: Still Vent Gas Heating Value: Still Vent Waste Gas Vent Rate: Flash tank Control Primary control device: Primary control device operation: Secondary control device: Secondary control device operation: Flash Tank Gas Heating Value Flash Tank Waste Gas Vent Rate: 7,300 8760 hr/yr hr/yr 18 Btu/scf 497E-01 MMSCFD 1 60 hr/yr hr/yr Btu/scf MMSCFD 31i',:i Control Efficiency % Control Efficiency% 100% Control Efficiency % Requested TO Temp Requested TO Temp Requested TO Temp Control Efficiency % Requested TO Temp Degrees F Degrees F Degrees F Degrees F Waste Gas Combusted: Still Vent Primary Control: 131 5 MMscf/yr Still Vent Secondary Control: an MMscf/yr Waste Gas Combusted: Flash Tank Primary Control: Flash Tank Secondary Control: 0.i) MMscf/yr �..r MMscf/yr Primary Control Device Pilot : uei Use tote: Assist Gas Rate: Pilot Fuel Gas Heating Value: Assist Gas Heating Value: Pilot & Assist Gas Heating Value: Thermal Oxidizer scfh scfh Btu/scf Btu/scf u.0 Btu/scf 0.0 MMscf/yr 0.0 MMscf/yr Secondary Control Device /lot Fuel Disc N�:c Assist Gas Rate: Pilot Fuel Gas Heating Value: Assist Gas Heating Value: Pilot & Assist Gas Heating Value: riot applicable scfh scfh Btu/scf Btu/scf U 0 Btu/scf 0.0 MMscf/yr 0.t) MMscf/yr How Will Source Demonstrate Compliance? Requested Permit Process Limits Process Parameter Inlet Sour Gas Throughput Still Vent Waste Gas to Thermal Oxidizer Annual Limit (MMscf/yr) 7300 1845 Flash Tank Waste Gas to closed -loop system f 0 Combustion of Pilot and Su lemental Fuel at Thermal Oxidizer Lean Amine Recirculation Rate Section 04 - Emissions Factors & Methodologies Amine Unit Source estimated emissions in Pr-omax based an a proifld inlet gas composition Input Parameters Inlet Gas Pressure Inlet Gas Temperature Requested Lean Amine Recirculation Rate lean Amine Weight Flash Tank Pressure Flash Tank Temperature Inlet H2S Concentration Inlet VOC Concentration woo 59.9 100 50.1 65 108 CL00o1 25.03 Monthly Limit (31 day) (MMscf/month) 0 0 0 psig °F Rpm psia °F wt% wt % Gallons Per Minute Metered Parameters Notes on Meted Amine Sweetening Unit Emissions Inventory STILE VENT Control Scenano Primary Secondary Pollutant Uncontrolled (b/hr) Controlled (lb/hr) Controlled (lb/hr) VOC 5.935 0.118709492 0 Benzene L7093 0.034185 0 Toluene 0.905499 0.01810998 0 Ethylbenzene 0.118628 0.00237256 0 Xylenes 0.2644506 0.005289012 0 n -Hexane 0.0145283 0.000290566 0 224-TMP 142029E-06 2.84058E-08 0 H,S 0.0727623 0.001455246 0 Methanol 0 0 0 FLASH TANK Control Scenario Primary 1 Secondary Pollutant Uncontrolled (lb/hr) Controlled (lb/hr) Controlled (lb/hr) VOC I4 862 0 0 Benzene 0.0597 0 0 Toluene 0.0223072 0 0 Ethybenzene 0.0024969 0 0 Xylenes 0.00358507 0 0 n -Hexane 0.0683582 0 0 224 -IMP L42373E-OS 0 0 H,S 0.000101277 0 0 Methanol 0 0 0 SOx Emission Calculations: Molecular Weight of SO, 64.066 Ib/Ibmol Molecular Weight of HA 34.08088 Ib/bmol 5Ox Emissions (Stitl Vent) 0.599097267 tpy SOx Emissions (Flash Tank) 0 tpy Requested Buffer (X): 0.012258885 Emission Factors Amine Unit Pollutant Uncontrolled Controlled (lb/MMscf) (lb/MMscf) Emission Factor Source (Sour Gas Throughput) (Sour Gas Throughput) VOC 24.96 0.14 ?. oAt: Benzene 2.12269224 0.041022 Pro'.tax Toluene 1.11336744 0.021731976 PraMax Ethylbenzene 0.14535228 0.002847072 Provb;4 Xylene 0.321642804 0.006346814 PtoM+ u n -Hexane 0.0994638 0.000348679 ProMax 224 TMP 1.87891E-05 3.4087E-08 Prot11as H;S 0.087436292 0.001746295 Prax Methanol t PrvSs',.a,t Pollutant Still Vent Primary Control Device Uncontrolled Uncontrolled (lb/MMBtu) (Ib/MMscf) Emission Factor Source (Waste Heat Combusted) (Waste Gas Combusted) PM 10 0.0075 0.1.317 AP -42 tame 1.410141.11/krttt2-Sf PM2.5 0.0075 0.1317 AP4L.Tab+e I.4-? P or..0(9M.2.5) SOx 6.6016 NOx 0. "*?R0 1.7316 Manufacturer CO '.:G -.,..S.'fl 1.4489 Manufacturer Pollutant Still Vent Secondary Control Device Uncontrolled Uncontrolled (Ib/MMBtu) (lb/MMscf) Emission Factor Source (Waste Heat Combusted) (Waste Gas Combusted) PM 10 0.0000 PM2.5 0.0000 SOx 0.0000 NOx 0.0000 CO 0.0000 Pollutant Flash Tank Primary Control Device Uncontrolled Uncontrolled (Ib/MMBtu) (lb/MMscf) Ems;:on Face_ . - (Waste Heat Combusted) (Waste Gas Combusted) PM 10 0.0000 PM2.5 0.0000 SOx 0.0000 NOx 0.0000 CO 0.0000 Pollutant Flash Tank Secondary Control Device Emission Factor Si.:rre Uncontrolled Uncontrolled (Ib/MMBtu) (1b/MMsef) (Waste Heat Combusted) (Waste Gas Combusted) P M 10 U. VUL.ti PM2.5 0.0000 0.0000 0.0000 SOx NOx CO 0.0000 Supplemental Fuel to Still Vent Primary Control Emission Factor Source Uncontrolled Uncontrolled Pollutant (Ib/MMBtu) (lb/ft./Mug (Waste Heat Combusted) (Waste Gas Combusted) PM 10 0.0000 PM2.5 0.0008 SOx 0.C NOx 0.0uw CO 0.0000 VG( !1.0000 Supplemental Fuel to Still Vent Secondary Control Emission Factor SC _r'--. Uncontrolled Uncontrolled Pollutant (Ib/MMBtu) (lb/MMsct) (Waste Heat Combusted) (Waste Gas Combusted) P M10 0.0000 PM'.5 0.0000 sox 0.0000 NOx 0.0000 co 0.0000 VOC _ 0.0000 _ C3 C4 CS C6 C7 C8 C9 C10 Total VOC 2.11 0.64 0.1248499 0.06 0.01 3.00 6.65E-06 1.20E-06 5.935 11.23 288 0.53 0 11 0.02 0.09 000 0.00 14.862 Amine Sweetening Unit Emissions Inventory Section OS - Emissions Inventory Requested Permit Monthly Emission Limits Process Parameter Pollutant PM10 (lbs/month) PM2.5 (lbs/month) SOx (lbs/month) H2S (lbs/month) NOx (lbs/month) CO (lbs/month) VOC (lbs/month) Still Vent Waste Gas to Thermal Oxidizer 2 2 10' 1 27 22 83 Supplemental Fuel Sent to Thermal Oxidizer ( 0 0 0 0 Still Vent Waste Gas to Thermal Oxidizer and Su • • emental Fuel Sent to Thermal Oxidizer 2 " ;t 1 27 ,, 22 SS 1 0 0 Flash Tank Waste Gas to closed -loo • • in 0 0 0 0 0 0 0 Requested Permit Annual Emission Um Process Parameter ks Pollutant Still Vent Waste Gas to Thermal Oxidizer Su lemental Fuel Sent to Thermal Oxidizer PM10 (tons/year) PM2.5 (tons/year) SOx (tons/year) 1125 (tons/year) 0.5 V Still Vent Waste Gas to Thermal Oxidizer and Su emental Fuel Sent to Thermal Oxidizer Flash Tank Waste Gas to closed400p system 0 0 NOx (tons/year) 0 0.6 0 0 U CO (tons/year) iI 0 VOC (tons/year) 0 0 0 0 I 0 I 0 I 0 1 0 I Total Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 SOx H25 NOx CO VOC 0.0 0.0 0.0 0.0 0.0 2 0.0 0.0 0.0 0.0 0.0 2 0.6 0.6 0.6 0.6 0.6 102 0.3 0.3 0.0 0.3 0.01 1 0.2 0.2 0.2 0.2 0.2 27 0.1 0.1 0.1 0.1 0.1 22 91.1 91.1 0.5 91.1 0.5 88 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene Toluene Et ylbenzene Xylene n -Hexane 224 TMP HAS Methanol 1S496 15496 299 15496 299 8128 8128 159 8128 159 1051 1061 21 1061 21 2 - 2348 46 2348 46 Teo 726 3 726 3 0 0 0 0 0 638 638 13 638 13 0 _ 0 0 0 0 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit 40 CFR, Part 60, Subpart LLL You have indicated that this facility is not subject to NSPS LLL 40 CFR, Part 60, Subpart OOOO You have indicated that this facility is not subject to NSPS OOOO. 40CFR, Part 60, Subpart O000a Facility is subject to NSPS 000Oa - Recordkeeping and Reporting Requirement per 60.5423a(c) (See regulatory applicability worksheet for detailed analysis) Amine Sweetening Unit Emissions Inventory Section 07 - Initial and Periodic Sampling and Testing Requirements Sampling Stream Has source provided a site -specific sample within the last year? Is Periodic Sampling Needed? Is Initial Sampling Needed? Composition? Heat Content? Conclusion Inlet (Sour) Gas Yes r' , Yes No Please indicate whether a site -specific sample exists Still Vent Waste Gas es No Yes Yes Please indicate whether a site -specific sample exists Flash Tank Waste Gas No Nn No No Please indicate whether a site -specific sample exists Supplemental Fuel to Thermal Oxidizer No No N/A No Please indicate whether a site -specific sample exists Supplemental Fuel to Not applicable rlo No N/A No Please indicate whether a site -specific sample exists Testing Still Vent Control Control Device Is this an enclosed combustor or thermal oxidizer? (Can this control device be tested?) Requested Control % Requested Minimum Combustion Chamber Temperature Thermal oxidizer with requested minimum combustion chamber temp below 1400 F? Has a control percentage greater than 95% been requested (or a testable combustion device? Conclusion Primary Control Thermal Oxidizer 98's .. Yes This Thermal Oxidizer must be stack tested to determine its control efficiency at the requested minimum chamber temperature of N/A Secondary Control Not applicable No 0> No No stack testing is required Flash Tank Control Primary Control closed -loop system Nu 100% N/A No No No stack testing is required Secondary Control Not applicable No 0% N/A No No No stack testing is required Section 03 - Technical Analysis Notes Secondary emissions for all amine unit still vents counted on AIRS Point 001 (AMINE 1) Sr' -n n.""Eri '"97,7.1Cn.,...,...,—i. mexxarmX Yxxx xx*n ..� xsxDtxxx.exxMX l,S.sXxH :.x.e....a �xx,t s.eXxx e t y� Z xi x %:ff: -:s ...ux %x x,'tR�a �xi% x. AxnvnF QflRx xrritrxxT YYT-1 Y x YY •�YYx X" tl Zvnxxs x � xxnxY mx [�xu x xmex r a xxrt�x� � n2.-"<x§YC,1-^!. xxrxx%xXRx:L% �.t%xwx . YMA'd%XfYNL»X�X>v%iG%xXAi: �iytY.,Y %N[ >i.<0(N-f% X%x .tXn�¢¢e�%% is,. tKs '±`` iTirt2i S K RNX NX. f :fSs i3f xX%3 R f y YKY t<%Y9�'(Y� �<xxJUL�<�•c�xJ�<Y.,x3 xX�� I am requiring annual testing of the waste gas stream. My priority is monthly testing for the largest amine unit, and given that the operator has accepted an individual meter on each unit, I believe this is proportional. Waste gas metering shall be summed on a monthly basis. Section 09 - Inventory SCC Coding and Emissions Factors Al RS Point # 003 Process # 01 SCC Code Pollutant PM10 PM2.5 SOx H25 NOx VOC CO Benzene Toluene Ethylbenzene Xylene n -Hexane 224 IMP Methanol Uncontrolled Emissions Factor Control % .0.003 0.0 0.003 0.0 0.164 0.0 0.087 98.0 0.043 0.0 25.0 99.4 0.036 0.0 2.123 98.1 L113 98.0 0.145 93.0 0.322 98.0 0.099 99.6 0.000 99.8 0.000 #DIV/0! Units lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf Ib/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf Amine Sweetening Unit Regulatory Analysis Worksheet Colorado Regulation 3 Parts A and B - APEN and Permit Requirements Source is in the Attainment Ares ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.3)? Source requires a permit NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.2)? You have indicated that source is in the Attainment Area Yes NSPS Analysis 1. Is the sweetening unit located at an onshore natural gas processing plant that processes natural gas produced from either onshore or offshore wells? Source is subject to NSPS - Continue to determine applicable sections 40 CFR, Part 60, Subpart LLL, Standards of Performance for SO2 Emissions from Onshore Natural Gas Processing 1. 2. 3. Did construction or modification (see definitions 40 CFR 60.2) of the sweetening unit commence after January 20, 1984 and on or before August 23, 2011 (60.640(d))? Does facility have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) (60.640(b))? You have indicated that this facility is not subject to NSPS LLL. Subpart A, General Provisions §60.642 - Standards for sulfur dioxide §60.646 - Monitoring of emissions and operations §60.647 - Recordkeeping and reporting requirements 40 CFR, Part 60, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution 1. Did construction, modification or reconstruction (see definitions 40 CFR 60.2) of the sweetening unit commence after August 23, 2011 and on or before September 18, 2015? 2. Does facility have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) (60.5365(g)(3))? You have indicated that this facility is not subject to NSPS OOOO Subpart A, General Provisions per §60.5425 Table 3 §60.5405 - Standards for sulfur dioxide §60.5407 - Monitoring of emissions and operations § 60.5423 - Notification, Recordkeeping and reporting requirements 40 CFR, Part 60, Subpart OOOOa, Standards of Performance for Crude Oil and Natural Gas Facilities 1. Did construction, modification or reconstruction (see definitions 40 CFR 60.2) of the sweetening unit commence after September 18, 2015? 2. Does facility have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) (60.5365a(g)(3))? Facility is subject to i`ISPS 0000a - Recordkeeping and Reporting Requirements per 60.5423a(c) Subpart A, General Provisions per §60.5425a Table 3 §60.5405a - Standards for sulfur dioxide Do Not Apply §60.5407a - Monitoring of emissions and operations Do Not Apply §60.5423a(c) - Recordkeeping and reporting requirements Colorado Regulation 3 Parts BSection III.D.2.a - RACT Site is in attainment and not subject to RACT Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations. and Air Quality Control Commission regulations. This document is not a rule or regulation. and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act„ its implementing regulations. and Air Quality Control Commission regulations. the language of the statute or regulation will control. The use of non -mandatory language such as "recommend," 'may,- "should, " and -can," is intended to describe APCD interpretations and recommendations. Mandatory terminology such as "must" and "required- are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself. Glycol Dehydrator Emissions Inventory 004 Dehydrator Facility AIRs ID: 123 County A020 Plant 004-005 Point Section 02 - Equipment Description Details Dehydrator Information Dehydrator Type: Make: Model: Serial Number: Design Capacity: Recirculation Pump Information Number of Pumps Pump Type Make: Model: Design/Max Recirculation Rate: Dehydrator Equipment Flash Tank Reboiler Burner Stripping Gas Dehydrator Equipment Description Emission Control Device Description: 1 tic TBD TBD 335 MMscf/day gallons/minute , flash tank, and reboiler burner One (1) Triethylene glycol (TEG) natural gas dehydration unit (Make: TBD, Model: TBD, Serial Number: TBD) with a design capacity of 30 MMscf per day. This emissions unit is equipped with 1 (Make: TBD, Model: TBD) electric driven glycol pump with a design capacity of 3.75 gallons per minute. This dehydration unit is equipped with a still vent, flash tank, and reboiler burner. Emissions from the still vent are routed to the Enclosed Flare. Emissions from the flash tank are routed directly to the closed -loop system. Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Dehydrator Still Vent and Flash Tank (if present) Requested Permit Limit Throughput = 30.0 MMscf per year Requested Monthly Throughput = 2.55 MMscf per month Potential to Emit (PIE) Throughput = 10,950 MMscf per year Secondary Emissions - Combustion Device(s) for Air Pollution Control Still Vent Control Condenser: Condenser emission reduction claimed: Primary control device: Primary control device operation: Secondary control device: Secondary control device operation: Still Vent Gas Heating Value: Still Vent Waste Gas Vent Rate: Flash tank Control Primary control device: Primary control device operation: Secondary control device: Secondary control device operation: Flash Tank Gas Heating Value Flash Tank Waste Gas Vent Rate: Requested Condenser Outlet Temperature: 9:r% Control Efficiency % Requested TO Temp Control Efficiency % hr/yr 219 Btu/scf 2.GSE+03 scfh hr/yr Btu/scf scfh 100%. Control Efficiency % Control Efficiency % 120 Degrees F Degrees F Section 04 - Emissions Factors & Methodologies Dehydrator 30 MMSCFD TEG dehydrator with condenser and reboiler. Flash tank is recycled 100%. Glycmic was used to model emissions from a modeled inlet composition. Input Parameters Inlet Gas Pressure Inlet Gas Temperature Requested Glycol Recirculate Rate 1100 120 3.75 psig deg F gpm STILL VENT Control Scenario Primary Secondary Pollutant Uncontrolled (lb/hr) Controlled (lb/hr) Controlled (lb/hr) VOC 18.9638 0.94819 0 Benzene 0.7098 0.03549 0 Toluene 0.0373 0.001865 0 Ethylbenzene 0.0008 0.00004 0 Xylenes 0.0005 0.000025 0 n -Hexane 0.3704 0.01852 0 224-TMP 0.0006 0.00003 0 FLASH TANK Control Scenario Primary Secondary Pollutant Uncontrolled (lb/hr) Controlled (lb/hr) Controlled (lb/hr) VOC 0 0 Benzene 0 0 Toluene 0 0 Ethylbenzene 0 0 Xylenes 0 0 n -Hexane 0 0 224 -TM P 0 0 Dry Gas Throughput: Still Vent Primary Control: 30.0 MMscf/yr Still Vent Secondary Control: 0.0 MMscf/yr Waste Gas Combusted: Still Vent Primary Control: 23.6 MMscf/yr Still Vent Secondary Control: 0.0 MMscf/yr Dry Gas Throughput: Flash Tank Primary Control: 30.0 MMscf/yr Flash Tank Secondary Control: 0.0 MMscf/yr Waste Gas Combusted: Flash Tank Primary Control: 0.0 MMscf/yr Flash Tank Secondary Control: 0.0 MMscf/yr Primary Control Device Pict Fuei use Assist Gas Rate: 33 scfh scfh Pilot Fuel Gas 1030 Btu/scf Assist Gas Heating Value: Btu/scf Pilot & Assist C 1030.0 Btu/scf Glycol Dehydrator Emissions Inventory Emission Factors Glycol Dehydrator Pollutant Uncontrolled Controlled (lb/MMscf) (lb/MMscf) Emission Factor Source (Dry Gas Throughput) (Dry Gas Throughput) VOC 5537.43 276.87 Benzene 207.2616 10.36308 Toluene 10.8916 0.54458 Ethylbenzene 0.2336 0.01168 Xylene 0.146 0.0073 n -Hexane 108.1568 5.40784 224 TMP 0.1752 0.00876 Pollutant Still Vent Primary Control Device Uncontrolled Uncontrolled (lb/MMBtu) (lb/MMscf) Emission Factor Source (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0075 1.6331 AP -42 Table 1.4-r', (PM4 :W/PM.2, 5) PM2.5 0.0075 1.6331 C..1,42 Tabi 1.47 419/r.' - :' AP -42 Table `j-4-2 ""`'" :^-apt r 13.5 tnri, SOx 0.0006 0.1289 NOx 0.0680 14.9042 CO 0.3100 67.9458 a Pollutant Still Vent Secondary Control Device Emission Factor Source Uncontrolled Uncontrolled (Ib/MMBtu) (lb/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) 0.0000 ft:iPM10 p) c. :(*gi�{b,�o>v t 1. d x'uc�≥ dab. r p�� o'oi.Z'o etL,%oo >.--' PM2.5 0.0000 SOX 0.0000 NOx 0.0000 CO 0.0000 Flash Tank Primary Control Device Emission Factor Source Uncontrolled Uncontrolled Pollutant (Ib/MMBtu) (lb/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0000 PM2.5 0.0000 SOx 0.0000 NOx 0.0000 CO 0.0000 Flash Tank Secondary Control Device Emission Factor Source Uncontrolled Uncontrolled Pollutant (Ib/MM Btu) (lb/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0000 :. :..: ... ., PM2.5 0.0000 SOx 0.0000 NOx 0.0000 CO 0.0000 Section 05 - Emissions Inventory Did operator request a buffer? Requested Buffer (%): Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 SOx NOx CO VOC 0.0 0.0 0.0 0.0 0.0 3 0.0 0.0 0.0 0.0 0.0 3 0.0 0.0 0.0 0.0 0.0 0 0.2 0.2 0.2 0.2 0.2 34 0.9 0.9 0.9 0.9 0.9 156 83.1 83.1 4.2 83.1 4.2 705 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene Toluene Ethylbenzene Xylene n -Hexane 6218 6218 311 6218 311 327 327 16 327 16 7 7 0 7 0 4 4 0 4 0 3245 3245 162 3245 162 224 TMP 5 5 0 5 0 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit Regulation 7, Section XVII.B,D Dehydrator is subject to Regulation 7, Section XVII, B, D.3 Regulation 7, Section XVII.B.2.e The control device for this dehydrator is not subject to Regulation 7, Section XVII.B.2.e Regulation 7, Section XII.H Dehydrator is not subject to Regulation 7, Section XII.H Regulation 8, Part E, MACT Subpart HH (Area) The dehy unit meets the benzene exemption Regulation 8, Part E, MACT Subpart HH (Major) You have indicated that this facility is not subject to Major Source requirements of MACT HH. Regulation 8, Part E, MACT Subpart HHH You have indicated that this facility is not subject to MACT HHH. (See regulatory applicability worksheet for detailed analysis) Glycol Dehydrator Emissions Inventory Section 07 - Initial and Periodic Sampling and Testing Requirements Was the extended wet gas sample used in the GlyCalc model/Process model site -specific and collected within a year of application submittal? ti If no, the permit will contain an "Initial Compliance" testing requirement to demonstrate compliance with emission limits Does the company request a control device efficiency greater than 95% for a flare or combustion device? it If yes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling If the company has requested a control device efficiency greater than 95%, is a thermal oxidizer or regenerative thermal oxidizer being used to achieve it? If yes, the permit will contain a condition specifying the minimum combustion chamber temperature for the thermal oxidizer Is the company using a thermal oxidizer AND requesting a minimum ccmbustion chamber temperature lower than 1,400 degrees F? f- - No If yes, the permit will contain an "Initial Compliance" testing requirement AND a permit condition specifying the minimum combustion chamber temperature for the thermal oxidizer. Section 08 - Technical Analysis Notes Because source is using a modeled gas composition as input to G'ycalc, testing of inlet gas as well as waste gas will be required. Dehydrator's 004 and 005 are presented as identical in operation. Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 004 - 005 Process # 01 SCC Code re Uncontrolled Pollutant Emissions Factor Control % Units PM10 1.283 0.0 lb/MMscf PM2.5 1.283 0.0 lb/MMscf SOx 0.101 0.0 lb/MMscf NOx 13.404 0.0 Ib/MMscf VOC 5537.4 95.0 lb/MMscf CO 61.109 0.0 lb/MMscf Benzene 207.262 95.0 lb/MMscf Toluene 10.892 95.0 lb/MMscf Ethylbenzene 0.234 95.0 lb/MMscf Xylene 0.146 95.0 lb/MMscf n -Hexane 108.157 95.0 Ib/MMscf 224 TMP 0.175 95.0 lb/MMscf Dehydrator Regulatory Analysis Worksheet Colorado Regulation 3 Parts A and B - APEN and Permit Requirements Source is in the Attainment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.3)? Source requires a permit NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutarts from this individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOx greater than S TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.2)? You have indicated that source is in the Attainment Area Colorado Regulation 7, Section XII.H 1. Is this glycol natural gas dehydrator located in the 8 -hr ozone control area or any ozone non -attainment area or attainment/maintenance area (Reg 7, Section XII.H.1 and 2)? 2. Is this glycol natural gas dehydrator located at an oil and gas exploration and production operation", natural gas compressor station, natural gas drip station or gas -processing plant (Reg 7 Section 3. Is the sum of actual uncontrolled emissions of VOC from any single dehydrator or group of dehydrators at a single stationary source equal to or greater than 15 tpy (Reg 7, Section XII.H.3.b)? 4. Are actual uncontrolled emissions of VOC from the individual glycol natural gas dehydrator equal to or greater than 1 tpy (Reg 7, Section XII.H.3.a)? Dehydrator is not subject to Regulation 7, Section XII.H No Yes Section XII.H — Emission Reductions from glycol natural gas dehydrators MACT Analysis 1. Is the dehydrator located at an oil and natural gas production facility that meets either of the following criteria: a. A facility that processes, upgrades or stores hydrocarbon liquids' (63.760(a)(2)); OR A facility that processes, upgrades or stores natural gas prior to the point at which natural gas enters the natural gas transmission and storage source category or is delivered to a final b. end user2 (63.760(a)(3))? 2. Is the dehydrator located at a facility that is a major source for HAPs? Yes Go to MACT HH Area Source Requirernert section to determine MACT HH applicability 40 CFR, Part 63, Subpart MACT HH, Oil and Gas Production Facilities Area Source Requirements 1. Is the dehydrator a triethylene glycol (TEG) dehydration unit (63.760(b)(2))? Exemptions 2a. Is the actual annual average flowrate of natural gas to the glycol dehydration unit less than 3.001747 MMscf per day (63.764(e)(1)(i)? 2b. Are actual annual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere less than 1,984.2 lb/yr (63.764(e)(1)(ii)? 3. Is the unit located inside of a UA plus offset and UC boundary area? The dehy unit meets the benzene exemption Subpart A, General provisions per §63.764 (a) Table 2 §63.765 - Emissions Control Standards Do Not Apply §63.773 - Monitoring Standards Do Not Apply §63.774 - Record keeping §63.775 - Reporting Standards Do Not Apply Major Source Requirements 1. Does the facility have a facility -wide actual annual average natural gas throughput less than 0.65 MMscf/day AND a facility -wide actual annual average hydrocarbon liquid throughput less than 249.7 Small or Large Dehy Determination 2a. Is the actual annual average flowrate of natural gas to the glycol dehydration unit less than 3.001747 MMscf per day (63.761)? 2b. Are actual annual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere less than 1,984.2 lb/yr (63.761)? Small Dehy Requirements 3. Did construction of the small glycol dehydration unit commence on or before August 23, 2011 (63.760(b)(1)(i)(B) and (C )? 4. For this small dehy, is a control device required to meet the BTEX emission limit given by the applicable equation? Yes 'Sled You have indicated that this facility is not subject to Major Source requirements of MACT HH. Subpart A, General provisions per §63.764 (a) Table 2 §63.765 - Emissions Control Standards §63.773 - Monitoring §63.774 - Record keeping §63.775 - Reporting 40 CFR, Part 63, Subpart MACT HHH, Natural Gas Transmission and Storage Facilities 1 Is the facility wide actual annual average natural gas throughput less than 0.9994051 MMscf/day and glycol dehydrators the only HAP emission source (63.1270(f))? Small or Large Dehy Determination 2a. Is the actual annual average flowrate of natural gas to the glycol dehydration unit less than 9.994051 MMscf per day (63.1270(b)(2))? 2b. Are actual annual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere less than 1,984.2 lb/yr (63.1270(b)(2))? Small Dehy Requirements 3. Did construction of the small glycol dehydration unit commence on or before August 23, 2011 (63.1270(b)(2) and (3) )? 4. For this small dehy, is a control device required to meet the BTEX emission limit (standard?) given by the applicable equation? i'Vare 1/4>A You have indicated that this facility is not subject to MACT HHH. Subpart A, General provisions per §63.1274 (a) Table 2 §63.1275 - Emissions Control Standards §63.1281 -Control Equipment Standards §63.1283 - Inspection and Monitoring §63.1284 - Record keeping §63.1285 - Reporting Colorado Regulation 7, Section XVII.D 1. Is the dehydrator subject to an emissions control requirement under MACT HH or HHH (Regulation 7, Section XVII.B.5)? 2. Is this dehydrator located at a transmission/storage facility? 3. Is this dehydrator located at an oil and gas exploration and production operation , natural gas compressor station or gas processing plant (Reg 7, Section XVII.D.3)? 4. Was this glycol natural gas dehydrator constructed before May 1, 2015 (Reg 7 Section XVII.D.4.b)? If constructed prior to May 1, 2015, are uncontrolled actual emissions from a single glycol natural gas dehydrator equal to or greater than 6 tons per year VOC or 2 tpy VOC if the 4a. dehydrator is located within 1,320 feet of a building unit or designated outside activity area (Reg 7, Section XVII.D.4.b)? 5. If constructed on or after May 1, 2015, are uncontrolled actual emissions from a single glycol natural gas dehydrator equal to or greater than 2 tpy VOC (Regulation 7, Section XVII.D.4.a)? Dehydrator is subject to Regulation 7, Section XVII, B, D.3 No No Yes Section XVII.B —General Provisions for Air Pollution Control Equipment and Prevention of Emissions Section XVII.D.3 - Emissions Reduction Provisions Alternative Emissions Control (Optional Section) 6. Is this glycol natural gas dehydrator controlled by a back-up or alternate combustion device (i.e., not the primary control device) that is not enclosed? The control device for this dehydrator is not subject to Regulation 7, Section XVII.B.2.e Section XVII.B.2.e —Alternative emissions control equipment Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations, and Air Quality Control Commission regulations. This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act,, its implementing regulations, and Air Quality Control Commission regulations, the language of the statute or regulation will control. The use of non -mandatory language such as "recommend," "may," "should," and "can, " is intended to describe APCD interpretations and recommendations. Mandatory terminology such as "must" and "required" are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself. Condensate Storage Tank(s) Emissions Inventory 006 Condensate Tank (Facility AIRs ID: County 006 Plant Point Section 02 - Equipment Description Details Detailed Emissions Unit Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: One (1) 400 BBL Emergency tank for off -spec stabilized condensate Enclosed Combustor Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Storage Tank(s) Actual Condensate Throughput = 9,125 Barrels (bbl) per year Actual Condensate Throughput While Emissions Controls Operating = 9,125 Barrels (bbl) per year Requested Permit Limit Throughput = 9,125 Barrels (bbl) per year Requested Monthly Throughput = 775 Barrels (bbl) per month Potential to Emit (PTE) Condensate Throughput Secondary Emissions - Combustion Device(s) Heat content of waste gas = Volume of waste gas emitted per BBL of liquids produced = 10,950 Barrels (bbl) per year 1906 12.64 Btu/scf scf/bbl Actual heat content of waste gas routed to combustion device = Requested heat content of waste gas routed to combustion device = Potential to Emit (PTE) heat content of waste gas routed to combustion device = Section 04 - Emissions Factors & Methodologies Will this storage tank emit flash emissions? 220 MMBTU per year 220 MMBTU per year 264 MMBTU per year Emission Factors Condensate Tank Pollutant Uncontrolled Controlled (lb/bbl) (Ib/bbl) Emission Factor Source (Condensate Throughput) (Condensate Throughput) VOC 2...4? 0.12 Slt t Sped{€. EPA ' "crNic,'S E.C.Vilbrkisitand E ec: '. Benzene 0.039 0.002 Site Specific EPA TANKS. E..Working arid Breas Toluene 0.017 0.001 Site Specific EPA TANKS E.F. Working and 8 ;: Site Sped c EPA TANKS Et:. . Working and P Ethylbenzene 0.002 0.000 Xylene 0.003 0.000 Site Specific. EPA IAN 'S E,E. Working and 8 n -Hexane 0.000 0.000 Site Specific EPA TANKS ELF. Working and fire,,: „:ite Specific EPA TANKS Er'. Working and 8' 224 TMP 0.000 0.000 Control Device Emission Factor Source Uncontrolled Uncontrolled Pollutant 4 (Ib/MMBtu) (Ib/bbl) (waste heat combusted) (Condensate Throughput) PM10 0.0075 0.0002 AP -.$2: i abie .1.4.2 iin0.l j'PM.2..S;: AP -42 Table 1.,4-2 (PM1O/PM.2,S' AP -42 Chapter 13.5 Industrial Flare, 4 • .:.:,, 1V'-4≥ Chapter 13.5 Inds stna! Flares (CO'= PM2.5 0.0075 0.0002 NOx 0.0680 0.0016 CO 0.3100 0.0075 Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) VOC PM10 PM2.5 NOx CO 13.=. 11.3 0.6 11.3 0.6 96 0.0 0.0 0.0 0.0 0.0 0 0.0 0.0 0.0 0.0 0.0 0 0.0 0.0 0.0 0.0 0.0 1 0.0 0.0 0.0 0.0 0.0 6 Hazardous Air Pollutants Potential to Emit Unccntrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene Toluene Ethylbenzene Xylene n -Hexane 224 TMP 425 354 18 354 18 182 152 8 152 8 24 20 1 20 1 34 28 1 28 1 0 0 0 0 0 2 2 0 2 0 Section 06 - Regulatory Summary Analysis 25 bbl/day 9125 bbl/yr ton/yr lb/yr VOC 11.26 Benzene 0.177 Toluene 0.0/6 Ethylbenzen 0.010 Xylene 0.014 n -Hexane 0.000 224 TMP 0.001 Regulation 3, Parts A, B Source requires a permit Regulation 7, Section XII.C, D, E, F Storage Tank is not subject to Regulation 7, Section XII.C-F Regulation 7, Section XII.G, C Storage Tank is not subject to Regulation 7, Section XII.G Regulation 7, Section XVII.B, C.1, C.3 Storage tank is subject to Regulation 7, Section XVII, B, C.1 & C.3 Regulation 7, Section XVII.C.2 Storage Tank is not subject to Regulation 7, Section XVII.C.2 Regulation 6, Part A, NSPS Subpart Kb Storage Tank is not subject to NSPS Kb Regulation 6, Part A, NSPS Subpart 0000 Storage Tank is not subject to NSPS 0000 Regulation 8, Part E, MACT Subpart HH Storage Tank is not subject to MACT HH (See regulatory applicability worksheet for detailed analysis) 22510 354 152 20 28 0 2 26 of 76 K:\PA\2019\19WE0081.CP1.xlsm Condensate Storage Tank(s) Emissions Inventory Section 07 - Initial and Periodic Sampling and Testing Requirements Does the company use the state default emissions factors to estimate emissions? No If yes, are the uncontrolled actual or requested emissions estimated to be greater than or equal to 80 tons VOC per year? No If yes, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor based on guidelines in PS Memo 05-01. Does the company use a site specific emissions factor to estimate emissions? If yes and if there are flash emissions, are the emissions factors based on a pressurized liquid sample drawn at the facility being permitted? This sample should be considered representative which generally means site -specific and collected within one year of the application received date. However, if the facility has not been modified (e.g., no new wells brought on-line), then it may be appropriate to use an older site -specific sample. Not applicable - stabilized tank If no, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor based on guidelines in PS Memo 05-01. Does the company request a control device efficiency greater than 95% for a flare or combustion device? No If yes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling Section 08 - Technical Analysis Notes Stabilized tank will require testing of RVP for self -certification Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 006 Process # 01. SCC Code Uncontrolled Emissions Pollutant Factor Control % Units PM10 0.00 0 lb/1,000 gallons condensate throughput PM2.5 0.00 0 Ib/1,000 gallons condensate throughput NOx 0.04 0 lb/1,000 gallons condensate throughput VOC 58.7 95 lb/1,000 gallons condensate throughput CO 0.18 0 lb/1,000 gallons condensate throughput Benzene 0.92 95 lb/1,000 gallons condensate throughput Toluene 0.40 95 lb/1,000 gallons condensate throughput Ethylbenzene 0.05 95 lb/1,000 gallons condensate throughput Xylene 0.07 95 lb/1,000 gallons condensate throughput n -Hexane 0.00 95 Ib/1,000 gallons condensate throughput 224 TMP 0.01 95 Ib/1,000 gallons condensate throughput 27 of 76 K:\PA\2019\19WE0081.CP1.xlsm Condensate Tank Regulatory Analysis Worksheet Colorado Re ulation 3 Parts A and B - APEN and Permit Re uirements _ Source is in the Attainment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Is the construction date (service date) prior to 12/30/2002 and not modified after 12/31/2002 (See PS Memo 05-01 Definitions 1.12 and1.14 and Section 2 for additional guidance on grandfather applicability)? 3. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.3)? Source requires a permit Yes N, NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Is the construction date (service date) prior to 12/30/2002 and not modified after 12/31/2002 (See PS Memo 05-01 Definitions 1.12 and1.14 and Section 2 for additional guidance on grandfather applicability)? 3. Are total facility uncontrolled VOC emissions greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.2)? You have indicated that source is in the Attainment Area Na Colorado Regulation 7, Section XII.C-F 1. Is this storage tank located in the 8 -hr ozone control area or any ozone non -attainment area or attainment/maintenance area? 2. Is this storage tank located at an oil and gas exploration and production operation', natural gas compressor station or natural gas drip station? 3. Is this storage tank located upstream of a natural gas processing plant? Storage Tank is not subject to Regulation 7, Section XII.C-F Section XII.C.1 — General Requirements for Air Pollution Control Equipment — Prevention of Leakage Section XII.C.2 — Emission Estimation Procedures Section XII.D — Emissions Control Requirements Section XII.E — Monitoring Section XII.F — Recordkeeping and Reporting Colorado Regulation 7, Section XII.G 1. Is this storage tank located in the 8 -hr ozone control area or any ozone non -attainment area or attainment/maintenance area? 2. Is this storage tank located at a natural gas processing plant? 3. Does this storage tank exhibit "Flash" (e.g. storing non -stabilized liquids) emissions and have uncontrolled actual emissions greater than or equal to 2 tons per year VOC? Storage Tank is not subject to Regulation 7, Section XII.G No No Yes Section XII.G.2 - Emissions Control Requirements Section XII C.1 — General Requirements for Air Pollution Control Equipment — Prevention of Leakage Section XII C.2 — Emission Estimation Procedures Colorado Regulation 7, Section XVII 1. Is this tank located at a transmission/storage facility? 2. Is this condensate storage tank' located at an oil and gas exploration and production operation , well production facility, natural gas compressor station] or natural gas processing plant? 3. Is this condensate storage tank a fixed roof storage tank? 4. Are uncontrolled actual emissions' of this storage tank equal to or greater than 6 tons per year VOC? Storage tank is subject to Regulation 7, Section XVII, B, C.1 & C.3 Section XVII.B — General Provisions for Air Pollution Control Equipment and Prevention of Emissions Section XVII.C.1 - Emissions Control and Monitoring Provisions Section XVII.C.3 - Recordkeeping Requirements 5. Does the condensate storage tank contain only "stabilized" liquids? Storage Tank is not subject to Regulation 7, Section XVII.C.2 No Yes Yes Yes Section XV1I.C.2 - Capture and Monitoring for Storage Tanks fitted with Air Pollution Control Equipment 40 CFR, Part 60, Subpart Kb, Standards of Performance for Volatile Organic Liquid Storage Vessels 1. Is the individual storage vessel capacity greater than or equal to 75 cubic meters (m3) ["472 BBLsj? 2. Does the storage vessel meet the following exemption in 60.111b(d)(4)? a. Does the vessel has a design capacity less than or equal to 1,589.874 m3 [`10,000 BBL] used for petroleum' or condensate stored, processed, or treated prior to custody transfer" as defined in 60.111b? 3. Was this condensate storage tank constructed, reconstructed, or modified (see definitions 40 CFR, 60.2) after July 23, 1984? 4. Does the tank meet the definition of "storage vessel"3 in 60.111b? 5. Does the storage vessel store a "volatile organic liquid (VOL)"5 as defined in 60.111b? 6. Does the storage vessel meet any one of the following additional exemptions: a. Is the storage vessel a pressure vessel designed to operate in excess of 204.9 kPa [-29.7 psi] and without emissions to the atmosphere (60.110b(d)(2))?; or b. The design capacity is greater than or equal to 151 m3 [950 BBL] and stores a liquid with a maximum true vapor pressures less than 3.5 kPa (60.11ob(b))?; or c. The design capacity is greater than or equal to 75 M3 ["472 BBL] but less than 151 m3 ['950 BBL] and stores a liquid with a maximum true vapor pressures less than 15.0 kPa(60.110b(b))? Storage Tank is not subject to NSPS yr: Subpart A, General Provisions §60.112b - Emissions Control Standards for VOC §60.113b - Testing and Procedures §60.115b - Reporting and Recordkeeping Requirements §60.116b - Monitonng of Operations 40 CFR, Part 60, Subpart 0000, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution 1. Is this condensate storage vessel located at a facility in the onshore oil and natural gas production segment, natural gas processing segment or natural gas transmission and storage segment of the industry? 2. Was this condensate storage vessel constructed, reconstructed, or modified (see definitions 40 CFR, 60.2) between August 23, 2011 and September 18, 2015? 3. Are potential VOC emissions2 from the individual storage vessel greater than or equal to 6 tons per year? 4. Does this condensate storage vessel meet the definition of "storage vessel"' per 60.5430? 5. Is the storage vessel subject to and controlled in accordance with requirements for storage vessels in 40 CFR Part 60 Subpart Kb or 40 CFR Part 63 Subpart HH? Storage Tank is not subject to NSPS 0000 Yes Source Req Go to next Source Req Storage Tar Storage Tar Storage Tar Storage Tar Continue -' Go to the n Go to then Source is st Storage Tai Storage Tar J Ye> N:, Subpart A, General Provisions per §603425 Table 3 460.5395 - Emissions Control Standards for VOC §60.5413 - Testing and Procedures §60.5395(g) - Notification, Reporting and Recordkeeping Requirements §60.5416(c) - Cover and Closed Vent System Monitoring Requirements 460.5417 - Control Device Monitoring Requirements [Note: If a storage vessel is previously determined to be subject to NSPS 0000 due to emissions above 6 tons per year VOC on the applicability determination date, it should remain subject to NSPS 0000 per 60.5365(e)(2) even if potential VOC emissions drop below 6 tons per year) 40 CFR, Part 63, Subpart MACT HH, Oil and Gas Production Facilities 1. Is the storage tank located at an oil and natural gas production facility that meets either of the following criteria: a. A facility that processes, upgrades or stores hydrocarbon liquids2 (63.760(a)(2)); OR b. A facility that processes, upgrades or stores natural gas prior to the point at which natural gas enters the natural gas transmission and storage source category or is delivered to a final end user3 (63.760(a)(3))? 2. Is the tank located at a facility that is major' for HAPs? 3. Does the tank meet the definition of "storage vesser4 in 63.761? 4. Does the tank meet the definition of "storage vessel with the potential for flash emissions"5 per 63.761? 5. Is the tank subject to control requirements under 40 CFR Part 60. Subpart Kb or Subpart 0000? No Storage Tank is not subject to MACT HH Subpart A, General provisions per §63.764 (a) Table 2 §63.766 • Emissions Control Standards §63.773 • Monitoring §63.774 - Recordkeeping §63.775 - Reporting RACT Review RACT review is required if Regulation 7 does not apply AND if the tank is in the non -attainment area. If the tank meets both criteria, then review RACT requirements. Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations, and Air Quality Control Commission regulations. This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act„ its implementing regulations, and Air Quality Control Commission regulations. the language of the statute or regulation will control. The use of non -mandatory language such as 'recommend," "may," "should,- and "can." is intended to describe APCD interpretations and recommendations. Mandatory terminology such as "must" and "required" are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself Continue -' Storage Tar Storage Tar Continue - Storage Tar Produced Water Storage Tank(s) Emissions Inventory 007 Produced Water Tank Facility AIRs ID: County A020 Plant 007 Point Section 02 - Equipment Description Details Detailed Emissions Unit Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: Five (5) 400 bbl produced water tanks Enclosed combustor Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Storage Tank(s) Actual Produced Water Throughput = 237,250 Barrels (bbl) per year Actual Produced Water Throughput While Emissions Controls Operating = Requested Permit Limit Throughput = 237,250 Barrels (bbl) per year Requested Monthly Throughput = 20150 Barrels (bbl) per month Potential to Emit (PTE) Produced Water Throughput = 2.84700 Barrels (bbl) per year Secondary Emissions - Combustion Device(s) Heat content of waste gas = 1496 Btu/scf Volume of waste gas emitted per BBL of liquids produced = 36 scf/bbl Actual heat content of waste gas routed to combustion device = Requested heat content of waste gas routed to combustion device = Potential to Emit (PTE) heat content of waste gas routed to combustion device = Section 04- Emissions Factors & Methodologies Will this storage tank emit flash emissions? 12,777 MMBTU per year 12,777 MMBTU per year 15,333 MMBTU per year Emission Factors Produced Water Tank Pollutant Uncontrolled Controlled (lb/bbl) (Ib/bbl) Emission Factor Source (Produced Water Throughput) (Produced Water Throughput) VOC 0.262 1.31E-02 Benzene 0.007 3.50E-04 I.duced Water State E.F. (ir&ides OFfshi - Fror. Toluene 0.000 !ducets Water State.E.F. ` ' 5 a r s; Ethylbenzene 0.000 Xylene 0.000 n -Hexane 1.10E-03 224 TMP 0.000 Control Device Emission Factor Source Uncontrolled Uncontrolled Pollutant (lb/MMBtu) (Ib/bbl) (waste heat combusted) (Produced Water Throughput) PM10 0.0075 0.0004 AP -42 Table 14.2(# M1df0 € 2S AP -42 tabte .1.4-2 (PM10/PM.2.5 AP -42 Chapter 1.5,5 Industriaf Flares {NOx) AP -42 :_.” ,,' " t :...;4z t -,r :' ..-,- ,,-::, PM2.5 0.0075 0.0004 NOx 0.0680 0.0037 CO 0,3100 0.0167 Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tcns/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) VOC 37.3 31.1 1.6 31.1 1.6 264 PM10 0.1 0.0 0.0 0.0 0.0 8 PM2.5 0.1 0.0 0.0 0.0 0.0 8 NOx 0.5 0.4 0.4 0.4 0.4 74 CO 2.4 2.0 2.0 2.0 2.0 336 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene 1993 1661 83 1661 83 Toluene 0 0 0 0 0 Ethylbenzene 0 0 0 0 0 Xylene 0 0 0 0 0 n -Hexane 6263 5220 261 5220 261 224 TMP 0 0 0 0 0 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit Regulation 7, Section XVII.B, C.1, C.3 Storage tank is subject to Regulation 7, Section XVII, B, C.1 & C.3 Regulation 7, Section XVII.C.2 Storage tank is subject to Regulation 7, Section XVII.C.2 Regulation 6, Part A, NSPS Subpart OOOO Storage Tank is not subject to NSPS 0000 (See regulatory applicability worksheet for detailed analysis) 29 of 76 K:\PA\2019\19WE0081.CP1.xlsm Produced Water Storage Tank(s) Emissions Inventory Section 07 - Initial and Periodic Sampling and Testing Requirements Does the company use a site specific emissions factor to estimate emissions? If yes and if there are flash emissions, are the emissions factors based on a pressurized liquid water sample drawn at the facility being permitted and analyzed using flash liberation analysis? This sample should be considered representative which generally means site -specific and collected within one year of the application received date. However, if the facility has not been modified (e.g., no new wells brought on-line), then it may be appropriate to use an older site -specific sample. If no, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor. See PS Memo 14-03, Questions 5.9 and 5.12 for additional guidance on testing. Does the company request a control device efficiency greater than 95% for a flare or combustion device? No If yes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling Section 08 - Technical Analysis Notes Source is using state EFs. No testing is required q < . < • • .C. S .. ..... ..n'.44:: ' < ,....:''•< :C C .. '<.1.•••<:•:•:• .:,< x 1,:nY.< :> < .i\.: /..� ♦ \ . .\J ^\.. .ynl., 1 .V.....S '.C: % S K. <t.f:/...<. ....\::S in/: ••••Z:<:::::.:'>(....Q'...:....:.:, ..S.. ........:W/.• I /K.t Y.. <i ! .4. 1. f 1 [ /.....4.4:44. ....<'. >:: S 'V cxx>::[ni < ..xx,:n ..• .n :..<:x ['.t .<t4T[ . ( xx x..'... : .>':<..i n: n .<>.. .::... R S>n(./.. •••••1‘.:.:5;;'..1:•.' [C,.,1•••.......:(...'..'..;.•.c.4 X'....;:::„.....:...:.:2::::•••••.....n .: %.4 ... .<1.: .1. .I.I.... 1.. 2:. rCll :?tom:..w .inn ......r(. .... :..t C4 c: 44[x(4: — ..—.C <)- C........ .,. r. . . >:! n: n. .... .. .. .. .. `..< . ' ..... .. :a: .....,%:::: xxxxx ...: .: .. � S nx`C::CCJ.C.: i.. .. •- :C: ! .n:...... .. k ..... ... >: s22 f: a:z;:a ♦6i S F nor.:: q:-:-.3 i Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 007 Process # SCC Code 01 4-04-003-15 Fixed Roof Tank, Produced Water, working+breathing+flashing losses Uncontrolled Emissions Pollutant Factor Control % Units PM10 0.01 0 lb/1,000 gallons liquid throughput PM2.5 0.01 0 lb/1,000 gallons liquid throughput NOx 0.09 0 lb/1,000 gallons liquid throughput VOC 6.2 95 lb/1,000 gallons liquid throughput CO 0.40 0 lb/1,000 gallons liquid throughput Benzene 0.17 95 lb/1,000 gallons liquid throughput Toluene 0.00 95 lb/1,000 gallons liquid throughput Ethylbenzene 0.00 95 Ib/1,000 gallons liquid throughput Xylene 0.00 95 lb/1,000 gallons liquid throughput n -Hexane 0.52 95 lb/1,000 gallons liquid throughput 224 TMP 0.00 95 lb/1,000 gallons liquid throughput 30 of 76 K:\PA\2019\19WE0081.CP1.xlsm Produced Water Storage Tank Regulatory Analysis Worksheet Please note that NSPS Kb might be might be applicable for certain tanks at water management and injection facilities. If the tanks you are reviewing are at one of these facilities, please review NSPS Kb. Colorado Regulation 3 Parts A and B - APEN and Permit Requirements Source is in the Attainment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Is the operator claiming less than 1% crude oil and is the tank located at a non-commercial facility for processing oil and gas wastewater? (Regulation 3, Part B, Section II.D.1.M) 3. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.3)? Yes No Yes Source requires a permit NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Is the operator claiming less than 1% crude oil and is the tank located at a non-commercial facility for processing oil and gas wastewater? (Regulation 3, Part B, Section II.D.1.M) 3. Are total facility uncontrolled VOC emissions greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.2)? You have indicated that source is in the Attainment Area Colorado Regulation 7, Section XVII 1. Is this tank located at a transmission/storage facility? 2. Is this produced water storage tank' located at an oil and gas exploration and production operation , well production facility2, natural gas compressor station3 or natural gas processing plant? 3. Is this produced water storage tank a fixed roof storage tank? 4. Are uncontrolled actual emissions' of this storage tank equal to or greater than 6 tons per year VOC? No Yes Storage tank is subject to Regulation 7, Section XVII, B. C.1 & C.3 Section XVII.B — General Provisions for Air Pollution Control Equipment and Prevention of Emissions Section XVII.C.1 - Emissions Control and Monitoring Provisions Section XVII.C.3 - Recordkeeping Requirements 5. Does the produced water storage tank contain only "stabilized" liquids? If no, the following additional provisions apply. Storage tank is subject to Regulation 7, Section XVII.C.2 Section XVII.C.2 - Capture and Monitoring for Storage Tanks fitted with Air Pollution Control Equipment 40 CFR, Part 60, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution 1. Is this produced water storage vessel located at a facility in the onshore oil and natural gas production segment, natural gas processing segment or natural gas transmission and storage segment of the industry? 2. Was this produced water storage vessel constructed, reconstructed, or modified (see definitions 40 CFR, 60.2) between August 23, 2011 and September 18, 2015? 3. Are potential VOC emissions2 from the individual storage vessel greater than or equal to 6 tons per year? 4. Does this produced water storage vessel meet the definition of "storage vessel"1 per 60.5430? Storage Tank is not subject to NSPS OOOO Subpart A, General Provisions per §60.5425 Table 3 §60.5395 - Emissions Control Standards for VOC §60.5413 - Testing and Procedures §60.5395(g) - Notification, Reporting and Recordkeeping Requirements §60.5416(c) - Cover and Closed Vent System Monitoring Requirements §60.5417 - Control Device Monitoring Requirements [Note: If a storage vessel is previously determined to be subject to NSPS OOOO due to emissions above 6 tons per year VOC on the applicability determination date, it should remain subject to NSPS OOOO per 60.5365(e)(2) even if potential VOC emissions drop below 6 tons per year] RAG Review RAG review is required if Regulation 7 does not apply AND if the tank is in the non -attainment area. If the tank meets both criteria, then review RACT requirements. Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations, and Air Quality Control Commission regulations. This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law. regulation, or any other legally binding requirement and is not legally enforceable_ In the event of any conflict between the language of this document and the language of the Clean Air Act„ its implementing regulations, and Air Quality Control Commission regulations, the language of the statute or regulation will control. The use of non -mandatory language such as 'recommend," 'may," 'should," and 'can," is intended to describe APCD interpretations and recommendations. Mandatory terminology such as "must" and 'required" are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself Source Req Go to next • Source Req Continue -' Continue -' Go to the n Source is st Source is st Continue -' Storage Tar Natural Gas Heater Emissions Inventory Detailed Emissions Unit Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: Low NOx combustion system is considered an integral control device. Section 03 - Processing Rate Information for Emissions Estimates Design Heat Input Rate = Heat content of waste gas = Actual Hours of Operation = Requested Hours of Operation = Requested heat input rate = Actual Fuel Consumption = 008 NG Heater 'Facility AIRs ID: County 008 Plant Point Section 02 - Equipment Description Details Heater Information Fuel Type Number of Heaters Purpose Make: Model: Serial Number: Design Heat Input Rate: Equipped with Low-NOx burners: Equipped with Add -On Control Equipment: eneraton hteater One (1) MMBtu/hr One (1) natural gas heater(s) (Make: TBD, Model: TBD, Serial Number: TBD) each with a design heat input rate of 17.5 MMBtu/hr. Each unit is equipped with low-NOx burners. Each unit is an amine regeneration heater. No add-on control equipment 17.5 MMBtu/hr 1030 Btu/scf 8760 hrs/year 8760 hrs/year 153,300.00 MMBTU per year MMscf/year Requested Fuel Consumption = 8 83 MMscf/year Requested Monthly Throughput = 12.64 MMscf per month Potential to Emit (PTE) Fuel Consumption = Section 04 - Emissions Factors & Methodologies 118.83 MMscf/year Emission Factors Natural Gas Heaters Pollutant Uncontrolled Uncontrolled lb/MMBtu lb/MMscf (Fuel Heat Combusted) (Fuel Consumption) Emission Factor Source PM10 0.00745098 7.674509804 A) .t .1, , 2: > sLi r.1-tn.t .); PM2.5 0.00745098 7.674509804 AP•42 Table 1.4-2 FPNt10/PM.t .Sj AP -42 Table. 1.4-2 (Sox) AP -42 Table 1..4-. zirti.,v1 3 inirhirrM'; r` SOx 0.000588235 0.605882353 NOx 0.049019608 50.49019608 CO 0.082352941 41.2 Maneifizcturec. VOC 0.005392157 5.553921569 Ar,42 "a uilk- s.4-2 (!V'0;:. Formaldehyde 7.35294E-05 0.075735294 AP -42 1 able 1.4-3 {Forma-. Benzene Benzene 2.05882E-06 0.00212058S AP -42 Table ?.4-3 {Benzene) AP -42 Table 1.4_x {Toluene) Toluene 3.33333E-06 0.003433333 n -Hexane 0.001764706 1.817647059 A," "' -: , - Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 SOx 0.57 0.57 0.57 0.57 0.57 97 0.57 0.57 0.57 0.57 0.57 97 0.05 0.05 0.05 0.05 0.05 8 NOx 3.76 3.76 3.76 3.76 3.76 638 CO 3.07 3.07 3.07 3.07 3.07 521 VOC 0.41 0.41 0.41 0.41 t 41 70 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Formaldehyde 11 11 11 11 11 Benzene 0 0 0 0 0 Toluene 1 1 1 1 1 n -Hexane 271 271 271 271 271 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit Regulation 1, Section VI Based on the requested emissions and emission factor, compliance is presumed. Regulation 1, Section III & Regulation 6, Part B, Section II Based on the design heat input rate, the source is subject to Regulation 1 Section III.A.1.b. and Regulation 6, Part B, Section II.C.2. and 3. Based on the requested emission factor, compliance is presumed. Regulation 6, Part A, Subpart Db, 502 Standards Source is not subject to NSPS Db. Regulation 6, Part A, Subpart Db, NOx Standards Source is not subject to NSPS Db. Regulation 6, Part A, Subpart Dc Source is subject to NSPS Dc. Regulation 7, Section XVI.D Source is not subject to Regulation 7, Section XVI.D. Regulation 8, Part E, MACT Subpart DDDDD Source is not subject to MACT DDDDD. 32 of 76 K:\PA\2019\19W E0081.CP 1.xlsm Natural Gas Heater Emissions Inventory (See regulatory applicability worksheet for detailed analysis) Section 07 - Initial and Periodic Sampling and Testing Requirements Is the project close to the 40 tpy modeling / NANSR threshold for NOx? If yes, stack -testing should be required for NOx, as well as for CO. Is the operator limiting their heat input rate below the design rate? If yes, stack -testing should be required for NOx, as well as for CO. Is the project close to the 5 tpy modeling threshold for PM 2.5? If yes, stack -testing should be required for PM 2.5 Does the company use AP -42 emission factors (or more conservative factors)? If no and testing hasn't already been required due to proximity to modeling thresholds, testing should be required for any pollutants for which alternative emission factors have been used. If testing is being done for only NOx or only CO, the other should be included as well. Section 08 - Technical Analysis Notes Source claims a manufacturer spec sheet for CO emission factor of 41.2 lb/mmscf (AP42 is 84 lb/mmscf), but source has not specified the manufacturer or model in the APEN or elsewhere, or provided any spec sheet. Therefore, this heater and any other heater using this emission factor shall be required to stack test for CO, and incidentally for NOx. Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point tt 008 Process # 01 SCC Code Pollutant 3-10-004-04: Industrial Process; Oil & Gas Production; Process Heaters; Natural Gas (MMscf) PM10 PM2.5 SOx NOx CO VOC Formaldehyde Benzene Toluene n -Hexane Uncontrolled Emissions Factor 7.67 7.67 0.61 50.49 41.20 5.55 7.57E-02 2.12E-03 3.43E-03 1.8 Control% Units 0 lb/MMscf Burned 0 lb/MMscf Burned O lb/MMscf Burned 0 lb/MMscf Burned 0 lb/MMscf Burned O lb/MMscf Burned 0 lb/MMscf Burned 0 lb/MMscf Burned O lb/MMscf Burned 0 lb/MMscf Burned 34 of 76 K:\PA\2019\19WE0081.CP1.xlsm Natural Gas Heater Regulatory Analysis Worksheet Based on the heater purpose selection in the inventory. this unit qualifies as fuel burning equipment per Colorado Regulations 1 8 6, a steam generating unit per NSPS Db & Dc and a industrial. commercial or institutional boiler or process heater per MALT DOODD This unit fires natural gas as defined by N5PS Db 8 Dc and/or is designed to bum gas 1 Lela as defined by MACT DODDD Colorado Beletton 3 Pens A end l • APEN and Permit Reou(rements ISource is in the Attain:nent Area 1. Are uncontrolled actual emissions of arty cnteria pollutants from this individual source greater than 2 TRY (Regulation 3, Part A, Section 11.0.1 a)? 2. Does the heater have a design heat Input rate less than or equal to 5 MMBtu/hr? (Regulation 3, Peak Section II.D.1.k.) 3. Dom the heater have a design heat input rate less than or equal to 10 MMBtu/hr? (Regulation 3. Part B. Section 1I.O.1.e.) 4. Are total facility uncontrolled VOC emissions greater than S TPY,14Ox greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section11.O.3)? Source requires a permit No No NON -ATTAINMENT 1. Are uncontrolled emissions of any criteria pollutants from this Individual source greater than 1 TPY (Regulation 3, Part A, Section 11.O.1.a)? 2. Does the heater have a design heat input rate less than or equal to 5 MM8tu/hr? (Regulation 3, Part A, section 11.O.1.k.) 3. Does the heater have a design heat input rate less than or equal to 10 MMBtu/hr? (Regulation 3. Part B, Section II.D.1.e.) 4. Are total facility uncontrolled VOC emissions greater than 2 TPY, NOu greater than 5 WY or CO emission greater than 10 TPY (Regulation 3, Part B, Section II.D2)? you have indicated that source is in the Attainment Area Sslstuntelanulation L Section Nit 1. Are sulfur dloclde emissions from the heater greater than 2 tons per day? (Regulation 1, Section VI.8.5.a.) IBased on the requested emissions and emission factor, compliance :s presumed Section VI.BS - Emission Limits Section VI.6b and 7 - Recordkeeping, Reporting, Data Retention Colorado Regulation 1. Section 111 and Colorado Regulation 6 Part B Stollen II Standards of Perfp�rne_ for New Fual•6tin(D basins rS 1. What Is the design heat input rate of the heater? (Regulation 1, Section IIIA. and Regulation 6, Part B, Section I&.C.) 2 Does the source discharge particulate matter In excess of 0.5 Ib/Mmbtu heat input? (Regulation 1, Section IIIA.1a. and Regulation 6, Part 6, Section II.C1.) 3. Does the source disdarge particulate matter In access of the following equation: PE = 0.5(FI)1MI? (Regulation 1, Section 111.A.1.b. and Regulation 6, Part B, Section II.C2.) 4. Does the source discharge particulate matter In excess of 0.1 b/Mmbtu heat Input? (Regulation 1, Section IIIA.1.c.) Based on the design hen ;nput rate. the source is subject to Regulation 1 Section It! AI.b. and Regulation 6. Part B. Section II.C.2. and 3 Based on the requested emission factor, compaance is presumed. Colorado Regulation 7. Section XVI.D 1. Did the natural gas fired heater exist at a major source of NOs as as of June 3,2016? (Regulation 7 Section XVt.D.1.) 2. Does the natural gas fired heater have uncontrolled actual emissions of NO* equal to or greater than 5 tpy? (Regulation 7 Section XVI.D.6.a.) ISource is not subject to Regulation 7. Section XVI O. Section XVI.D.6.b. —Combustion Process Ad(ustmeM Section XV1.D.7.—Recordkeeping NSPS Analysis 1. Does the natural gas fired heater have a maximum design heat Input capacity of 29 megawatts (MW) (100 MMBtu/hr) or less, but greater than or equal to 2.9 MW (10MMBtu/hr)? (660.40c(a)) 2. Does the natural gas fired heater have a maximum design heat Input capacity greater than 29 megawatts (MW) (100 MMBtufhr)? (660.40b(a)) 'Evaluate questions In NSPS Dc section below. 40 CFR. Part 60. Subpart Dc. Standards of Performance for smell hndustrial-Commerclal•Inet(tutlorot Steam Generating Unita 1. Did construction, modification, or reconstruction of the steam generating unit commence after June 9, 1989? (660.40c(a)) 'Source is subject to ASPS De Subpart A. General Provisions 660.46c • Reporting and Resoordkeeping Requirements Source Requires an APEN. Go to the nest question Go to the neat question. Go to the next question. Source Respires 4 permit Go to the next question. Go to the neat question. No I Based on the requested missions and emission factor. compliance is presumed. Yes No Go to question 3. Based on the requested emission factor, compliance is presumed Based on the requested emission factor, compliance is presumed. Based on the requested emission factor, compliance Is presumed. Source is not subject to Regulation 7. Section XVI.D. Go to NSPS Dc applicability section Source (s not sullied to NSPS Db. Source is subject to NSPS Dc. 40,3313. Part ...subpart rks 1. r,mArb0m rec uurttvanetm.m gene...3 mx.nu une 9.3 rt 3146 33213, 2. Does the rratura13333red heater havea 3..1,302 emrs3Ten are 33130 /i 1n331WMMetu1 heat input .)3333 003.432[4)M] a. ti<,31�m bmt5wance MPS..mconnmam eaar�narnnaaa.awaa23.200sxlmo.42.11111 tt 4. Does the natural redIl Fd;trdw„I� Feat Inputnowaaix3 MW(50Mklgtwhr)arlaaa (25a.,ablgn 5a. tambm. alone onn mmbinanan, only natural-xas, dlnmate az, or mlaualml wlt2 nmwnaement fame weight p6amterin11430.432(0011: 52. combined annual opamy factor of 10 percent ak.33,33Nalga, dlstalate oil, and mldualfall W.a Mmgen copem 3(030 we1321 percent or kes(4303364111)I:and federally•subject tea fedlfederallyed2enble requirement umningapentlm 031 be affected lau4ity m thefeng daist naturalgas,ghleel{and/a2h r.dualellw3 nrtmgen content of030 w dght puentarlos am 11,311333 apenllon Wbealimeafaaiirvtoa comb. a annual cap.,' actor03a0 pecentaless foe natural gat, distillate an.and,eaunalaa with a mnogen Sc. content& 3.33 wegin percent a less.1§6u.aah11N31) laftl the tames commmc<comtpnb,, r®mlmewn a mminonun afterluly 03.19973 I4so.Mb1111 thenaturalgas fired subject b and In comdlsrsnnh a factuallyeaorcea,equuim,en that lbn opeation,therawty to an annual capacity facto- 0330 percent luagorlessror coal, oltad xvaPs(wan, canbbatlm of t.Ih,Wx146wa4yp1311 133e3323 natural gasfred Feat Hwelow.rat release rate andomtnet natural as ortlbtalateoaln yeas 0330 pemn 03Naheat input en a 30davr .gatvage front. mmtunlm of all 032.31450.�MMxg I xilafed 38.3136. 460.e3aq(31-wNara ter sulfur dfoaaa 15021 §3u.3agalegkl e.11l: OA andlo ..Startler" for nmrman odaea(nm) 43o.356.compllamaanclparfomanwa tad marra lsammroaauresbrarafurale.u. 460.3Sb.compliama and parkrmee..tint methods aMmremaumsfor partkulaa matter and nkroganoal"ea 450.076-Em6alon MON 2. 460.36h nnrogan oxides 430.336 p rtlacaM recordNaapl vlragrdamarm N MALI -Analysis 90am fwrt63 suboarusnn0000aa(wwbr Maim murtn:I,dustdal,mmmartaA and lmdturbal 3ellersana pmnROFF.F• 1. Is the heater locatedat facilitythat la a major aou,ororst+ps7(43a.7<ss) 2. man(§333440(2))ar®aeunf22(5.7444(0) ofhat=commeraaherfur44, 70103 3. y leas the n a equal l4 6 MM6hgN7 (5.7220(6)) a. at. eat Mmµm3tmks3thanomalaxa MMMu/M1r71463.7500(ell Isms. MAR MOW. 4M.75m la) rani 7aue 3 - W of oactke wMa. 434.7340 m 01-GenenlI,., ,0 ents §63.7520(et-Inmal,aquuemm�fdreapthgsmrces on®.733.3(gl ramxmum 593.7131.1 -subsequent ...fuel •3•133.73 atunnw 433.7530N andit-6amomtraurrg Innml complyram §n3.7330141i21and 747.3l731-0emmu,nling mminmus cominn e 5.7545(.4 2) foaedh40ore.,or cowl, la),b1131,1.1, 71,ef31-rvanmtiom 433.75231,1.16 41.10114 1141- 4apnllm 5.7553 (.1,13X31 ad 1x1 an"w.733n 14.121 and Id-gamNMnfrs3 This dawned Thawned 23sls(s epeatas.tlete2 mieq app6ab7Ayormran requirements ala 02447Aa34 i s impkaenllsgrequbliav ...4C.. 32x41 743. This NosM 6 ,aot rtelea6 aNfM amNs6 ifcmans May ml aypy d a pa .vau0070ased upon.udip .1/a. fixa(y law, repyt .... aa3ry49(2(1 04 tird,'r3mluYamMard6 rot kgalHmla®Me In Me aurymld4) 4477227 the (nguapeufuJs Nmma7) and )731379wpea7(he 064(39,34. ps 9npem+Nlge3gMalions, and A9, O.* Cam. Commission regulations, Me NUr 404327 re74(4347 llmn44. The703422777477(&640427079487422(723 (34472and.—may."abam,'md'C2n• is aro4tl Io desmbe 3KCO nlelpretatae ant recommendations. Mande, temmbpy S. as.'nausY an11 YaxuireC are 0(24(0eY b Oesoa3e mnfrd674 nenb under the arms a&ae Clean AYAct and. .Wil Control C4mna.nmyuatb40. OutV2[locum.doss not establish )222044Mrgrequirements irepntl NpseH. 7he unit arats,INanto nen Go. neatco.talen. 11.3. seurcemua cord. a taw.upamualH. Natural Gas Heater Emissions Inventory 008 NG Heater Facility AIRs ID: 123 A020 009 County Plant Point Section 02 - Equipment Description Details Heater Information Fuel Type Number of Heaters Purpose Make: Model: Serial Number: Design Heat Input Rate: Equipped with Low-NOx burners: Equipped with Add -On Control Equipment: One (1) MMBtu/hr One (1) natural gas heater(s) (Make: TBD, Model: TBD, Serial Number: TBD) each with a design heat input rate of 11 MMBtu/hr. Each unit is equipped with low-NOx burners. Each unit is a hot oil heater. Detailed Emissions Unit Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: Section 03 - Processing Rate Information for Emissions Estimates Design Heat Input Rate = Heat content of waste gas = Actual Hours of Operation = Requested Hours of Operation = Requested heat input rate = Actual Fuel Consumption = No add-on control equipment Low NOx combustion system is considered an integral control device. 11.0 MMBtu/hr 1030 Btu/scf 8760 hrs/year 8760 hrs/year 96.360.00 MMBTU per year 9 3.5'7 MMscf/year Requested Fuel Consumption = 93.6 MMscf/year Requested Monthly Throughput = 7.9 MMscf per month Potential to Emit (PTE) Fuel Consumption = Section 04 - Emissions Factors & Methodologies 93.55 MMscf/year Emission Factors Natural Gas Heaters Uncontrolled Uncontrolled Ib/MMBtu lb/MMscf Pollutant (Fuel Heat Combusted) (Fuel Consumption) Emission Factor Source PM10 0.00745098 7.674509804 Y g1r /i l`4.:, - Trig#1t..1. -2 PM10/PM,.: 1.4-2 U.: sx 1. : 1 V z . C25 ft,.OVY $`vsw i :Ai, Fes: >, AP -42 T .. ,t ' (‘: ; :: rt rt r 4, >J -. 1> AP -42 Tabie 1.4-3 (Fern (2hyde) '1°1 ,..p.. ; ; .2 AP -42 Tabs 1.4-3 (Benzene) s AP --12 Table 1.4-3 (Toluene} AP -42 ratite 1.4-3 (n -Hexane) PM2.5 0.00745098 7.674509804 SOx 0.000588235 0.605882353 NOx 0.049019608 50.4901960E CO 0.082352941 41.2 VOC 0.005392157 5.553921569 Formaldehyde 7.35294E-05 0.075735294 Benzene 2.05882E-06 0.00212058S Toluene 3.33333E-06 0.003433333 n -Hexane 0.001764706 1.817647059 Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 0.36 0.36 0.36 0.36 0.36 61 PM2.5 0.36 0.36 0.36 0.36 0.36 61 SOx 0.03 0.03 0.03 0.03 0.03 5 NOx 2.36 2.36 2.36 2.36 2.36 401 CO 1.93 1.93 1.93 1.93 1.93 327 VOC 0.26 0.26 0.26 0.26 0.26 44 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Formaldehyde 7 7 7 7 7 Benzene 0 0 0 0 0 Toluene 0 0 0 0 0 n -Hexane 170 170 170 170 170 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit Regulation 1, Section VI Based on the requested emissions and emission factor, compliance is presumed. Regulation 1, Section III & Regulation 6, Part B, Section II Based on the design heat input rate, the source is subject to Regulation 1 Section III.A.1.b. and Regulation 6, Part B, Section II.C.2. and 3. Based on the requ Regulation 6, Part A, Subpart Db, SO2 Standards Source is not subject to NSP5 Db. Regulation 6, Part A, Subpart Db, NOx Standards Source is not subject to NSPS Db. Regulation 6, Part A, Subpart Dc Source is subject to NSPS Dc. Regulation 7, Section XVI.D Source is not subject to Regulation 7, Section XVI.D. Regulation 8, Part E, MACT Subpart DDDDD Source is not subject to MACT DDDDD. 37 of 76 K:\PA\2019\19WE0081.CP1.xlsm Natural Gas Heater Emissions Inventory (See regulatory applicability worksheet for detailed analysis) Section 07 - Initial and Periodic Sampling and Testing Requirements Is the project close to the 40 tpy modeling / NANSR threshold for NOx? If yes, stack -testing should be required for NOx, as well as for CO. Is the operator limiting their heat input rate below the design rate? If yes, stack -testing should be required for NOx, as well as for CO. Is the project close to the 5 tpy modeling threshold for PM 2.5? If yes, stack -testing should be required for PM 2.5 Does the company use AP -42 emission factors (or more conservative factors)? If no and testing hasn't already been required due to proximity to modeling thresholds, testing should be required for any pollutants for which alternative emission factors have been used. If testing is being done for only NOx or only CO, the other should be included as well. 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X k 4x MN4%)'aa CXaxx..x4Gkxx%4xa%4xx3n xYfx tx xx Y ttK`cxx' XxxzxK't ts[glrY xk: <T.Yxx\".'X Y [LCCC XV")C>C>> Yj X. >ix n.a Y',X _344.. > 344.1.4 : </ L " '''''3>\•' ;. s ]s"<'X Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 009 Process # 01 SCC Code Pollutant 3-10-004-04: Industrial Process; Oil & Gas Production; Process Heaters; Natural Gas (MMscf) PM10 PM2.5 SOx NOx CO VOC Formaldehyde Benzene Toluene n -Hexane Uncontrolled Emissions Factor 7.67 7.67 0.61 50.49 41.20 5.55 7.57E-02 2.12E-03 3.43E-03 1.8 Control% Units 0 lb/MMscf Burned O lb/MMscf Burned 0 lb/MMscf Burned 0 Ib/MMscf Burned O lb/MMscf Burned 0 lb/MMscf Burned 0 lb/MMscf Burned O lb/MMscf Burned 0 Ib/MMscf Burned 0 lb/MMscf Burned 38 of 76 K:\PA\2019\19WE0081.CP1.xlsm Natural Gas Heater Regulatory Analysis Worksheet Based on the heater purpose selection it the nventcry, this,;^it q;,aiifin as fuel burning equipment per Colorado Regulatiem 1 & 6. a steam generating unit per 45..s Db 6 Oc and a irdustrial. commercial or irotiru tonal baler or process heater per MAC' MOW This unit fires natural gas as deairod by NSPS Db & Dc and/or is designed to bum tea 1 tale as defined by MACT 00000 Coloredoltegulation 3 Parts A and B - APEN and Permit Requirements ISo _rco :c .n the,tta. ,^aerr. Pt ea N77ABYMEf4T 1. Are uncontrolled actual emissions of any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section 11.D.1 a)? 2. Does the heater have a design heat Input rate less than or equal to S MMBtu/hr? (Regulation 3. Part A, Section 11.0.1.k.) 3. Does the heater have a design heat input rate less than or equal to 10 MMBtu/hr? (Regulation 3, Part 8, Section II.D.l.e.) 4. Are total facility unmet rolled VOC emissions greater than 5 TPY, NOx greater than 10 TRY or CO emissions greater than 10 TPY (Regulation 3, Part 8, Sect on n.D.3)? Soave requires ape NON -ATTAINMENT I. Are uncontrolled emissions of any cntena pollutants from this individual source greater than I TPY (Regulation 3, Part A. Staid, II.D.1.a)? 2. Doe the heater have a design heat input rate less than or equal to S MMBtu/hr? (Regulation 3, Part A. Sect ion 11.D.1.k.) 3. Don the heater have a design heat input rate les than or equal to 10 MMBtu/hr? (Regulation 3. Part B, Section II_D.Le.) 4. Are total facility uncontrolled VOC emissions greater than 2 TRY, NOx greater than S IVY or CO emissions greater than 10 TPY (Regulation 3, Part 8, Section 0.0.2)? You have indicated that source is in the Attainment Area Colorado Regvlatlon 1. Section VI 1 Are sulfur amide emissions from the heater greater than 2 tons per day? (Regulation 1, Section VI.B.5.a.) IEased o^ the requested em :s one en;; em.ssion factor, wrr Bence ore turned Section VI.B3 • Emission Limes Section Vi.gb and 7 - Recordkeepng, Reporting, Data Retention Colorado. Ragukfioel• Secti9_n PI and Coloreds! Rofelation6, Vert g, soul{n II,Stonecda ¢ Porfornsonettettirtchothlanclaiirtet 1. what is the design heat input rated the heater? (Regulation 1, Section IIIA and Regulation 6, Part B. Section B.C) 2 Does the source discharge particulate matter in excess of 0.5 b/Mmbtu heat input? (Regulation 1, Section IIIA1 A. and Regulation 6, Part 8. Section It C.1.) 3. Does the source discharge particulate matter in excess of the following equation: PE a 0.5(H)t s"7 (Regulation 1, Section IIIA1.b. and Regulation 6, Part 8, Stalon 1112.) 4. Does the source discharge particulate matter In excess of 0.1 Ib/Mmbtu heat input? (Regulation 1, Section III.A.1.c.1 eased on the desgn vat spurt ratettw source is sucier- to iegulation I Section Ill_A.1.0. and Regulation 6. Put B, Section II.C2. and 3. Based on the requested emisaion factor, ccmpli arca is presumed Co f or ad ol4exvkt!on?..,.cticn X V I.Q. 1. Did the natural gas fired heater vat at a major source of NO as as of June 3.2016? (Regulation 7 Section XVI.0.1.) 2. Does the natural gas fired heater have uncontrolled actual emissions of NOx equal to or greater than 5 toy? (Regulation 7 Section XVt.0.6.a.) Source ia not tut ea to Raiulat en 7 Section i Section XVI.D.6.b. -Combustion Process Adlustment Section XVI.D.7. — Recordkeepng NSPS Analysis Does the natural gas fired heater have a maxim urn design heat input capacity of 29 megawatts (MW) (100 MMetu/hr) a less, but greater than or equal to 2.9 MW (10MMBtu/Fv)? (§60.40c(a)) 2. Does the natural gas fired heater have a maximum design heat input capacity greater than 29 megawatts (MW) (100 MMBtu/M)? (460.40b(a)) IEvaivata q.nesto -s In NSPS Dc section beic« Source Requires an Aefti. Go to the nein question Go to this nen question. Go M the nem gsastion_ Source Requires a permit Go to the next question. Go to the non question. Not I Based on the requested emissions and emMsion factor. compliance is presumed. vas 4Q CERtro t44.Sgbent Qc.IUr1ded69f hrformanct for Small Industrie Kontrtlerciel-lrtst(ttrtioMl Steam GO neratint k0(ta 1. Did construction, modification, or reconstrtxtlon of the steam generating unit commence after June 9, 1989? (§60.4Oc(a)l ISource is suttee: to NSPS Dc Subpart A, General Provisions §60.48c - Reporting and Recordkeeping Requirements No Go to question 3. Based on the requested emission factor. compliance a presumed Based on the requested emission factor. compiiarce is presumed. Based on the requested emission factor, compliance is Presumed. Source is rot subject bo Regulation 7. Section 41.9.0. Go to NSPS Dc applicability season Source a not stilted to NSPS Db subject to NSPS Dc. 3, and sonstn.cnn, racciffkat., or reconstruction dthe Pee rn generating tm,nmenaartertunoza,Sae<g I4.a4u6p11 yea potemlal sox esn0slou rate4340 ng/1 la3z Ih/INMatu)n.at snout orine≥ (4sa.4xb(k)2)) 3. old the affeuted fad commenceaostroaron reconstruct,. ormodfleation rtterFeliva 2e 2005, 042 source rots. ett NSPSOb Nosstordards 4. Dom the natunl gas feed beater have a tInv(zso mmetuhr) orlea1§.3.44611)1 3. Doestne heatersnea gofthemoig etc. (§.313A41:44) sa. combun.atone a In combnalonanh, natural as, ammaled,anstlualoawaha narosen rntenta0.3wekk percent of lets 660.44M111s11: 511 omcayrado ezo percent a less for nauntas,memlale m,md mnulm wM a nitrogen content of 020 weight percent orlessl§s3.a46Ck)l: and �ubject to fiderally ertmaable raquoeme tltmm,¢opernlonxmearteadraafitoahera6,e afnatnral eas,aenmeoa, ana/orieuaualmwnha nitrogen cont., 030 wednpetanorlasadumnxsoperabatdthe affected awtytea tan6stoa anal olamyraoord10 petal orIna la-naturalga4,db<ele<eoa,ad rase. .oPhoO mgr Sc. content of 020 weight pert. or la..14s0.44bg11311 6. Did the affected fadaymminer4m6ln,_a.,reocesttunwtor mdlgoton anamp03 33ni14sa4eb(11) asubiee m and In compllapcewaha led.sfallye.rceablerequirement.t Iboboprotwne to man/to anammualnpaem factoro 10peent(0.10)alea.m- gas leanymnbbnlonofthe lhreelg l440.44H111x11 Dom the natural heater have lax beat ielnaerate and combust natural as ordhalzteoaen ace. 4 x 30 pentalthe heat Input on a 30.day melng average (ram Me enmb+alta crap fi(4so.44H111x11� 0004370110)-smdardnr.utfurdloed.15o4) 450447.1nrlklnrm:lhl.Mrl.rin-St derdm, nbroe4n ealde.100a) 450.456-cumpmrce and weorm.rc.<sat methods and procedures for sulfur dioxide %mar- cernptionce.na padenare. 3.,tnthads and presoduroslorpartkulrta mata..dnmeg.nedd.a .50.400-amlabn m0Htedn4moron and Aragon oxides 4ad.4ah aepotbrem and n44breep51bg,4444regmrem.ss MAC -Analysis 40 cm. Pert sn.suwart rnxroop3o Haaws tar m.kr.wm..'ldom•L Comm... and lmbwdoml Sellers and rmna NW, 1. Is tbe heater facIlItythat is a major sourcerorFupsd443.T4ss1 4. on(4s3�4solbl124 onl4s3.T4en101dheatercommenareemam ,e4, en 3.milunnat pmrapadgla 4(noregqualtoo3mmamm0lsa3.>5.(0) 4. lathe atoll but lea than enenuslmao mmetu/hR15,33.T00.11 '44 mtsuhleusm corer [mono. §04.7500 lel and Tatie 3-wwtpractice 00774rds 4.3.,5.6 (d -3nenl recuaenter4. 03.751041-t ener0ra vOWten,(.aaaam 004.T5351d1-S. x4vn<cs.rwaaMe=tu� .a3. 4a3.Ts0oml ad() -m mmdo-00 §a3.as40(a11xaland1.1U31-04400441n4mm5veu mma0uc 4c0.Ts451.1, R -.r Seating or a. der mwL 1.L 1.11f 1,.Iq, all Mal -x ogoten 460.,0501.1.16E 14 1011 H31-p.mnlea 4.3.4551aL 411118.121.4 53.356.14.1 bl and lq-wwrdb.plm Dizmlaimer This document assists operators with datermoing applicability reser Mrequirements ofMe Clean Freq., its enplementeq regulations, ell Ai Ouabts Coned Commission reguietrorw, This document Is rat a ruled mgulalta,, and Me erre,ysls contains miss not apply lea particularsduatdan beset, wont. lMrvMual/077 eat raraumstances. This document does not charge or substitute /crony late,regukb'an,want CMare,p00 Nndiegrapuharenyand is ratiag7707 mseree In Me ant of any con0Mrbetwsen the language of lhls document and the language olth0 use A6 Act„ ifs Implem0nl4g regulations, andir[Mares Cored Lommissi reputations, Me languages site statute a reputationtnnconed. The use Wrmmardetay language such es Yecamna 0• resere• rehired; and tang is intenda In describe AOCCMrernetaliom end tecommaOa00m. Mardatuy terminology such es tWrenlb/S sure 0074710000 iden.�Mdesabe canedbng requirements underlies terms tithe Crean 'relict end Ai°WilyC itsre Commission regulations, del this document does nut establish IegalH binding requienvth eneX. uni in ems own -rem nk net sublenmrnac,. Natural Gas Heater Emissions Inventory 008 NG Heater (Facility AIRs ID: 123 A020 County Plant 010 Point Section 02 - Equipment Description Details Heater Information Fuel Type Number of Heaters Purpose Make: Model: Serial Number: Design Heat Input Rate: Equipped with Low-NOx burners: Equipped with Add -On Control Equipment: Natural Gas 1 re regeneration heater TBD TBD TBD 16.5 Yes No One (1) MMBtu/hr One (1) natural gas heater(s) (Make: TBD, Model: TBD, Serial Number: TBD) each with a design heat input rate of 16.5 MMBtu/hr. Each unit is equipped with low-NOx burners. Each unit is a molecular sieve regeneration heater. Detailed Emissions Unit Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: Section 03 - Processing Rate Information for Emissions Estimates Design Heat Input Rate = Heat content of waste gas = Actual Hours of Operation = Requested Hours of Operation = Requested heat input rate = Actual Fuel Consumption = No add-on control equipment Low NOx combustion system is considered an integral control device. 16.5 MMBtu/hr 1030 Btu/scf 8760 hrs/year 8760 hrs/year 144,540.00 MMBTU per year 1.:1? MMscf/year Requested Fuel Consumption = 130.3 MMscf/year Requested Monthly Throughput = 11.9 MMscf per month Potential to Emit (PTE) Fuel Consumption = Section 04 - Emissions Factors & Methodologies 1,1,) 133 MMscf/year Emission Factors Natural Gas Heaters Pollutant Uncontrolled Uncontrolled lb/MMBtu Ib/MMscf (Fuel Heat Combusted) (Fuel Consumption) Emission Factor Source PM10 0.00745098 7.674509804 AP -42 Table 1.4-2 (PM10/PM.2.5) PM2.5 0.00745098 7.674509804 AP -42 Tab₹e 1.4-2 (PMIO/PM.2.5) AP -42 Table 1.4-2 (SOx) AP -42 Table 1.4-1(NOx) - (<100MMatu} tow . SOx 0.000588235 0.605882353 NOx 0.049019608 50.49019608 CO 0.082352941 41.2 Manufacturer AP -42 Table 1.4.2 (VOC) AP -42 Table 1.43 (Formaldehyde) AP -42 Table 1.4-3 (Benzene) AP -42 Table 1.4-3 (Toluene) AP -42 Table 1.43 (n -Hexane) VOC 0.005392157 5.553921569 Formaldehyde 7.35294E-05 0.075735294 Benzene 2.05882E-06 0.002120588 Toluene 3.33333E-06 0.003433333 n -Hexane 0.001764706 _ 1.817647059 Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 SOx NOx CO VOC 0.54 0.54 0.Y. 0.54 0.54 91 0.54 0.54 0.54 0.54 0.54 91 0.04 0.34 0.04 0.04 0.04 7 3.54 3.54 3.54 3.54 3.54 602 2.89 2.39 2.89 2.89 2.89 491 0.39 0.39 0.39 0.39 0.39 66 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Formaldehyde 11 11 11 11 11 Benzene 0 0 0 0 0 Toluene 0 0 0 0 0 n -Hexane 255 255 255 25`, 255 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit Regulation 1, Section VI Based on the requested emissions and emission factor, compliance is presumed. Regulation 1, Section III & Regulation 6, Part B, Section II Based on the design heat input rate, the source is subject to Regulation 1 Section III.A.1.b. and Regulation 6, Part B, Section II.C.2. and 3. based on the requ Regulation 6, Part A, Subpart Db, 502 Standards Source is not subject to NSPS Db. Regulation 6, Part A, Subpart Db, NOx Standards Source is not subject to NSPS Db. Regulation 6, Part A, Subpart Dc Source is subject to NSPS Dc. Regulation 7, Section XVI.D Source is not subject to Regulation 7, Section XVI.D. Regulation 8, Part E, MACT Subpart DDDDD Source is not subject to MACT DDDDD. 41 of 76 K:\PA\2019\19WE0081.CP1.xlsm Natural Gas Heater Emissions Inventory �See regulatory applicability worksheet for decailed a natysis) Section 07 - Initial and Periodic Samplin¢ and Testinx Requirements Istheprojec[ closetothe90ipymodeling / NANSRLhresholdforNOx7 `�� .°�;#' ?' .,n�;'u"� cf �: � �� If yes, scack-tes[ing should be required for NOx, as well as for CO. Is the operator limking their heat input rate below the design rate? i "i�" >hx ?}+qss Wwmar:+nf4 ..A .mV>`v...,_ If yes, stack-testing should be required for NOv, as well as for CO. Istheprajectclosetothe5tpymodeling [hresholdforPM2.5? �'''{�'c'4i � �% . __., 'se'c'�`-� `_: If yes, stack-testing should be required for PM 2.5 Does the wmpany use AP-42 emission factors �or more wnservative fac[ars)7 . . ' If no and testing hasn't already been required due to proximity to modeling thresholds, testing should he required for any pollutants forwhich altemative emission facmrs have been used. IFtesting is 6eing done for only NOx or onty CO, [he other should be included as well. Section OS - Technical Analysis Notes � SourcedaimsamanufaccurerspeczheetforCOemissiontacrorof411ib/mmscf (AP42is841b/mmscf), butsourcehasnotzpecified [hemanufacturerormodelinlheAPENorelsewhere, orprovidedanyspecsheet. � Therefore, thisheaterandanyo[herheaterusingthisemissionfacmrshallberequiredtostacktesiforCO, andincidentallyforNOx. � . ' . . . . . . . . . � . . . . . ,. . .. . .. . . . ; � . . . . . �. .. y . . . . . . . . . . . . . . . . . ; �. . � . ,. . � � . . . . � , , ; � � � � . � � . , . . . . . . , i , . . . . . , . . € � � . . . . . . . . . . ,. . - . 3 � . . . . �. . . . . . . . � . . ; . . . . . .. . . .. . . ,, _ . .. ,. . . . . . . i - . . ., . . . . . _ � . � . � . :� . � . . . . . . � � � j . . � . . . .. �. . . . . . . . � � . � . . . . . . . . . � .� . . . . . . . . . , Section 09 - I nve�tory SCC Codine and Emissions Factors Uncontrolled Emissions AIRSPoint # Processk SCCCnde Pollutant FaRor Control % Unks 010 Ol 3-10-0040C: Indusirial Process; Oil & Gas Production; Process Heaters: Natural Gas �MMscf) PM10 7.67 0 Ib/MMscf Burned PM2.5 7.67 0 Ib/MMscfBurned SOx 0.61 0 Ib/MMscfBurned NOx 50.49 0 Ih/MMscf Bumed CO 4110 0 Ib/MMs<f Bumed VOC 5.55 0 Ih/MMscf Burned Formaldehyde 7.SIE-02 0 Ib/MMscf Burned Benzene 2.12E-03 0 Ib/MMscfBurned Toluene 3.43E-03 0 Ib/MMscfBurned n-Hexane 1.8 0 Ib/MMscfBurned 42 of 76 K:\PA\2079\39WEOOSS.CPl.xlsm Natural Gas Heater Regulatory Analysis Worksheet CQIOrad Rag Based on the Mater purpose selection in the inventory, this unit qualifies as h tail burning egtttpnert per Colorado Regulation I & 6, a steam tenanting ,nit per ^iSPS Db B Cc ar-I a industrial. commerdel or institutional boiler or process heater per MACT 00000 This unit fires natural gas ea defined by NSPS Db & Dc and/or is designed to bum gas 1 f unit a defined by MALT 00000 lation 3 Parts A and B • APEN end Permit Requirements So✓ca is ;n the Attainnteir are♦ ATIAINMINI 1. Are uncontrolled actual emissions of any criteria polutanu from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1 a)? 2. Does the heater have a design heat input rate less than or equal to S MMBtu/hr? (Regulation 3, Part A, Section II.D.1.k.) 3. Does the heater have a design heat ripe rate less than or equal to 10 MMBtu/hr? (Regulation 3, Part B, Section ii.D.l.e.) 4. Are total facility uncross roiled VOC emissions grater than S TPY, NO: greater than lO TPY or CO emissions greater than 10TPY (Regulation 3. Part B. .ect rani 1.0.3)7 SOiece raquifes a per tot Its KIN -ATTAINMENT 1. Are uncontrolled emissions of argentine polkitares from this indl idual son greater than 1 TPY (Regulation 3. Part A, Section 1I.D.1.a)? 2. Doe the heater have a design heat Input rate less than or equal to 5 M Metu/M? (Regulation 3, Part ASection II.D.l.k.) 3. Does the heater have a design heat Input rate less than or equal to 10 MMBtu/hr? (Regulation 3. Part B, Section II.D.1.e.) 4. Are total facility Inca*roll d VOC emissions greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 10 WY (Regulation 3, Put B, Section 11.02)? You have indicated that source is in the Atranere^t A -e Colorado.Rnnu)ation 1, Section V( 1 Are sulfur dice 'de emissions from the heater greater than 2 tons per day? (Regulation 1, Section N.B.S.e.) IBased on the requested emissions and emission factor, compliance is presumed. Section VI 5.5 - Emission Units Section VI.6.6 and 7 - Recordteeping, Reporting, Data Retention CQierodo_RenittioaltaketIllnifsleutheittmolatIon_LAMILkstionandattlasitsthirmeathattelstot 1. What is the design heat input rate of the heater? (Regulation 1. Season I I IA and Regulation 6, Part B, Section LC) 2 Does the sane discharge particulate matter in excess of OS tb/Mmhtu heat input? (Regulation 1, Section III.A.l s. and Regulation 6, Part B. Section lSC.1J 3. Dots the source discharge particulate matter Si excess of the following equation: PE a 03(R j-"'? (Regulation 1, Section XIA1 b. and Regulation 6, Put B, %Mon it. Doe the source discharge particulate matter in aces of 0.1 Ib/Mmteu heat input? (Regulation 1. Section!!lefts.) Based on the design heat input rate. the source Is sublet, to Regulation 1 Section 111 A.i b. and Regulation 6, Part 5, Section lt.C2. and S. Bawd on de requested emissionfactor, complete le presumed. Colorado Regulation 7. Section XVI& 1. Did the natural gas fired heater exist at a major source of NOt as as of lune 3,2016? (Regulation 7 Section XVt.D.1.) 2. Does the natural gas fired heater have unroMrolled actual emissions of Neer equal to or greater than S tpy? (Regulation 7 Section !Source is rot subject to RagJadon 7, Section *VI.D. Section XVLD.B.b. —Combustion Process Adlustnert Section XVLD.7. — Rexvdkeepblg NSPS Analysis 1. Does the natural gas fired heater have a maximum design heat input capacity of 29 megawatts (MW) (100 MMBtu/hr) or less- but greater than or equal to I.9 MW (IOM MStu/hr)? (§60.40c(a)) 2. Does the natural gas fired heater have a maximum design heat input capacity treater than 29 mesa%atts (MW) (100 MMBtu/hrl? (§60.40b(a)) IEvaluate questions in NSPS Cc section be'aw 40 Ci R. Part 60. SubpatttjtendLSgf,M1iformerw for Snell bndustriaKornmgttlifinfkutlons(9lsarnSt anniOtt)nin 1. Did construction, modification, or reconstruction of the steam generating unit commence after June 9, 1989? (f60.40c(a)) Source et subject to N5PS Dc Subpart A, General Provisions §60.48c - Reporting and Recordkeeping Requirements 1st No fl Source Requires an APE. Go to the nIn guesnon Go to the nn question. Go to the ned question. Source Respires a permit Go to the neat queuion Go to the red question Nov ! Used on the requested ens salons end relation factor. compliance is presumed. Co to question 3. R4 se on the req uesten •mission factor compliance is presumed .:edam the requested emission factor. compliance is presumed :e d on the requested emission factor. cornpllam is [resumed pillSource is not subject to Regulation 7. Section XVI.D. Go to NSPS Oc apoi icabitity season Source is not u.bjaa to NSPS Db Source is subiect to NSPS Dc. 40 CM Part eubaart 06. Standards of nadarmanca for lM.ral.0 I. Oldronstructon, m�..., or reconstruct. Men mean tong un0 commence afterlunel3,1604?)§3aa06(a6 SOESearnian2. Does the al gas firedheaterhauea potential:oz el -Madan rate 01400 /1(0a7Ib/MM3tu) heat input orIessi)§an.uabp)(4l) 3. 4d the affectedfaddycommence netructre,.Ieconstrauonor modmation akvsebruary>B.>o4s,(4004abt4(t) le 4. Dm the natural gas red beater have Feat rapt amctyof73 Mw 5x50 MMetu/hd4rlea71440.446141) 5. Does the >thdtollomnsmtab7(36a.443A1) sa. mmbnst,a,one or,n combination, only natural gas. ...Wale al.ermdua! oa walla naroeen content 0,6.3 wereFt percent ar,ess1M0.4461n1x11: 56. Nave a cambric., annual capactyeaa044peamatessr0rmtaal gas, drnlllaaml, andmrdual 01)4404 a nitrogen contem00.30welght percent orressl§60.4466141;an esubtea to afMeraIly enfowble requlrementhmrungmeatroo of the affwtedraAMrotefIdngo,natural gas,d64Alateail,and/nmrdualmmho nitmgenmlrtmrofo30 content pen orl4s nd llmalogaperatrm 460))31) end Acityroa mmWnei annul eaWaty Actoref10 pewltarlssfanatunl gas,distliate 04,and remm,odwnlh antmgen Weight percent w Iess. 1440.44bp11311 6. 04140 affeted belay mm nafter,*09.1967?(§30.6646) Is the natualgasnlei heatersubt<434 sand innr4mplrartadmF a federally enforceable requirement that limas operation >ehefanlity loan annual apanty factor of to paced 10.x01 orl6ms for cwl.al,and natural gas(or anyambmavan&the three), I§a0.44b66.6 Does tM1eater a.elowheat release rate and combust natural gas ardttillateoil Imeceees a 30 percent of the Feat input on a 30 -day mine awragetmm the wmbunion oral, rm6,1§po.4460,160 r� Source is notsubfacem 446506. 664Axgk111) • Standard forsulfw droudalsve) 640.44aaI4r 161 arg41F1 and 16 orll -s oxides 16,04 666.4 5.6 and ronorm.�.eertmaModsane,� procedures .ftlmeam matter and narneano.rdes 460.476 -emission monitoring for sulfa dioxide 434466 p1) , and mmrdimeprg requirements MACT analysts as em. Part 63 subpart MAcio400o i¢wp for War sources. bdme. mmmarda6 and lnaghrtioar Balers and 6mams H6ame 1. Is the heaterIomted at afaeiy that m45454 rmfor HAN, 453.7465) a0466>494)04 cerewmatuctC,)463.>4s01g10 heater commence a16144064, 20147 pa754IDOthonor equal to6 MMOm5rf (463.4644(44 4. Is thenmtto, m4 404reate,thansr4416704 but less than orwua, tale Mn4iu/Fr>)443.>64ien §33.4500)=1 and Tab,e3 won practicesta6dards 663.756564-0 466.714141-Imtlarequirements f4.oraIstig mums 0g33.>510 EEO formasawm 666.7541611 -Subsequent testa,fuelaalymortaneum 663,536 6,1and lFl- )emonttaune chicmmprance §43.>s64 Wag) and M,23)-4 a1,Ck §33.4456),) nor adsnm 670.167 n.wl.64.1011 =161. =01.=161-xamanom §63.745544146(),I d)41,FI31•.04444 663.7655K MI) and 111 and 33.75301a1.lbland fit keagm Disclaimerdocument assists opera's,' MO appliaadley ofcertainregdVamenh of me his dclean 44405 ifs implanwrtirg regulations, and Air Quality Cord. Commission This document. sof a rule crieguk44 emithe 0, I6sls it =Maim may not apply to a 4067lar situation Miser/ upon the Individual facts ar subs4N(e(wanylew, regukfiC4 rany °Ds,mkgaly Sind.ssqui35474. iDDDD In fhe eyelid any tro1165 =lies., Me language alts document and Me language stem clean Air Pct, ifs enplement6gregulatiens, anda6oua4tycmWl Commission an 3040 ofthe6101310 or reg.. Will control. Theof Melanguage such as'recomm&M.'"may,'"she.W,' and tan.' mbeCFC0 inferprefalbns and recommerda5es. Marc/aim y terminology such as "must' and174770 0 are intended lc describe c ..Deem isquiram's Ls ande-the ...IT al Me Clean Ab Act end Ab P.Ily Control commission regu6wrs; ant this document does col eslahlisn legally hireling miuimirants in amides. me wtenaesu6Aato coon. r efammmu4tcord. a m16,63..666. Natural Gas Heater Emissions Inventory 008 NG Heater 'Facility AIRs ID: 123 ?,;;' ;. 011 County Plant Point Section 02 - Equipment Description Details Heater Information Fuel Type Number of Heaters Purpose Make: Model: Serial Number: Design Heat Input Rate: Equipped with Low-NOx burners: Equipped with Add -On Control Equipment: Natural Gas One (1) MMBtu/hr Btu/hr One (1) natural gas heater(s) (Make: TBD, Model: TBD, Serial Number: TBD) each with a design heat input rate of 55 MMBtu/hr. Each unit is equipped with low-NOx burners. Each unit is an amine regeneration heater. Detailed Emissions Unit Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: Section 03 - Processing Rate Information for Emissions Estimates Design Heat Input Rate = Heat content of waste gas = Actual Hours of Operation = Requested Hours of Operation = Requested heat input rate = Actual Fuel Consumption = No add-on control equipment Low NOx combustion system is considered an integral control device. 55.0 MMBtu/hr 1030 Btu/scf 8760 hrs/year 8760 hrs/year -31,800.00 MMBTU per year MMscf/year Requested Fuel Consumption = 4b 7.c MMscf/year Requested Monthly Throughput = 39.7 MMscf per month Potential to Emit (PTE) Fuel Consumption = Section 04 - Emissions Factors & Methodologies 367.77 MMscf/year Emission Factors Natural Gas Heaters Pollutant Uncontrolled Uncontrolled lb/MMBtu lb/MMscf (Fuel Heat Combusted) (Fuel Consumption) Emission Factor Source PM10 0.00745098 7.674509804 ';'M:0/PM.2.5) AP -42 'ai .. <-2(PM10/PM-2.5) AP -42 Table 1.42 SSOt) AP-42Ta' #e L.4-1 (Ni3:t; ,,'OM:7'y b ; t >'.,. PM2.5 0.00745098 7.674509804 SOx 0.000588235 0.605882353 NOx 0.049019608 50.49019608 CO 0.082352941 41.2 Maw.;factuter AP -42 Tab#t 1A-2 (VOCJ.. AP -42 Table 1.4-3 Forrwaidehvt$e& AP -42 Table 1.4-3 (Benzene) .AP -47. Ta;isz'e ,4 3 f Tok erte) AP-421'atife, L4-3 (n-1,#exta v) VOC 0.005392157 5.553921569 Formaldehyde 7.35294E-05 0.075735294 Benzene 2.05882E-06 0.002120588 Toluene 3.33333E-06 0.003433333 n -Hexane 0.001764706 1.817647059 Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 1.79 1.79 1.79 1.79 1.79 305 1.79 1.79 1.79 1.79 1.79 305 SOx 0.14 0.14 0.14 0.14 0.14 24 NOx 11.81 11.81 11.81 11.81 11.81 2006 CO 9.64 9.64 9.64 9.64 9.64 1637 VOC 1.30 1.30 1.30 1.30 1.30 221 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Formaldehyde . , 35 35 35 . ) Benzene 1 1 1 1 1 Toluene 2 2 2 2 n -Hexane 55: 850 850 850 850 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit Regulation 1, Section VI Based on the requested emissions and emission factor, compliance is presumed. Regulation 1, Section III & Regulation 6, Part B, Section II Based on the design heat input rate, the source is subject to Regulation 1 Section III.A.1.b. and Regulation 6, Part B, Section II.C.2. and 3. Based on the requ Regulation 6, Part A, Subpart Db, SO2 Standards Source is not subject to NSPS Db. Regulation 6, Part A, Subpart Db, NOx Standards Source is not subject to NSPS Db. Regulation 6, Part A, Subpart Dc Source is subject to NSPS Dc. Regulation 7, Section XVI.D Source is not subject to Regulation 7, Section XVI.D. Regulation 8, Part E, MACT Subpart DDDDD Source is not subject to MACT DDDDD. 45 of 76 K:\PA\2019\19WE0081.CP1.xlsm Natural Gas Heater Emissions Inventory (See regulatory applicability worksheet for detailed analysis) Section 07 - Initial and Periodic Sampling and Testing Requirements Is the project close to the 40 tpy modeling / NANSR threshold for NOx? If yes, stack -testing should be required for NOx, as well as for CO. Is the operator limiting their heat input rate below the design rate? If yes, stack -testing should be required for NOx, as well as for CO. Is the project close to the 5 tpy modeling threshold for PM 2.5? If yes, stack -testing should be required for PM 2.5 Does the company use AP -42 emission factors (or more conservative factors)? If no and testing hasn't already been required due to proximity to modeling thresholds, testing should be required for any pollutants for which alternative emission factors have been used. If testing is being done for only NOx or only CO, the other should be included as well. Section 08 - Technical Analysis Notes Source claims a manufacturer spec sheet for CO emission factor of 41.2 Ib/mmscf (AP42 is 84 lb/mmscf), but source has not specified the manufacturer or model in the APEN or elsewhere, or provided any spec sheet. Therefore, this heater and any other heater using this emission factor shall be required to stack test for CO, and incidentally for NOx. Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 011 Uncontrolled Emissions Process # SCC Code Pollutant Factor Control % Units 01 3-10-004-04: Industrial Process; Oil & Gas Production; Process Heaters; Natural Gas (MMscf) PM10 7.67 0 lb/MMscf Burned PM2.5 7.67 0 lb/MMscf Burned SOx 0.61 0 lb/MMscf Burned NOx 50.49 0 lb/MMscf Burned CO 41.20 0 lb/MMscf Burned VOC 5.55 0 lb/MMscf Burned Formaldehyde 7.57E-02 0 Ib/MMscf Burned Benzene 2.12E-03 0 lb/MMscf Burned Toluene 3.43E-03 0 lb/MMscf Burned n -Hexane 1.8 0 lb/MMscf Burned 46 of 76 K:\PA\2019\19WE0081.CP1.xlsm Natural Gas Heater Regulatory Analysis Worksheet Rased on the heater purpose selection in the Inventory, this unit qualIfies as fuel burring equipment per Colorado Regulations 1 & 6, a steam pneradng task per NSPS Db & Cc and • 6dtstrial, co minim's' or institutional boiler or process heater per MACT 00000 This unit hires natural gas as defined by NSPS Ob & Dc end/or is designed to bum gas 1 fuels as defined by MALT DOODD n 3 Parts A and Re uirements o n the Atta:natant Area ATTAINMENT I. Are uncontrolled actual emissions of any criteria pollutants from this individual source greater than 2 TRY (Regulation 3, Part A, Section II.D.1.a)? 2. Does the heater have a design heat input rate less than or equal to 5 MMBtu/hr? (Regulation 3, Part A, Section 11.0.1.k.) 3. Does the heater have a design heat Input rate less than or equal to 10 MMBtu/hr? (Regulation 3, Part B, Section II.D.1.e.) 4. Are total facility uncontrolled UDCemissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TRY (Regulation 3. Part B. Section 11.0.3)? Source requires a permit NON -ATTAINMENT 1. Are uncontrolled emissions of any criteria pollutants from this Individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Does the heater have a design heat input rate less than or equal to 5 MMBtµthe? (Regulation 3. Part A. Section II.D.1.k.) 3. Does the heater have a design heat input rate Ins than or equal to 10 MMBtu/hr? (Regulation 3, Part 8, Section II.D.1.e.) 4. Are total facility uncontrolled VOCemissions greater than 2 TPY, NOx greater than 5 TPY or CO emissions grater than 10 TPY (Regulation 3, Part B, Section 11.02)? You have indicated that source is in the Attainment Area CcJorado ReeuWton 1. Sedlon VI 1. Are sulfur dioxide emissions from the heater greater than 2 tons per day? (Regulation 1, Section VI.85.a.) 'Basal on the requested emissions and emission factor, compliance h presumed Section Vl.B3 -Emission Urn Its Section VI.6.6 and 7 - Recordkeeping, Reporting, Data Retention Cotordo egulatipnL Section III and Color o Regulat(orn_¢ pentl sSlonll..itandlyds of Performance for New Fuel-Burnina_Egstiyment I. What is the design heat input rate of the heater? (Regulation 1, Section III.A. and Regulation 6, Part 8, Section II.C.) 2 Does the source discharge particulate matter in excess of 05 b/Mmbtu heat input? (Regulation 1, Section IIIA1a. and Regulation 6, Part B, Section II.`.1.) 3. Does the source discharge particulate matter In access of the following equation: PE a 03 (Fl f 2 '? (Regulation 1, Section III A1.b. and Regulation 6, Pat B, Section II.C2.) 4. Does the source discharge particulate matter in excess of 0.1 b/Mmbtu heat input? (Regulation 1, Section IIIA1.c.) eased on the design heat input rue. the source Is subject to Regulation 1 Section IRAS.b. end Regulation S. Part R, Section h.C2_ and 3 Said on the requited emission fade compliance is presumed. COktredgligndelionlilitalonlYhtl 1. Did the natural gas fired heater exist at a major source of NOx as as of June 3, 2016? (Regulation 7 Section XVI.D.1.) 2. Does the natural gas fired heater have uncontrolled actual emissions of NOx equal to or greater than 5 tpy? (Regulation 7 Section XVI,Db,a.) (Source is not subject to Regulation 7. Section XVI.O. Section XVI.D.6.b. —Combustion Process Adjustment Section XVI.D.7. — Recordkeeping NSPS Analysis 1. Does the natural gas fired heater have a maximum design heat input capacity of 29 megawatts (MW) (100 MMBtujhr) or less; but greater than or equal to 2.9 MW (.0MM8tu/hr)? (§60,40c(a)) 2. Does the natural gas fired heater havea maximum design heat input capacity greater than 29 megawatts (MW) (100 MMBtu/hr)? (§60.40b(a)) Evaluate questions in NSPS De section below. 4CFR, Part 6C Suboert Do Standards of Performance for Smell Industr1al-Comma rciallnstltutione15tsem_Genetatirw Unb 1. Old construction, modification, or reconstruction of the steam generating unit commence after June 9, 1989? (460.40c(al) Source is subject to NSF'S Dc Subpart A, General Provisions §60.48e - Reporting and Recordkeeping Requirements Source naquires an ADEN. Go to the newt question Go to the non question. Go to the nen question. Source Requires a permit Go to the next question. Go to the next question. No I Based on the requested emissions and emission factor. compliance Is presumed. Yes No Go to question 3. Based on the requested omission factor, compliance is presumed Based on the requested a mission factor, compliance is presumed Based on the requested emission factor, compliance is ere -turned Source is cot subject to Regulation 7. Section XVID. Go to NSPS Dc applicability section Source is not subject to NSPS Db Source is subject to NSPS Dc. 40.74 Nrt 10042 424�.rds. dorm. ndaalel�mme�.l0,2,26426lxeema.n.�xrex 1. �fiallon,w,c.nuunlondtxezteam geers.6 onamnmmce.v1°2619,1960(45u.45614)1 2. o4eathe natural beateamkapaaNlal.o:eelss,anrare of3.4onv,I63alb/MMatulheat Input r nl44a.4=blaau 150u -eels notsubiott to MPS.. rda 0. Ones lgasxredheaterhau,aheatInpurea4 4of-MMWnse0 atumrloNaa:lsaa.4461kn 5. Does theheatermeet011! .the kllxmng nite,4,14504401411 501. Combust. alone aInamdnallom only natural gas. din11.1545,a,240.l ell wit. a nrtmeemmotent 00.5 weight =mentor leaf 145o.44d1111111 56. Have a combined ana1460504fado' ell5 percent ales, fornatual gas,dlsllllatadl,es4101dual nil with amtmgen contentdaaa welBh, p40e,norleu 1450.444111(211: and Aresubfecttaa fedeng'y'MmeableagWamntllmhlng�operatiu ofthe affected facAlty m thel0ing d,aturalgas.d.IllateoA.anglartzldual all with mgamd4a13 ha Nref0 weight pemmr orless a',Iimhln xa4dtheaffcacAhrytaa ambled annul capacity factadl5 percentcr.,anatunlga,d6.ateo1. and rm.wl eawM a Nrmgn Sc. content of 030 weight prcentaless.(455.w0101311 6. OW theaffm raalitymmmencemmw¢lea, rm2vuvn amoAgodon aftntury0,19977 (§60.446(0) rers040en to and In a,npllamewnh a (*talk edorceaderegu6enent that limes op atfm of.efawtyaan alma! opacity factor dl5 p,ce t(0.10)erlas la Is onatural ."d".iroa1 q. to am am6MatM of te.reap (60.4441)nu Does a0dosreedheaterha.elasheat ,eafeateamtomb.nataalgasaa6nlateaem,.aessd5o penentdm. heat «„m,na50-aaymllingaaerageeemtlem,nmatfarelall ise.o.e rotadafeeu tars m. 535.4:4441111 -standard k1 sulfur dlodde Ism! 454.444441411414, 101 Inland IA arm- Standard for nhroc.noddex*Nat 430.40 -.mean .andperformance testrnehansann procedures for mlurdioxide 450.471, Emission menItoring for sulfur 4!014!40 434366. Emission monitoringfo.0] .61 mater and nitra.ane.ldaa 4.362.4ewrtie nmN end 4oep.ro ul.emen6 MALT Analysis aoaa Pare. subpart 5un00000 NOVA. for Malarsomces: Indatdd, m,nmarda4 and Impttghwl eioll.nand pman kraac afa0T,ty4hataa maicsouR for HAW 1453.24551 Z. Old maw (4012:7455161) a,40,44010400063.799.10). lotea pammeaee axeazuw 4.5o1ax 3. is the ®eat npdaSewyleasthana aqua! to MMatu(6R 14x.4555144 4. Is the heath o 1 Mat'044 a s than wult0 t04405lt✓ai 14x3540101 amLeeu 455.7SCO andTable3-Work paNastandards 465.25551.1 -Genera I eau laments 4s5.5s4ol.l-Inrtnlag emnetfereaetingawr�05xmxolglfa„4azm,as 465.5515141-subsewem tests,tud analnesa026513 a 455.2501.1 and m - �momtrd ing Int.! mm 40ana 455,25451elllol and (403)-o mm.lan 455.25451.), I1• for existing e•I or 0103 s41o1111.1s1,.ry6.1e1-xn5larnm 465.4551.1, 161.14,14411, .54l • ga wnlre 05.155551.1, NM and (4End 53.2560 IOW end 10...eeOne fitslaimer Occurrent asisfsope-etas 1010 d4(emni4gapp a.tyofmila4 te}irem4010d4he .Man AMA..@tmloto enlug Moto . 600*0l At..bol Commission '04. This documet'smf a4Wev1eg,da550 and doe arwNsis dcarlaianar401 001[432442uslnn 40402 upon the udnNVWlacls .Imam This document does nor change. 0 0244 40 41016114lair.me4111.404 many 4ttagmo.6 lydt35g 4ap0604341 and Islegally 6*f4l de. In Me ant. any =Mae.. Om language 4f Ms document a40 the language 01!44 Cka0 N Act, its enp2emenb0g rgWabau, 4,224 005104 C00401 cormrission regulations, lntap d cm., The nue nommtamlatory APCOne1N 04 ardrecomen0deflmw.Mandatoy Innlieloyysuch 05 "moor and oe'aqu6Meta Mlandod M doom em 401404 is intend.. descan,' requnts under Ma beau d Me Clean Air Acton2nir 0ua12y Control C4mmisoMnregulafiau, but this document does not establish legaly Wld144444miremenfs in ndnads. Natural Gas Heater Emissions Inventory 008 NG Heater 'Facility AIRs ID: 123 A020 County Plant 012 Point Section 02 - Equipment Description Details Heater Information Fuel Type Number of Heaters Purpose Make: Model: Serial Number: Design Heat Input Rate: Equipped with Low-NOx burners: Equipped with Add -On Control Equipment: Natural Gas Mno Ski teeter `. One (1) MMBtu/hr One (1) natural gas heater(s) (Make: TBD, Model: TBD, Serial Number: TBD) each with a design heat input rate of 18 MMBtu/hr. Each unit is equipped with low-NOx burners. Each unit is a hot oil heater. Detailed Emissions Unit Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: Section 03 - Processing Rate Information for Emissions Estimates Design Heat Input Rate = Heat content of waste gas = Actual Hours of Operation = Requested Hours of Operation = Requested heat input rate = Actual Fuel Consumption = No add-on control equipment Low NOx combustion system s considered an integral control device. 18.0 MMBtu/hr 1030 Btu/scf 8760 hrs/year 8760 hrs/year 157,680.00 MMBTU per year MMscf/year Requested Fuel Consumption = MMscf/year Requested Monthly Throughput = MMscf per month Potential to Emit (PTE) Fuel Consumption = Section 04 - Emissions Factors & Methodologies '5s (::9 MMscf/year Emission Factors Natural Gas Heaters Emission Factor Source Uncontrolled Uncontrolled lb/MMBtu lb/MMscf Pollutant (Fuel Heat Combusted) (Fuel Consumption) PM10 0.00745098 7.674509804 AP -42 ..4r2 # ' Tel •:%/F'.3ri. . PM2.5 0.00745098 7.674509804 rP-42 Tabie 1.4.1(PM10/PM.2.u'f AP -42 Table 1.4- (Sex) AP -42 Table 1.4-1 fsithi.)- ("1:0MM&tit) Low NOx ani,:f:-:c:':sres 2-4a s"nH;' 1.42 (VOC) SOx 0.000588235 0.605882353 NOx 0.049019608 50.49019608 CO 0.082352941 41.2 VOC 0.005392157 5.553921569 Formaldehyde 7.35294E-05 0.075735294 "-42 Tabie 1.4-3 (Forama!d flvd') AP -42 Table 2.4-3 (B'T•s''zene) AP -42 Table 1,4-3 ( Foltiene•} Benzene 2.05882E-06 0.002120588 Toluene 3.33333E-06 0.003433333 n -Hexane 0.001764706 1.817647059 AP -42 T*-bie 1.4-3 (n -Ryan ) Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 0.59 0.59 0.59 0.59 0.59 100 PM2.5 0.59 0.59 0.59 0.59 0.59 100 SOx 0.05 0.05 0.05 0.05 0.05 8 NOx 3.86 3.86 3.86 3.86 3.86 656 CO 3.15 3.15 3.15 3.15 3.2 536 VOC 0.43 0.43 0.43 0.43 _ 0.43 72 Hazardous Air Pollutants I Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Formaldehyde 12 12 12 12 12 Benzene 0 0 0 0 0 Toluene 1 1 1 1 1 n -Hexane 278 278 278 278 278 ction 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit Regulation 1, Section VI Based on the requested emissions and emission factor, compliance is presumed. Regulation 1, Section III & Regulation 6, Part B, Section II Based on the design heat input rate, the source is subject to Regulation 1 Section IIl.A.1.b. and Regulation 6, Part B, Section II.C.2. and 3. Based on the requ Regulation 6, Part A, Subpart Db, 502 Standards Source is not subject to NSPS Db. Regulation 6, Part A, Subpart Db, NOx Standards Source is not subject to NSPS Db. Regulation 6, Part A, Subpart Dc Source is subject to NSPS Dc. Regulation 7, Section XVI.D Source is not subject to Regulation 7, Section :(VI.D. Regulation 8, Part E, MACT Subpart DDDDD Source is not subject to MACT DDDDD. 49 of 76 K:\PA\2019\19 W E0081.CP 1.xlsm Natural Gas Heater Emissions Inventory (See regulatory applicability worksheet for detailed analysis) Section 07 - Initial and Periodic Sampling and Testing Requirements Is the project close to the 40 tpy modeling / NANSR threshold for NOx? If yes, stack -testing should be required for NOx, as well as for CO. Is the operator limiting their heat input rate below the design rate? If yes, stack -testing should be required for NOx, as well as for CO. Is the project close to the S tpy modeling threshold for PM 2.5? If yes, stack -testing should be required for PM 2.5 Does the company use AP -42 emission factors (or more conservative factors)? If no and testing hasn't already been required due to proximity to modeling thresholds, testing should be required for any pollutants for which alternative emission factors have been used. If testing is being done for only NOx or only CO, the other should be included as well. Section 08 - Technical Analysis Notes Source claims a manufacturer spec sheet for CO emission factor of 41.2 lb/mmscf (AP42 is 84 Ib/mmscf), but source has not specified the manufacturer or model in the APEN or elsewhere, or provided any spec sheet. Therefore, this heater and any other heater using this emission factor shall be required to stack test for CO, and incidentally for NOx. Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 012 Process # SCC Code 01 3-10-004-04: Industrial Process; Oil & Gas Production; Process Heaters; Natural Gas MMscf) Pollutant PM10 PM2.5 SOx NOx CO VOC Formaldehyde Benzene Toluene n -Hexane Uncontrolled Emissions Factor 7.67 7.67 0.61 50.49 41.20 5.55 7.57E-02 2.12E-03 3.43E-03 1.8 Control % Units 0 Ib/MMscf Burned O Ib/MMscf Burned 0 lb/MMscf Burned 0 lb/MMscf Burned 0 lb/MMscf Burned O lb/MMscf Burned 0 lb/MMscf Burned O lb/MMscf Burned O lb/MMscf Burned 0 lb/MMscf Burned SO of 76 K:\PA\2019\19WE0081.CP1.xlsm Natural Gas Heater Regulatory Analysis Worksheet Based on the heater purpose selection in the inventory. this unit quaiiies as fuel burning equipment per Colorado Regulations 1 & 6.3 steam generating unit per NSPS Db & Dc and a industrial. commercial or institutional boiler or process heater per MALT 00000 This unit fires natural gas as defined by NSPS Oti & Dc and/or is designed to burn gas 1 fuels as defined by MACCT DOOM Colorado Re lion 3 Parts A and B • APEN and Permit Reautrements Source Is in the Attainment Area AITAIRMISI 1. Are uncontrolled actual emissions of any crteria pollutants from this Individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Does the heater have a design heat input rate less than or equal to S MMBtu/hr? (Regulation 3, Part A, Section li.D.1.k.) 3. Does the heater have a design heat input rate less than or equal to 10 MMBtu/hr? (Regulation 3, Part B, Section Ii.D.I.e.) 4. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 30 TPY (Regulation 3, Part B, Section 11.0.3)? Source requiresa permit NON -ATTAINMENT 1. Are uncontrolled emissions of any criteria pollutants from this Individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Does the heater have a design heat input rate less than or equal to 5 MMBtu/hr? (Regulation 3, Part A, Section 11.D.1.k) 3. Does the heater have a design heat Input rate less than or equal to 10 MMBtu/hr? (Regulation 3, Part 8, Section II.D.1.e.) 4. Are total facility uncontrolled VOC emissions greater than 2 TPY, NOx greater than 5 MY a CO emissions greater than 10 TPY (Regulation 3, Part 8, Section 11.02)? You have indicated that source is in the Attainment Area colored* Reaulationt Section VI 1. Are sulfur dioxide emissions from the heater greater than 2 tans per day? (Regulation 1, Section VI.B.5.a.) IBased on the requested emissions and emission factor, compliance is presumed Section 1/1.6.3 • Emission limits Section VL6.6 and 7 - Recordkeeping, Reporting. Data Reentton Colorado Regulation 1. Section III and Colorado Regulation 6. Part B. Section II. Standards of Performance for New Fuel -Burning Ea,lanent 1. What is the design heat input rate of the heater? (Regulation 1, Section IIIA and Regulation 6, Part B, Section 11.C.) 2 Does the source discharge particulate matter in excess of 0.5 b/Mmbtu heat input? (Regulation 1, Section IIlA1.a. and Regulation 6, Part B, Section II.C1.) 3. Does the source discharge particulate matter in excess of the following equation: PE • OS(FI)'M"? (Regulation 1, Section tllA1.b. and Regulation 6, Part B, Section II.C2.) 4. Does the source discharge particulate matter in excess of 0.1 lb/Mmbtu heat input? (Regulation 1, Section IIIA1.c.) Based on the design had input rate. the source Is subject to Regulation 1 Section 'ILA -Lb. and Regulation 8. Part B. Section ti.C2. and 3. Based on the requested emission factor. compliance is presumed. So).orado Regulation 7. Section XVLD 1. Did the natural gas fired heater exist at a major source of NOx ss as of June 3.2016? (Regulation 7 Section JM.D.1.) 2. Does the natural gas fired heater have uncontrolled actual emissions of Max equal to or greater than 5 tpy? (Regulation 7 Section J(V1.D.6.a.) 'Source is not subject to Regulation 7. Section XVI.D. Section JM.D.6.b. —Combustion Process Adjustment Section XVI.D.7.—Recordkeeping NSPS Analysis 1. Does the natural gas fired heater have a maximum design heat input capacity of 29 megawatts (MW) (100 MMBtu/hr) or less, but greater than orequal to 2.9 MW (10MMBtu/)r)? (§60.40c(a)) 2. Does the natural gas fired heater have a maximum design heat input capacity greater than 29 megawatts (MW) (100 MM8tu/hrl? Evaluate questions in NSPS Dc section below 40 CFR. Part 60. Subvert De. Standards of Performance for Small hdtstrlal-Commerclal-Institutional Steam Generating Ur& 1. Did construction, modification, or reconstruction of the steam generating unit commence after June 9, 1989? (§60.40c(a)) ISource is subject to NSPS Dc Subpart A. General Provisions §60,48c- Reporting and Recondkeeping Requirements • Source Requires an ADEN. Go to the neat question Go to the neat question. Go to the neat question. Source Requires a permit Go to to next question. Go to the neat question. No I Based on the requested emissions and emission factor. compliance Is presumed. yes No Go to question 3. Based onthe requested emission factor, compliance is presumed. Based on the requested emission factor, compliance is presumed Based onus requested emission factor, compliance is presumed. Source is rut subject x Regulation 7 Section XV r.D Go to NSPS Dc applicability section Source is not subject to NSPS Db. Source is subiect to PJSPS Dc. 40 a Subparen13.2rn.0FdarnmebrIN Generating ,2r(21 1. okgotknarreaau...orthes e re mnmanceafterguness,1330221560.40h(ell 2. 122.¢ naturalgas Esed terbatea late.tlal o4 enhslnateM144 (0.32,12/121M3to) beat Input arias, 14o0.4ab((ryll 3. qd lMaffected recommnlm ntce or moauw after rehruaa1s,g043i1ta0.414k11111 'Some is wsrwrenwpevsvb nlarda 4. sir oAed healer ',alma heal 12444442444417(2501.12t0/24w t13C2tu/hrl orlmrt4B0.44b(k1) S. Ones the Meatmen4J d the folloMn¢4,ne2i l4e0.440k11 sir. combust. alarm cr. tembinnlwu only natural ns, dmlllaxal,orre(ualan wltM1 a nnmpn content of 0.3 wekm percent orlaa 1.2.442,11112: sbs annual apecCv factor of 10 percent or,. Arnaural ps,Nanllaeal, and lcldualoilwnM1.2 nitrogen content Ma30 weight per orle.r14w.44bmun:..d nro.�ga eoaffm>ellrentoaable cequnemnt llmmnnopealon of the Waded fad', to thefNng d iatoalgas, detdateog and/erreldualdl wMa nitrogen cement 22030 weight per s andllmitingopmuon a 0440 tedfaeltyta a canbmel annual apaelty factor dap paren«les fun nut.algae, dlatnale all, and Rxiwl o2 wltM1, anroge 3s. mote. 413,30 2r;243t;cantor1..7 0.442,WD _ CAI the a ed.224am, er0ury0,12277 1424.440111 suhleom ampiance fm0011 ded«cn0 requ en that fun yau"onnrthen tenanal owdty faawdIC percent 1010)alas f« I�lm.e el oattun vs(oranyrombwt and fthe thme)t I4rm4404d11 W es Materhaelowbatmdaeeateanaeanbatnatural gas adgtaved,Inone.. paemtathetietlnpntone 3paayrelllnaaaeagefmmtheen of all 2.,21§...K212,1 � 13 4ublaa 320430 (131- 34.323,. fer 2wce dlexide (3713) 420.440.1ar10 ern rol and In er(f•34Nard ler nkmmn oxides INN 562.43b.mmmlent.aad eedo.na.teat nenedaand procedumaforWhir dle., 560.4 rand pros tae orpaaewaa matte rand nkrennc.c.s 560.456-EmisaAmexan fo�.,0m performance., w. 471 W AS, ErnInfon 'Mende ...raid nitrogen oxides 456.466 Pepamcg and romNM Ping',Wrenn. MAGI analysis s0 can Part 63 suborn Macr 0o000.x4(APAr Maioraauaee INten1.I.commercial. ad lmtItnloml Boller* and Process Heaters I. 1.12e4..exlemtecla 37aaby 1427 42 major 3o«aa 347x3437 (3233423) 2. tumn (3233430(0 7u 1 « re.TunAn 1563.7420(1 a heatermmmoce afterlu4,20102 3. X41.aapaayleatlanoregualto4 2422940/11,111.23.230a(01) 4, lathe heat input cain.22reater than S An2natu/hr Part les tM1an oretaalto as MMmupu)1283.73201.1 ISo 43,3.730224aMraue3-wakpankesanda. $3.7sas121-Goner trzquIremmts 293.7440fel-lea 010(4f« new sores 423.72041. -sir a0n ea ue3(431Meconwn�e �a 0335301e] al. 0 124131 3, 43„tating 2304 ampna race 563.734012113. and 12 4131-4enomtraing am buous amp1ance 563.73431., Ib-ler alsgm or for nnwl.10.1.120 ebl, 01.00-x«m«tnrs 423.23301.00.641..(21.031-304002 9.22.7555140 12441 acxilA v.233900(4121 analcl.PeeordkeedK Disclaimer nue arentassletsapealos ...r ig 43 apeliadil0ya7mbm requirements or be Clear rrnarkena43q Ma*. a«IAS 02394 Cane. urnenl is cot a rulesmgeda4an. ardlheaa(su if conic may432appry loap217374 rsawlbn based upon the a9rv403113als and circumstances. Th0 dxermo nl Cono change orsuerinute bray.,, regale.. aaMether b7 a2y tlinpraluva70nl en, erwllega4y On.... In Me Mail 440444en Me language ofthis 3xume71 am Inc brycape a( the Clean,i oat., its:nplerenling regulative. and Ws Ousels Conic C747773sen 7egulatons, Iebrguage2lthe statute crregublion will conker. The wear amnvnanaatery language such as 'recmvr474 trey."anau4; 373'43n' is Intend.bdesvbe A4GOMlegelalionsardraommerdatgss. Mmdato' leMrNagysuch as ',misread tease, are inleaded b describe c4nnelerg requirements m nlnda the alms arthe Clean Air Act and Ai Quality ContolCammusbe reg2blbas, but mu document does not abnlieh kpelybinding requiems. In d en an coq.¢te Mac,. Separator Venting Emissions Inventory Section 01 - Administrative Information 'Facility AIRs ID: 123 County A020 Plant 014 Point Section 02 - Equipment Description Details Venting of gas from pig receivers during depressurization. Detailed Emissions Unit Description: None Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: Limited Process Parameter Gas meter # of depressurization events No, compliance will be demonstrated based on number of depressurization events Section 03 - Processing Rate Information for Emissions Estimates Total Requested Number of Depressurization Events: 365 Events/receiver Length of pig receivers (each): Pressure of pig receivers: Atmospheric pressure: Vented volume from 6" receiver: Volume calculated by applicant: Vented volume from 8" receiver: Volume calculated by applicant: Vented volume from 10" receiver: Volume calculated by applicant: Vented volume from 16" receiver: Volume calculated by applicant: Primary Emissions - Separator Requested Volume Vented 9.5 feet 300 psig 312.12 psia 12.12 psi 1.865320638 48.03662356 49.89742042 3.316125579 85.39844189 95.97782318 5.181446217 133.4350654 158.96358 13.26450232 341.5937675 449.3517332 cf/event scf/event scf/event cf/event scf/event scf/event cf/event scf/event scf/event cf/event scf/event scf/event 0.3 MMscf per year 31 Requested Monthly volume vented = Section 04 - Emissions Factors & Methodologies Description Emissions are estimated using inlet gas composition as calculated using ProMax simulation with projected plant operating parameters. MW 22.28 Weight % Helium 0.00 CO2 4.51 N2 0.35 methane 52.31 ethane 17.80 propane 17.79 isobutane 1.54 n -butane 3.86 isopentane 0.66 n -pentane 0.70 cyclopentane 0.03 n -Hexane 0.24 cyclohexane 0.07 Other hexanes 0.02 heptanes 0.04 methylcyclohexane 0.04 224-TMP 0.02 Benzene 0.00 Toluene 0.01 Ethylbenzene 0.00 Xylenes 0.00 C8+ Heavies 0.01 Total VOC Wt % 100.00 25.03 Ib/Ib-mol Displacement Equation Ex=Q*MW*Xx/C J MMscf per month 53 of 76 K:\PA\2019\19WE0081.CP1.xIsm Separator Venting Emissions Inventory Emission Factors Gas Venting (TOTAL) Emission Factor Source Pollutant Uncontrolled Controlled (lb/MMscf) (lb/MMscf) VOC 14712.2071 14712.2071 Extended gas analysis Benzene 0.9406 0.9406 Toluene 7.6422 7.6422 Ethylbenzene 1.2345 1.2345 Xylene 1.8812 1.8812 n -Hexane 140.2641 140.2641 224 TMP 10.1700 10.1700 :ice Emission Factors Gas Venting (6" receiver) Emission Factor Source Pollutant Uncontrolled Controlled (lb/Event) (lb/Event) VOC 0.7341 0.7341 Extended gas analysis Benzene 0.0000 0.0000 Toluene 0.0004 0.0004 Ethylbenzene 0.0001 0.0001 Xylene 0.0001 0.0001 n -Hexane 0.0070 0.0070 224 TMP 0.0005 0.0005 Emission Factors Gas Venting (8" receiver) Emission Factor Source Pollutant Uncontrolled Controlled (lb/event) (lb/event) Extended gas analysis VOC 1.4120 1.4120 Benzene 0.0001 0.0001 Toluene 0.0007 0.0007 Ethylbenzene 0.0001 0.0001 Xylene 0.0002 0.0002 n -Hexane 0.0135 0.0135 224 TMP 0.0010 0.0010 Emission Factors Gas Venting (10" receiver) Emission Factor Source Pollutant Uncontrolled Controlled (lb/event) (lb/event) Extended gas analysis VOC 2.3387 2.3387 Benzene 0.0001 0.0001 Toluene 0.0012 0.0012 Ethylbenzene 0.0002 0.0002 Xylene 0.0003 0.0003 n -Hexane 0.0223 0.0223 224 TMP 0.0016 0.0016 Emission Factors Gas Venting (16" receiver) Emission Factor Source Pollutant Uncontrolled Controlled (lb/event) (lb/event) ' Extended gas analysis VOC 6.6110 .6110 Benzene 0.0004 0.0004 Toluene 0.0034 0.0034 Ethylbenzene 0,0006 0.0006 Xylene 0.0008 0.0008 n -Hexane 0.0630 0.0630 224 TMP 0.0046 0.0046 Section OS - Emissions Inventory 'no ac. Criteria Pollutants Potential to Emit Uncontrolled (tons/year) At tual rrnr�srons- Uncontrolled Controlled Requested Permit L mits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) VOC 2.02 1 2.02 2 02 34 Potential to Emit :nual Emissions- Requested Permit L mits Hazardous Air Pollutants Uncontrolled Uncrxrt.rollr',j ! oro roll, . Uncontrolled Controlled (lbs/year) Ibs," ar', (Ibs/year) Obs/year) Benzene 0 ItREF! 0 3 Toluene 2 #Rr;' 2 Ethylbenzene 0 "' 0 Xylene 1 ftREl: ! 1 1 n -Hexane 39 #REFI #R'- 39 _ 9 224 TMP 3 ':EFI 3 6" Receiver Criteria Pollutants Requested Permit Limits Uncontrolled Controlled (tons/year) (tens/year) Requested Monthly Limits Controlled (lbs/month) VOC 0.1 0.1 23 8" Receiver Criteria Pollutants Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) VOC 0.3 0.3 -4 10" Receiver Criteria Pollutants Requested Permit Limits Uncontrolled Ccntrolled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) VOC 0.4 0.4 72 16" Receiver Criteria Pollutants Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) VOC 1.2 1.2 207 54 of 76 K:\PA\2019\19WE0081.CP1.xlsm Separator Venting Emissions Inventory Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B (See regulatory applicability worksheet for detailed analysis) Section 07 - Technical Analysis Notes Source requires a permit *composition is based on plant inlet gas. Although process design includes some portion of gas is routed to the stabilizer overheads, the remainder is vented to the atmosphere. Applicant is conservatively calculating emissions assuming the entirety is vented to atmosphere. "Permit will include separate limits for each diameter of pig receiver (ie. 6", 8", 10", 16"). Notes to permit holder will contain factors for each limit on a lb/event basis. Operator is requesting 1 events per day per receiver for a total of 365 events per receiver per year. Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 014 Process # SCC Code 01 3-10-002-11 Pipeline Pigging (releases during pig removal) Uncontrolled Emissions Pollutant Factor Control % Units V0C 14712.21 0 lb/MMSCF Benzene 0.94 0 lb/MMSCF Toluene 7.64 0 Ib/MMSCF Ethylbenzene 1.23 0 Ih/MMSCF Xylene 1.83 0 lb/MMSCF n -Hexane 140.26 0 lb/MMSCF 224 TMP 10.17 0 lb/MMSCF 55 of 76 K:\PA\2019\19WE0081.CP1.xlsm Separator Venting Regulatory Analysis Worksheet Colorado Regulation 3 Parts A and B - APEN and Permit Requirements Source is in the Mtt3izouient Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.3)? Source requires a permit NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.2)? You have indicated that source is in the Attainment Area Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations, and Air Quality Control Commission regulations. This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act., its implementing regulations, and Air Quality Control Commission regulations, the language of the statute or regulation will control. The use of non -mandatory language such as "recommend," "may," "should," and "can, "is intended to describe APCD interpretations and recommendations. Mandatory terminology such as "must" and "required" are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself. Source Requires an APEN. Go to the next question Source Requires a permit Fugitive Emissions Inventory Section 01-961691696961nformaton IFacOltyos a 41123,911619,91 m n Plant Porn, •. aq TMw MSAROWOOKitialeMEWAVAM com,aon enry'r_6&i7N4w410kmn&ana hmivrR component rm. Connectors 5-W 0 o,¢,e9a' xam; `o,omomian 4.415.04 8605.04 641563 5.5-03 962963 1.04,02 control io, 84096 Doe ope.6ndedunes I116,99 5966 199,994.1.6. 240666 0.646 98696 ere 8.80,06 lieery 01 165565 8.50,01 61.096 0.096 3 6667 YUMA P11906 Seals Valves aia99 5.135994 165,05 765,05 6166 6096 0.016 320566 rrattirr .19922166 cisR&+ Pmm4.nt Hass Fradlon WC Rye ErnIsstOns 30914 602 600 eva 0.00 000 0.06 6.00 601 0.61 0.61 1101 601 601 0901 601 061 14911 Cannectors Fiances Open -Ended Lln. PunvSea6 2.1.05434 4 63E-04 1.40,03 2.49,03 7.50,06 3.09,03 261562 5.50,03 165562 6016 0096 woe 6096 Olher .36 365 0.19 0.16 0.16 0.19 .16 I 09 109 I 63 1.10564 6.606.06 243564 0.090 0.016 0.090 0696 Open -Ended Line, Purrp VaNes Other 2.40,05 9 510,65 1.406432 51,04 210,04 3.06,02 Benzene Toluene %Yuen 300 000 000 600 660 MOO 1100 600 600 646.9.9 mud On aria,. 94696 Uncontrolled ernIssbns Source andhenzene 22. 7138 2108 2111 104 01 04 395 550 81a Wen] EPs 9996,4535695.0171atle 294 01.661615 - 619094539695-017 nee 26 k4yim-9ao»neexs aarelard Us- 61,4511395.017 186 Unco6 9621 v wc1co,.x,o,n,.a 917 244 110 OA 8.80 231 6.80 261 0.00 101.11 13.2 3614 32.84 6.64 0.15 0.15 0.03 603 0.00 OLIO 0.00 0.00 600 0.00 0.00 0.00 0.23 621 623 0.23 0.09 602 0.02 0.02 062 5.53 166 1.62 1.82 1.62 36.98 3696 1.85 1.85 4.06 9.06 4.05 606 54.58 54.56 645 0915 10242 01.19 42.66 16.5 !Uncontrolled 6mixene Mod., Unit nepl9m.,nm Fugit ve Emissions Inventory Sestina 06 - Raerllton SbnfnenAllettib Regulation 1 Section lki • Except as Weeded in prayaptn 2 trarph 6 below, no vans a opera at a sane slut Oar a cause the ennson no the atmosphere of arty ar poausfs n al is in excess el 20% opepty Tius standard is bused on 24 camecur a [patty readnps taken at 15•secrmd sienna for se nrutes The approved re!rence test malice to issue emssons measurement is EPA Mebod 9 (40 CFR. Part 60. Appendix A tidy 1992! I in al subsections of Steen ai A art B d en rep,aaaas Regulation 2 Section LA - No person. Wtereve located. Shia cause a dor the emission of odious air ccntamnants from any snye source such as to result in detectable odors leach are measured in excess of the fok'wing limes Fa areas used edannartly for a is residential a coercial NW bon Pr rmpurposes a if alas are defected after the odorous air has been deed wrath seven (7) a once volumes of odor free au Regulation 3 Part A-APEN Reguirenents Criteria Palettes Fe torero peasants Ae Pollutant Esryss.cn Notices re regaled for each sS4Sat ensues pant In a non-altaunwa area vial uncontrolled actual eminent d one to' per year a more of any nsl4&al cr:teia maws 1pollutants are na sunned) fa inch the area is net attainment Applicant Is required to Ole NI ADEN since emissions exceed 1 ion per year VOC Part S - Construction Permit Cxenptlons Applicant Is required to obtain a permit since uncontrolled VOC emissions from this facility are greater than the 2 0 TPY threshold (Reg 3. Pan B, Section I, D.2.a) is res located sane in an owe non -operable tree a aiaryeert nenenance areal No rf yes. is this spree suttees to leek detecdaf and rapt (WAR I regnrerrtres per Regulation 7 Sector XVII F a Xa G a 40 CFR, Part 60, Subparts KKK 0000. a 0000a'7 Yes Pon B. III D 2 - RACT requrenients ra new a modeled mina sources This section of Regulation 3 rewires RACT for new a nsodfted mina sources located in nonattarrment or adarnrtentereintenance areas This sane is NOT boated in the 6 -hour ozone nonasanment area and therefore Is nor silted to RACT per IID2 Regulation 6 'natural is en spree at an onstoe gas processng Owe as deed In 40 CFR. Pet 60 63» Yes C.c th, source con -nieces caxbuctan. recdnssudtm. a maflcatlo! after January 20 1964 and al a before August 23 20117 No The is rid to NSPS KXK because Me fugtve sauce subsea new egtrprent covered by this sauce are catmnce casstrucbon after August 23. 2011 Din this source commences cuntnjdlon reconstrucbana modification alter August 23. 2011 and on a before Seterrter 16. 2015, No Sort* is net sugect to NSPS 0000 because the new egaprere covered by en fugbve source wit can -twice costrsresan after September 16, 2015 Regulation 7 is en source bated in an axe nonattairanent area a ataumert Sc. wee'1 No is en source at an onshore 'natural gas ',ween g plane es defined in 40 CFR. Pan 60 631T Yes Facety is clessined as a naval gas accessing plant, however, a Is not located in Me nonottainnes area and is therefore not sugect to secbah X11 Is the holy dassrfted as a eel poducsan faellty a natural gas conpressa stalah7 No Since lux racily tacky is not classified aslant production a natral gas ca... nsa steal it is rid select to Regusiai 7 Secaoh )MI F Regulation a is M same at a 'natural gas proaserp Orr as d,Medn 40 CFR. Part 63.7611 Yes Is en facility canted a'maja sera' of HAP as speafkYy dented in 40 CFR, Pert 63 761 fa sites sort arena poeisar fieldfacYbesy No reaulatlon 8. Part E MACT %uboart FIRM alai 63.769 0 applies to ancdary equipment and curve ssas at new sources of HAP. located at a natural gas processing plant that operate in VHAP service equal to a Beater than 300 hours per cakndr year Aatary equpnent is defined in 5 63 761 es purtps. ;revive react devices. sewing connection systems, open-ended valves a tnes vaNes flanges a ear cdnectas Since this fa day is ma a Mapr soiree or HAP,. t is nor sugect to Rio subpart NSPS0000a MAI Vas source commence consvucbort recanstMbana masfcaba+ after Seallemrer c6. 20157 Yes ISM 'natural same fleet wet ste _onvesse steer a munre gas processing plane n anted n 40 CFR Part 80 5430a? Yes This facility meets the definition of onshore 'natural gas processing plant' as defined by 40 CFR, Part 60 5430,a, Therefore, the fwdltlre erne ;signs at this facility ire Subiea to NSPS 00004 SiWti9S1 4? • Technical Anahysh Nc$gs Additional Notes: 'The control percentage values utitzed are based on Cason approved efficiencies for rnontny WAR per 0000a. Source .s wblect to 0000a. 'The VOC and HAP weight %values used to estimate emissions from the gas service were obtained from ProMax simulated stream compositionsSource normalized gas specution weight percentages, which raved the VOC weight %from 25.01%to 26.3%. I art accepting this. Source has slightly higher VOC and HAP calculations, which may be due to rounding E have indicated that above and accept this. 'Since the emissions from this point are estimated using a representativesample, rather than a site-spedhc sample, initial compliance testing will require that a site specific extended gas/vapor sample be obtained to demonstrate compliance with the emission limits contained in the permit. A liquid analysis will not be required as part of the Initial compliance test because the operator is assuming 100% VOC in light ;Quid stream, which is the most conservative estimatte- •The component counts are estimated based on ergtneenng judgment. As resist, the permit wit contain an Initial cornpfrance test requiring that an actual hard count d components he complete upon commencement at operatuw- ' As discussed above, this source is ulna to NSPS OOCOa. However, this NSPS has not yet been adopted into Colorado Regulation 6. Asa result, the condition refereeing NSPS0000a wog be addressed in the notes to permit holder section of the permit. ' liquid HAP concentrations are based on plant -wee Promaa simulation and resukng stable oil composition. 'Caas(Ot hr) is a combination of 171 relief valves and 42 Compeases itction.40 Ifnanton SCC Coding and Embs1Qm1 ctQr, AIRS Pont ■ 015 Process a KC Cods 01 Uncontrolled Pollutant tmissiins factor Varies by VOC component type Varies by Benzene component type Varies by Toluene Component type Warts by Ethylbenzene component type Vanes by Xylene component type Vanes by n -Hexane component type 224 TW Vanes by Component type Control % Vanes by component type Varies by component type Varies by component type Woes by component type Vanes by component type Varies by component type Vises by component type Source Standard Eh - EPA -453/R-95-017 Table 2.4 Standard EFs • EPA 453/R-95-017 Table 2.4 Standard (Fs - EPA -453/R-95-017 Table 2-4 Standard EFs • EPA -453/R-95-017 Table 2-4 Standard Eft - EPA -453/R-95-017 Table 2.4 Standard Ifs • EPM53/R-95-017 Table 2.4 Standard Us • EPA -453/R -95-C17 Table 2.4 Condensate Storage Tank(s) Emissions Inventory 017 Methanol Tank 'FacilityAIRs ID: 123 County A020 Plant 017 Point Section 02 - Equipment Description Details Detailed Emissions Unit One (1) 750 bbl methanol storage tank Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: 0 Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Storage Tank(s) Actual Condensate Throughput Barrels (bbl) per year Actual Condensate Throughput While Emissions Controls Operating = Requested Permit Limit Throughput = 8,873 Barrels (bbl) per year Requested Monthly Throughput = 754 Barrels (bbl) per month Potential to Emit (PTE) Condensate Throughput 8,873 Barrels (bbl) per year Secondary Emissions - Combustion Device(s) Heat content of waste gas = Volume of waste gas emitted per BBL of liquids produced Actual heat content of waste gas routed to combustion device = Requested heat content of waste gas routed to combustion device Btu/scf scf/bbl Potential to Emit (PTE) heat content of waste gas routed to combustion device = Section 04 - Emissions Factors & Methodologies Will this storage tank emit flash emissions? No MMBTU per year MMBTU per year MMBTU per year Emission Factors Methanol Tank Pollutant Uncontrolled Controlled (lb/bbl) (lb/bbl) Emission Factor Source (Condensate Throughput) (Condensate Throughput) VOC 0.112 0.11 Site Specific EPA TANKS E.F. Working and Breathir Methanol 0.112 0.112 Site Specific EPA TANKS E.F. Working and Breathin Control Device Emission Factor Source Uncontrolled Uncontrolled Pollutant (Ib/MMBtu) (lb/bbl) (waste heat combusted) (Condensate Throughput) PM10,,�f''r9 0.0000 PM2.5 0.0000 NOx �'j� aeriC a! r:,.%' 0.0000 CO 0.0000 Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) VOC 0.50 0.00 0.00 0.50 0.5€) 34.68 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Methanol t}« ' 0 0 9(91 997 Section 06 - Regulatory Summary Analysis Barrels (bbl) per year Regulation 3, Parts A, B You have indicated that source is in the Attainment Area Regulation 7, Section XVII.B, C.1, C.3 Storage Tank is not subject to Regulation 7, Section XVII Regulation 7, Section XVII.C.2 Storage Tank is not subject to Regulation 7, Section XVII.C.2 Regulation 6, Part A, NSPS Subpart Kb Storage tank is subject to NSPS Kb, based on TVP less than 4 psi (27.6 kPa), only subject to recordkeeping per 60.116b(d) Regulation 6, Part A, NSPS Subpart OOOO Storage Tank is not subject to NSPS OOOO Regulation 8, Part E, MACT Subpart HH Storage Tank is not subject to MAC HH (See regulatory applicability worksheet for detailed analysis) NSPS Kb "Maximum True Vapor Pressure" determination (based on Antoine Equation Parameters for Methanol as found on NISI website: https://webbook.nist.gov/cgi/cbook.cgi?ID=C67561&Mask=4&Type=ANTOINE&Plot=on#ANTOINE) For T range (288.1K to 356K) A B C Source Log(P) = A-(B/T+C) 5.20409 1581.341 -33.5 Ambrose and Sprake, 1970 T (deg F) T (deg C) TVP (bar) TVP (psi) 70.0 294.2611111 0.137962687 2.000983223 73.9 296.4277778 0.154787177 2.245002263 74.0 296.4833333 0.155240674 2.251579693 75.0 297.0388889 0.159838523 2.318265972 80.0 299.8166667 0.184615371 2.677624424 For purposes of Kb, maximum TVP is defined at the local maximum monthly average temperature as reported by NWS for VOL's stored at ambient temperature July average temperature per NWS nttps.//w2.weather.gov/climate/index.php?wfo=bou 2014 74.5 deg F 2014 71.6 deg F 2015 72.8 deg F 2015 72.9 deg F 2016 76.2 deg F 2016 75.0 deg F 2017 76.4 deg F 2017 75.5 deg F 2018 75.3 deg F 2018 74.4 deg F 5 yr AVG 75.0 deg F 5 yr AVG 73.9 deg F Denver Greeley Airport 59 of 76 K:\PA\2019\19W E0081.CP1.xlsm Condensate Storage Tank(s) Emissions Inventory Section 07 - Initial and Periodic Sampling and Testing Requirements Does the company use the state default emissions factors to estimate emissions? If yes, are the uncontrolled actual or requested emissions estimated to be greater than or equal to 80 tons VOC per year? Na If yes, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor based on guidelines in PS Memo 05-01. Does the company use a site specific emissions factor to estimate emissions? Yes If yes and if there are flash emissions, are the emissions factors based on a pressurized liquid sample drawn at the facility being permitted? This sample should be considered representative which generally means site -specific and collected within one year of the application received date. However, if the facility has not been modified (e.g., no new wells brought on-line), then it may be appropriate to use an older site -specific sample. If no, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor based on guidelines in PS Memo 05-01. Not applicable - stabilized tank Does the company request a control device efficiency greater than 95% for a flare or combustion device? If yes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling Section 08 - Technical Analysis Notes * This equipment does not emit any criteria pollutants in reportable amounts (per Reg 3 Part A) and is only APEN required for HAPS (methanol). As such, this equipment will not include any emission limits in the permit (But will include a process limit). *It was determined that the true vapor pressure of methanol at the local July average temperature (Greeley) is greater than 2.2 psi. As such, this is subject to NSPS Kb (vessel greater than 75 m^3). Since the maximum TVP as defined in Kb is less than 4 psi, the tank only has monitoring/recordkeeping requirements per 60.116b(c) to ensure that TVP remains below 4 psi. Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 017 Process ft 01 SCC Code 4-04-003-02 Fixed Roof Tank: Working & Breathing Losses Uncontrolled Emissions Pollutant Factor Control % Units VOC 2.68 0 lb/1,000 gallons condensate throughput Methanol 2.68 0 Ib/1,000 gallons condensate throughput 60 of 76 K:\PA\2019\19WE0081.CP1.xlsm Condensate Tank Regulatory Analysis Worksheet Isouana.1rts: alnme Nze. bRequirements ATTNNMENT . a. Are uncontrolled actual emissions from anycnreda pollutantsfrom NS Individual source greater Nan RTPr or am angle Hap gyeaterMan 230 lb/yr IRabulation 3.Part0. Section ll.o.l.a1? Istbe construction dam(cem ate)o m1?/aORmz teriz/31/zmz(Sue guidance on grandfather pp nlery)? 3. Need Wily unconholledcwcemsslons greater than rflbf, NOx greater Nan to Tn. or Co em''sabns greater Men10TPr(Regulaobn 3.Part 'You bevoindloted Natsour®pIn maNtalmnamArea 1 Neuaoneolleden4abm from any cdterla Nob.. from Ns lndN.uals0urremeater Manl TPr or amslnple HAP greater than 2.30rb/yrOlegulatlon 3. Part0.ledbnl1o1a1? 2 Is the crate (service date) prior to 12/36/.2 and,mtmodmed erml?/31/Imzlxe P6 memo o5nloennitlons v.12andss4 and section z roc addldonx guidance on grandfather appllabnity)x 3. Are Iola! a<nlry ummnwaed VOL emissInns from the greater than:TPr,NOx greater. Mans i« of CO embsfons greater Nan 51,Niegdatmn 3 Pun Secmnn.Oxl? ITgnia.Fmd,c.eed that source isin theAttammentArea Coloatlo ...lion T. caso n l0l.G ., ozone control ern any ozone nonattenment area or ettainmenVmalntenance area? 2 Is Mbstorage lank mated at natural gas greasing plant? 3. Does Mb storage tank...Ras," edllqulesl emNsIons and have uncontrolled acme) embslons greater than or equalto x tons per year voc? kterage.rdas not aubjevtto Xqulatlon>senon NILG Control Requirement; sanionotei Gemaal Requiremen. for Plc Pollution Control Equipment-Preventlon of Leakage Sectiongiu-emisson Esdmadon Procedures Ml( Is tills tank located ata bansIon/s7. aBlryi ts Mk storage Nnk located man on and gas exploration and producdon operadon,wen pmductlon laciliry', natural gas p ormtmnor namral gel processing plena Areunconfrolled acbaal emissions', Mb storage lankequal tear greater 'ban 6 tons per veer VCIC, Iuo Section %NIS -General ProvNlons for ANPollubon Control emend Preventlon of Emissions Suction XIIII.C.1-Ernissions Comm! itorng Provisions Requirements 5. Wes nanN•sobllned,ulds? the I.o not sublan to R«nlation?,SeedN..I.C.? Section Xvil.C.2- Capture and Monitoring forStoragebanla wt.,. Pollution Control Ebufornent 40 CFR Part a0.5uboart Ko.5tandarth of PerformanceforVolatINIOnninIcLlould5toragaVeneIb 1 N. soct.e ve.sel capacitygreatai Man or equal ea 75 cublemeters l-4Tz661s17 0,Nn thestoragevmsel6wssbidIM, a Does tlle vessel has na, cap acity lea Man or equal to LS03.3?4 matt-i 30033L1 r petroleum' or condensate ted ate stapramsed.ore®md prior r custody crsles del,.in 60.1160.111b7tb? 3. Was this teegaragetan kmmtrucm3, reconstructed, or mental (see delln.ns 40CPx,EN2)60.z).lterluly?3,1364? Sub? 5. Does Seni 4ud lvor...fined In sasses? 6. Mestoragev mee anyoneeef the following additional exempeons: a. Ise swage vessel a pressure vessel desgned topper. n excesspf ..3 ba ra.7 pad onewmoutemissbns game atmosphere RO-bbO b; or pantyioaatrre i Nan or m 151 m'1'550M30 and stares a Iquld veld+ a maximum true Telter Pressure' Iea man..mal.i1.ObI:or des4o es mery greater man or equal ga?s Me r4?ze6Ll hatless Nan 131.' 1-350 Bell and stares ago. v. a mecmumwe vaporaesNms ass Nan15.0.16ossWro11? kb s.ionmNSP6Im.ham.onTwanthMr pal(22,9 onlyanaentoammamdniper w.hied) Subparta evewale) Provisions 4W.11m-Monrodrr of Opera.. 40 CFRPan$0.sutwrt0000.standaNS of Performance for Credo 011 and Wend Om Produ3tlon. Tamed dolt L Is Mrs ate storage vessel located at a facility n the onshore oil and namral gas production segment medal gel pm2Sxingseameet or natural gastrammfsslon and storage segrentorm? le Industry 2 Was this condensate s eE foe n 60.0 betynan Nrgmt23, xslan 4p$mberte, 2013? 3. Abe tench)we em one from'e Intl Ide� lsmagevesselgre terMan or Mtoeal 6 mni perr year? 4. Does tills e vessel meetthedefinItlon of.storage vessel. per 30.3430i 5. I3 tstore vessel abieam and conbolled In accordance MN re ulremennfor store 3e vessels. 4oaR Part 60 Subpart Nil r 40CSRPan63submw oarlst. rageTenk b Not aubject to MPS 0000 Subpart, General Paovbioos per 46o5425Table3 §605393-Embsbmmntrol Mandan. for wc 466.3413-Tesdng aM Procedures 460366310-n 560341614-c dCIosed Venn Reaulrements ($353-30Nev. Nonit1333lepul0mensnn (Nat �I Is pmdourlynaaminM m m subject m MPS 0000 duo m of aloneebow6Mm per year VOL on the appllmb6lry determination date, its u remafnsubjan to MPS 00 M 09351 2)« n If p.m., voc amulalo. drop bow 6 tam parvaerl 4.7,060 .1 5ubsart MAR., 00 and Goa Production Pacnit133 es a an all an s either of Me fallowing crlterla: a Afaciiilty tiro oraessa.uprndes organ. hydrocarbon Rouble (63.76001M:0P 2x 1111, mat o1coaaaebupgradmorstormnatural gas odor .Mepo(ntat which natural gas enters Me natural gas tammlssbn and sma¢.31mmte232,1300301red me final a5d user'163.760(al(311? Is nifty mat 6 mak' for HAN, es the tank meetOeaeMiVon of•.ors vN1$ r3 In 510617 4. Does the tank rreetclae derniiion or'Storage vessel wilb Wanda! for rash ernlisbna' per 63.7617 No No v. AMR No Yes Vas No source Napalms a permit CarnInve•VouNye Proled Summary 'beet. 6om the nod quebon•you have Indicated aeNry type.. Prole.aommar sInd. blot to Regulation sm1a%v11.C2 No to Pe neatouelNen Nos btorageTenbis mot subject 10 HIACr NH subberth General provision per 365.764 (a) Tablet 4G6.>66-Ernissbns Control scan.wrdz i §63..713 -Monitoring 463374-eecardbeeping 463.7.-Reoorbne RACT Rau* Racemiw s rMWreLn limitationdoe not aoayAND if [botanic 6137tba nomettafaeam area. Ifthetmk mean both NRela. item rMw PACT requim,wrra ctscairner mAtlocranenlaa. opeta fors wi3tletamun2q a2Plnabr2M acerb. requirements afire CASS00Acl, Asfrrp.ne1720 relotions.. and Pi101SSOCm0N Commission reguolons. Trio document a rof a n?eanMuktron, antl2c 0nays.0 aantalhs 0320 col aPPN lo particular silualion Imes, upon IM102wbual fact and 3401006axs 11150AcurrwlRtloes not change arsubs ?the for any Nw.nqu 055. oranr other bindbq ra0m0renland is not legalyMfO0eable. In isle even, ofany con. Oeiwecn thalangrageollfu cUctmiairvdtheorquaS or2e CO3an A6 Art.. ill urylewONtgreguLVons.adAirOua2551 Control Commission regulations, IN language&?,es..,awrgvofonswlwnfmL 1?re use dnonr�n2aronomrya9e suhas •nxum,370, 7or.' O23O0$ ard'can.'ism(e>da0 to 2ea006APC0.layreuton5 and reconme0latons. Mandalory(OMrooyy such as'musran2'requbed arententle2152040763 conbd2npaquverenIs under the fe>r¢d the Clean ANAc? and 00032lM Cad d Commission reprAtons. but Ilya 20.Vmenttloes not esfaA shlega?yb.Gnq requirements. aro 0012230. Continue,. have Indian. the source cab," ea the Project Sarnmeb.sheet. Hydrocarbon Loadout Emissions Inventory Section 01 - Administrative Information Facility AIRs ID: 123 County A020 Plant 018 Point Section 02 - Equipment Description Details Detailed Emissions Unit Description: Emission Control Device Description: Is this loadout controlled? Unloading of condensate from pressurized tanks to pressurized tank trucks. Loadout occurs via vapor balance and emissions are only released to the atmosphere during hose disconnect. Emissions from this source are not controlled. Requested Overall VOC & HAP Control Efficiency %: 0.00 Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Hydrocarbon Loadout Truck Loadout Capacity 10000 No gallons/load 730,000.00 bbl/year 30,660,000 Loadouts/year 3,066.00 loadout/year Loadouts/month Secondary Emissions - Combustion Device(s) 260.40 loadout/month Section 04 - Emissions Factors & Methodologies Loadout Hose Parameters Liquid Hose Diameter 0.25 feet Vapor Hose Diameter 0.17 feet Liquid Hose Length* 1.50 feet Vapor Hose Length` 2.00 feet Liquid Hose Volume 0.0736 cubic feet Vapor Hose Volume 0.0436 cubic feet Tank and Truck Pressure Tank and truck pressure 49.8 psig 62 psia PV=nRT Where: P = pressure in hose at time of disconnect = storage tank pressure (psia) V = volume of hoses (cubic feet) n = number of lb -moles of product in hoses R = Universal gas constant = 10.73 ft^3 • psi / lbmole / degR T = average loadout temperature = 60 •F = 519.67R Vapor Density n 0.000485156 Ibmol n/V 0.011118964 Ibmol/ft^3 MW 12.1 Ib/Ibmol Vapor Density 0.134650653 Ib/ft^3 MMBTU per year MMBTU per year MMBTU per year Liquid Density Liquid Density i 3.923796791 lb/gallon 29.35 Ib/ft^3 Notes: 1. All liquid lines contain liquid products at individual specific gravity. 2. All vapor return lines contain products that behave as ideal gases at 60°F and storage tank pressure. Uncontrolled VOC Emissions: Vapor Emissions 18.01 lb/year 0.01 tpy Liquid Emissions 6,625.85 lb/year 3.31 tpy Requested Total 3.32 tpy 1.53 lb/month 562.74 lb/month Component Mass Fraction Source Benzene 0.089% Representative Sample (See Section 08 for notes) Toluene 0.042% Representative Sample (See Section 08 for notes) Ethylbenzene 0.007% Representative Sample (See Section 08 for notes) Xylene 0.009% Representative Sample (See Section 08 for notes) n -Hexane 0.841% Representative Sample (See Section 08 for notes) 224 TMP 0.000% Representative Sample (See Section 08 for notes) 0.282136548 total tons per month 62 of 76 K:\PA\2019\19WE0081.CP1.xlsm Hydrocarbon Loadout Emissions Inventory Emission Factors Hydrocarbon Loadout Pollutant Uncontrolled Controlled (lb/loadout (lb/loadout event) event) Emission Factor Source (Volume Loaded) (Volume Loaded) VOC 2.1669E+00 2.17E+00 Other (Documentation in Technical Analysis Note' Other (Documentation in Technical Analysis Note: Other (Documentation in Technical Analysis Note! Other (Documentation in Technical Analysis Note! Other (Documentation in Technical Analysis Note: Other (Documentation in Technical Analysis Note' Other (Documentation in Technical Analysis Note: Benzene 1.93E-03 1.93E-03 Toluene 9.20E-04 9.20E-04 Ethylbenzene 1.49E-04 1.49E-04 Xylene 2.00E-04 2.00E-04 n -Hexane 1.82E-02 1.82E-02 224 TMP 1.00E-05 1.00E-05 Control Device Emission Factor Source Uncontrolled Uncontrolled Pollutant (Ib/MMBtu) (lb/bbl) (waste heat combusted) (Volume Loaded) PM10 0.00E+00 PM2.5 0.00E+00 5Ox °'Y 0.00E+00 NOx 0.00E+00 CO 0.00E+00 Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (torts/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM 10 PM2.5 SOx NOx VOC CO 0.00 0.00 0.00 0.00 0.00 0 0.00 0.00 0.00 0.00 0.00 0 0.00 0.00 0.00 0.00 0.00 0 0.00 0.00 0.00 0.00 0.00 0 3.32 3.32 3.32 3.32 3.32 564 0.00 0.00 0.00 0.00 0.00 0 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene Toluene Ethylbenzene Xylene n -Hexane 5.91 5.91 5.91 6 6 2.82 2.82 2.32 3 3 0.46 0.46 0.46 0 0 0.61 0.61 0.61 1 1 55.85 55.85 55.85 56 56 224 TMP 0.03 0.03 0.03 0 0 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit RACT - Regulation 3, Part B, Section III.D.2.a The loadout operation must satisfy RACT. (See regulatory applicability worksheet for detailed analysis) Section 07 - Initial and Periodic Sampling and Testing Requirements You have ;r.c.cated above the source is not controlled. 'he follow does not require an answer. Section 08 - Technical Analysis Notes `The molecular weight of the gas, density of the liquid and mass fractions of HAPs used to estimate the HAP emissions were obtained from representative modeling. Compositional data were obtained from the permit application 18WE1052 for Cureton's nearby Tampa Compressor Station. The Tampa facility accepts pressurized NGL (potentially from Front Range Gas Plant) and injects it into an NGL pipeline. Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # Cis Process # 01 SCC Code Uncontrolled Emissions Pollutant Factor Control % Units VOC 2.17E-01 0 lb/1,000 gallons transferred n -Hexane 1.82E-03 0 lb/1,000 gallons transferred 63 of 76 K:\PA\2019\19WE0081.CP1.xlsm Hydrocarbon Loadout Emissions Inventory 019 Liquid Loading Facility AIRs ID: 1.'3 County A020 Plant 019 Point Section 02 - Equipment Description Details Detailed Emissions Unit Description: Emission Control Device Description: Is this loadout controlled? Collection Efficiency: Control Efficiency: Loadout of stabilized condensate in trucks by submerged fill. Enclosed cornbustor(s) Requested Overall VOC & HAP Control Efficiency %: Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Hydrocarbon Loadout Actual Volume Loaded = Yes 100.0 95 95.00 730,000 Barrels (bbl) per year Actual Volume Loaded While Emissions Controls Operating = 730,000 Barrels (bbl) per year Requested Permit Limit Throughput = 730,000 Barrels (bbl) per year Requested Monthly Throughput = 62000 Barrels (bbl) per month Potential to Emit (PTE) Volume Loaded = Secondary Emissions - Combustion Device(s) Heat content of waste gas =- Volume of waste gas emitted per year = Actual heat content of waste gas routed to combustion device = Requested heat content of waste gas routed to combustion device = 730,000 Barrels (bbl) per year 2255 Btu/scf 1004525 scf/year Potential to Emit (PTE) heat content of waste gas routed to combustion device = Section 04 - Emissions Factors & Methodologies Does the company use the state default emissions factors to estimate emissions? Does the hydrocarbon liquid loading operation utilize submerged fill? 2,265 MMBTU per year 2,265 MMBTU per year 2,265 MMBTU per year Yes Yes The state default emissions factors may be used to estimate emissions. /M+r.•�..v...ru .milli .li:.• ..y..fd✓.i / / Ou di/.IN.. 'y!r r c . --. ...e...... «—.«- .Component "r. - i'dfac- Fraction {$ Ftz;isston Vattor. cJU t:5 Sonr. Benzene ' l,r.'..,: . " 1-. ?ofuene. # o ti ib -..1 -- - .. _.., - - - ... .. -. ''u' £rhylbenzene .. Lv L =, w- ___, -. �.. Emission Factors Hydrocarbon Loadout Pollutant Uncontrolled Controlled (Ib/bbl) (lb/bbl) Emission Factor Source (Volume Loaded) (Volume Loaded) VOC 2.36E-01 1.18E-02 Condensate Loadout State E.F. Condensate Loadout State E.F, Condensate Loadout State E.F. Benzene 4.10E-04 2.05E-05 Toluene 0.00E+00 0.00E+00 Ethylbenzene 0.00E+00 0.00E+00 Xylene 0.00E+00 0.00E+00 n -Hexane 3.60E-03 1.80E-04 224 TMP 0.00E+00 0.00E+00 Pollutant Control Device Emission Factor Source Uncontrolled Uncontrolled (Ib/MMBtu) (Ib/bbl) (waste heat combusted) (Volume Loaded) PM10 0.0075 2.31E-05 AP -42 Table 1.4-2 (PM10/PM.2 5) AP -42 Table 1.42 (PM10/PM.2.5) AP -42 Table 1.4-2 (SOx) AP -42 Chapter 13.5 Industrial Flares (NOx'; A.P.,,? r'lncttc.,d'?.S !ndustrial Flares (C(7 PM2.5 0.0075 2.31E-05 SOx 0.0006 1.33E-06 NOx 0.0680 2.11E-04 CO 0.3100 9.62E-04 64 of 76 K:\PA\2019\19W E0081.C P1.xlsm Hydrocarbon Loadout Emissions Inventory Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 SOx NOx VOC CO 0.01 0.01 0.01 0.01 0.01 1 0.01 0.01 0.01 0.01 0.01 1 0.00 0.00 0.00 0.00 0.00 0 0.08 0.08 0.03 0.08 0.03 13 26.14 86.14 4.31 86.14 4.31 732 0.35 0.35 0.35 0.35 0.35 60 % Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene 299 299 15 299 15 Toluene 0 0 0 0 0 Ethylbenzene 0 0 0 0 0 Xylene 0 0 0 0 0 n -Hexane 2628 2628 131 2628 131 224 TMP 0 0 0 0 0 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit RACT - Regulation 3, Part B, Section III.D.2.a Site is in attainment and not subject to RAG (See regulatory applicability worksheet for detailed analysis) Section 07 - Initial and Periodic Sampling and Testing Requirements Does the company request a control device efficiency greater than 95% for a flare or combustion device? 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( 4444 Y Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 019 Process # 01 SCC Code 4-06-001-32 Crude Oil: Submerged Loading Normal Service (S=0.6) Pollutant PM10 PM2.5 SOx NOx VOC CO Benzene Toluene Ethylbenzene Xylene n -Hexane 224 TMP Uncontrolled Emissions Factor 0.00 0.00 0.00 0.01 5.6 0.02 0.01 0.00 0.00 0.00 0.09 0.00 Control % 0 0 0 0 95 0 95 95 95 95 95 95 Units lb/1,000 gallons transferred lb/1,000 gallons transferred lb/1,000 gallons transferred lb/1,000 gallons transferred lb/1,000 gallons transferred Ib/1,000 gallons transferred lb/1,000 gallons transferred lb/1,000 gallons transferred lb/1,000 gallons transferred lb/1,000 gallons transferred lb/1,000 gallons transferred lb/1,000 gallons transferred 65 of 76 K:\PA\2019\19WE0081.CP1.xlsm Hydrocarbon Loadout Regulatory Analysis Worksheet Colorado Regulation 3 Parts A and B - APEN and Permit Requirements Source L. in the Attainment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Is the loadout located at an exploration and production site (e.g., well pad) (Regulation 3, Part B, Section 11.0.1.1)? 3. Is the loadout operation loading less than 10,000 gallons (238 BBLs) of crude oil per day on an annual average basis? 4. Is the loadout operation loading less than 6,750 bbls per year of condensate via splash fill? 5. Is the loadout operation loading less than 16,308 bbls per year of condensate via submerged fill procedure? 6. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.3)? Source require; a permit NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this irdividual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Is the loadout located at an exploration and production site (e.g., well pad) (Regulation 3, Part B, Section II.D.1.1)? 3. Is the loadout operation loading less than 10,000 gallons (238 BBLs) of crude oil per day on an annual average basis? 4. Is the loadout operation loading less than 6,750 bbls per year of condensate via splash fill? 5. Is the loadout operation loading less than 16,308 bbls per year of condensate via submerged fill procedure? 6. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.2)? You have indicated that source is in the Attainment Area 7. RACT - Are uncontrolled VOC emissions from the loadout operation greater than 20 tpy (Regulation 3, Part B, Section III.D.2.a Site is in attainment and not subject to RACT Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations, and Air Quality Control Commission regulations. This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act„ its implementing regulations, and Air Quality Control Commission regulations, the language of the statute or regulation will control The use of non -mandatory language such as 'recommend." 'may, "'should,"and 'can," is intended to describe APCD interpretations and recommendations. Mandatory terminology such as 'must" and 'required" are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself. Go to next Go to ques' The loadou Hydrocarbon Loadout Emissions Inventory 020 Liquid Loading 'Facility AIRs ID: 123 County A020 Plant 020 Point Section 02 - Equipment Description Details Detailed Emissions Unit Description: Emission Control Device Description: Is this loadout controlled? Collection Efficiency: Control Efficiency: Loading of mixed condensate liquids into tank trucks by submerged fill Enclosed combustors) Yes 100.0 95 Requested Overall VOC & HAP Control Efficiency %: 95.00 Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Hydrocarbon Loadout Actual Volume Loaded = 78,840 Barrels (bbl) per year Actual Volume Loaded While Emissions Controls Operating = 78,840 Barrels (bbl) per year Requested Permit Limit Throughput = 78,840 Barrels (bbl) per year Requested Monthly Throughput = 6696 Barrels (bbl) per month Potential to Emit (PTE) Volume Loaded = Secondary Emissions - Combustion Device(s) Heat content of waste gas = Volume of waste gas emitted per year = Actual heat content of waste gas routed to combustion device = Requested heat content of waste gas routed to combustion device = 78,840 Barrels (bbl) per year 2255 Btu/scf 108489 scf/year Potential to Emit (PTE) heat content of waste gas routed to combustion device = Section 04 - Emissions Factors & Methodologies Does the company use the state default emissions factors to estimate emissions? Does the hydrocarbon liquid loading operation utilize submerged fill? w 12,4t;" S "Pets Yes Yes 245 MMBTU per year 245 MMBTU per year 245 MMBTU per year The state default emissions factors may be used to estimate emissions. Factor # Meaning • •V -al Je Units.: Source .w µ .. 1 w.4 ...c-.-...- w. `N S am... J -.a... .ia-».r .a a+`.+.. ;./ ....sL. W+ti-•nr•Y4H_.r-Sa..-.Y / ;.-...,..,..,...,..„.......4.:. - ++•-r. 44 ! .- .. ", •.•+r.t.._ H -:....—......,1„.,..,,L.......“........1,-,...----.-M'.-. p >-.:..:.__:..'........4•44-‘:•4:----4-'-'.:14g4;.- / �b .^ .YfnY.^.w-- -4.4.--..n..-..wMa...,--. m -M.. .M.--.f.-.n w..M- earana } :'1.`iuo>;;4-o:.) W +tc)3'_;-tpets }a h.-^�.y .s.M ssi-.-.J-.-r...-1..RY^ .N.4..�...rr ibis -t ;} > " --44---..1.-:44,-;-‘4.--♦ i M- _ • T".-l.n.r.�l� i' 'i• ';'4.11i ..�.1n r}j1'"'!,f'-iii,. • `E}r, V,iY - ' - .- „-. _ Component. Benzene Ti l'tlette €thyiberizette ;CYlerte n44r-Kane 224 IMP P-Aass Fraction Emission Factor Units 4 •• • ...i . ,7 M•••• .. .. �fFB: t-i;•lr _ (tb,`lai l_ 15,Ityr...<1, Source w - .. .... Emission Factors Hydrocarbon Loadout Pollutant Uncontrolled Controlled (lb/bbl) (lb/bbl) Emission Factor Source (Volume Loaded) (Volume Loaded) VOC Z.36E-01 1.18E-02 Condensate Loadout State E.F. Benzene 410E-04 2.05E-05 Condensate Loadout State E.F. Toluene 0.00E+00 0.00E+00 Condensate Loadout State E.F. Ethylbenzene 0.00E+00 0.00E+00 Xylene 0.00E+00 0.00E+00 n -Hexane 3.60E-03 1.80E-04 224 TMP 0.00E+00 0.00E+00 Pollutant Control Device Emission Factor Source Uncontrolled Uncontrolled (lb/MMBtu) (lb/bbl) (waste heat combusted) (Volume Loaded) PM10 0.0075 2.31E-05 +-:P-42Tah e 1.4-2 (PM10/PM.2.5) AP -42 Table 1.42 (PMiO/PM.2.5) AP -42 Table 1.4-2 (Sox) AP -42 Chapter 13.5 Industrial Flares (F1Ox) nP-47 Chapter 13.5 Industrial Flares (CO` PM2.5 0.0075 2.31E-05 SOx 0.0006 1.83E-06 NOx 0.0680 2.11E-04 CO 0.3100 9.62E-04 67 of 76 K:\PA\2019\19WE0081.CP1.xlsm Hydrocarbon Loadout Emissions Inventory Section OS - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 S0x N0x V0C CO 0.00 0.00 0.00 0.00 0.00 0 0.00 0.00 0.00 0.00 0.00 0 0.00 0.00 0.00 0.00 0.00 0 0.01 0.01 0.01 0.01 0.01 1 9.30 9.30 0.47 9.30 0.47 79 0.04 0.04 0.04 0.04 0.04 6 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (Ibs/year) (Ibs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (Ibs/year) Benzene 32 32 2 32 2 Toluene 0 0 0 0 0 Ethylbenzene 0 0 0 0 0 Xylene 0 0 0 0 0 n -Hexane 284 284 14 284 14 224 TMP 0 0 0 0 0 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit RACT - Regulation 3, Part B, Section III.D.2.a site is in attainment and not subject to RAG See regulatory applicability worksheet for detailed analysis) Section 07 - Initial and Periodic Sampling and Testing Requirements Does the company request a contro device efficiency greater than 95% for a flare or combustion device? If yes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling Section 08 - Technical Analysis Notes This represents a mix of condensate and water. Source is using state EFs - i see no benefit from requiring testing on this point. Because source is using state default EFs, source must use submerge -fill loading. Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 020 Process # 01 SCC Code 4-06-001-32 Crude Oil: Submerged Loading Normal Service (S=0.6) Uncontrolled Emissions Pollutant Factor Control % Units PM10 0.00 0 Ib/1,000 gallons transferred PM2.5 0.00 0 lb/1,000 gallons transferred SOx 0.00 0 lb/1,000 gallons transferred NOx 0.01 0 lb/1,000 gallons transferred VOC 5.6 95 lb/1,000 gallons transferred CO 0.02 0 Ib/1,000 gallons transferred Benzene 0.01 95 lb/1,000 gallons transferred Toluene 0.00 95 lb/1,000 gallons transferred Ethylbenzene 0.00 95 lb/1,000 gallons transferred Xylene 0.00 95 lb/1,000 gallons transferred n -Hexane 0.09 95 lb/1,000 gallons transferred 224 TMP 0.00 95 lb/1,000 gallons transferred 68 of 76 K:\PA\2019\19WE0081.CP1.xlsm Hydrocarbon Loadout Regulatory Analysis Worksheet Colorado Regulation 3 Parts A and B - APEN and Permit Requirements Source is in the Attainment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Is the loadout located at an exploration and production site (e.g., well pad) (Regulation 3, Part B, Section II.D.1.1)? 3. Is the loadout operation loading less than 10,000 gallons (238 BBLs) of crude oil per day on an annual average basis? 4. Is the loadout operation loading less than 6,750 bbls per year of condensate via splash fill? 5. Is the loadout operation loading less than 16,308 bbls per year of condensate via submerged fill procedure? 6. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section 11.0.3)? Yes No Yes Source requires a permit NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Is the loadout located at an exploration and production site (e.g., well pad) (Regulation 3, Part B, Section II.D.1.I)? 3. Is the loadout operation loading less than 10,000 gallons (238 BBLs) of crude oil per day on an annual average basis? 4. Is the loadout operation loading less than 6,750 bbls per year of condensate via splash fill? 5. Is the loadout operation loading less than 16,308 bbls per year of condensate via submerged fill procedure? 6. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.0.2)? You have indicated that source is in the Attainment Area 7. RACT - Are uncontrolled VOC emissions from the loadout operation greater than 20 tpy (Regulation 3, Part B, Section III.D.2.a)? Site is in attainment and not subject to RACT Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations, and Air Quality Control Commission regulations_ This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable In the event of any conflict between the language of this document and the language of the Clean Air Act„ its implementing regulations, and Air Quality Control Commission regulations, the language of the statute or regulation will control The use of non -mandatory language such as "recommend," "may," "should," and "can, "is intended to describe APCD interpretations and recommendations. Mandatory terminology such as "must" and "required" are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself. Go to next Go to ques' The loadou Condensate Storage Tank(s) Emissions Inventory 021 Condensate Tank 'Facility AIRs ID: 123 County A020 Plant 021 Point Section 02 - Equipment Description Details Detailed Emissions Unit Two (2) 400 BBL tanks for storage of mixed liquids (condensate and produced water) Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: Enclosed Combustor(s) 95 Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Storage Tank(s) Actual Condensate Throughput = 78,840 Barrels (bbl) per year Actual Condensate Throughput While Emissions Controls Operating = 78,840 Barrels (bbl) per year Requested Permit Limit Throughput = 78,840 Barrels (bbl) per year Requested Monthly Throughput = 6696 Barrels (bbl) per month Potential to Emit (PTE) Condensate Throughput Secondary Emissions- Combustion Device(s) Heat content of waste gas = Volume of waste gas emitted per BBL of liquids produced = 78,840 Barrels (bbl) per year 2255 Btu/scf 244 scf/bbl Actual heat content of waste gas routed to combustion device = Requested heat content of waste gas routed to combustion device = Potential to Emit (PTE) heat content of waste gas routed to combustion device = Section 04 - Emissions Factors & Methodologies Will this storage tank emit flash emissions? 43,379 MMBTU per year 43,379 MMBTU per year 43,379 MMBTU per year Emission Factors Condensate Tank Emission Factor Source Pollutant Uncontrolled Controlled (lb/bbl) (lb/bbl) (Condensate Throughput) (Condensate Throughput) VOC 13.70 0.69 Condensate State c.t~. (inciudkrs tiash) -Front ii,.. Benzene 0.024 0.001 Condensate State E.F. (includes flash) -Front Re::. Toluene 0.000 Ethylbenzene 0.000 Xylene 0.000 n -Hexane 0.210 0.011 Condensate State E.F. (Includes flash) -Front Rang, 224 TMP 0.000 Control Device Emission Factor Source Uncontrolled Uncontrolled Pollutant (lb/MMBtu) (lb/bbl) (waste heat combusted) (Condensate Throughput) PM10 0.0075 0.0041 AP -42 Table 1.4-2 (PM1O/PM.2.5) PM2.S 0.0075 0.0041 AP -42 Table 1.4-2 (PM10/PM,2.5) AP -42 Chapter 13.5 Industrial Flares (NOx) AP -42 Chapter 13.5 Industrial Flares (CO) NOx 0.0680 0.0374 CO 0.3100 0.1706 Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) VOC PM10 PM2.5 NOx CO 540.1 540.1 27.0 540.1 27.0 4587 0.2 0.2 0.2 0.2 0.2 27 0.2 0.2 0.2 0.2 0.2 27 1.5 1.5 1.5 1.5 1.5 251 6.7 6.7 6.7 6.7 6.7 1142 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene Toluene Ethylbenzene Xylene n -Hexane 224 TMP 1892 1892 95 1392 95 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 16556 16556 828 16556 828 0 0 0 0 0 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit Regulation 7, Section XII.C, D, E, F Storage Tank is not subject to Regulation 7, Section XII.C-F Regulation 7, Section XII.G, C Storage Tank is not subject to Regulation 7, Section XII.G Regulation 7, Section XVII.B, C.1, C.3 Storage tank is subject to Regulation 7, Section XVII, B, C.1 & C.3 Regulation 7, Section XVII.C.2 Storage tank is subject to Regulation 7, Section XVII.C.2 Regulation 6, Part A, NSPS Subpart Kb Storage Tank is not subject to NSPS Kb Regulation 6, Part A, NSPS Subpart OOOO Storage Tank is not subject to NSPS OOOO Regulation 8, Part E, MACT Subpart HH Storage Tank is not subject to MACT HH (See regulatory applicability worksheet for detailed analysis) 70 of 76 K:\PA\2019\19 W E0081. C P1.xl sm Condensate Storage Tank(s) Emissions Inventory Section 07 - Initial and Periodic Sampling and Testing Requirements Does the company use the state default emissions factors to estimate emissions? Yes If yes, are the uncontrolled actual or requested emissions estimated to be greater than or equal to 80 tons VOC per year? Yes If yes, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor based on guidelines in PS Memo 05-01. Does the company use a site specific emissions factor to estimate emissions? No If yes and if there are flash emissions, are the emissions factors based on a pressurized liquid sample drawn at the facility being permitted? This sample should be considered representative which generally means site -specific and collected within one year of the application received date. However, if the facility has not been modified (e.g., no new wells brought on-line), then it may be appropriate to use an older site -specific sample. If no, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor based on guidelines in PS Memo 05-01. Does the company request a control device efficiency greater than 95% for a flare or combustion device? If yes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling Section 08 - Technical Analysis Notes Source is using state emission factors Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 021 Process # 01 SCC Code Uncontrolled Emissions Pollutant Factor Control% Units PM10 0.10 0 Ib/1,000 gallons condensate throughput PM2.5 0.10 0 lb/1,000 gallons condensate throughput NOx 0.89 0 lb/1,000 gallons condensate throughput VOC 326.2 95 lb/1,000 gallons condensate throughput CO 4.06 0 lb/1,000 gallons condensate throughput Benzene 0.57 95 lb/1,000 gallons condensate throughput Toluene 0.00 95 Ib/1,000 gallons condensate throughput Ethylbenzene 0.00 95 lb/1,000 gallons condensate throughput Xylene 0.00 95 lb/1,000 gallons condensate throughput n -Hexane 5.00 95 Ib/1,000 gallons condensate throughput 224 TMP 0.00 95 lb/1,000 gallons condensate throughput 71 of 76 K:\PA\2019\19WE0081.CP1.xlsm Condensate Tank Regulatory Analysis Worksheet Colorado Re ulation 3 Parts A and B - APEN and Permit Re uirements _ Source is iii the Attainment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Is the construction date (service date) prior to 12/30/2002 and not modified after 12/31/2002 (See PS Memo 05.01 Definitions 1.12 and1.14 and Section 2 for additional guidance on grandfather applicability)? 3. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.3)? Source requires a permit Yes No NON•ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 WY (Regulation 3, Part A, Section II.D.1.a)? 2. Is the construction date (service date) prior to 12/30/2002 and not modified after 12/31/2002 (See PS Memo 05-01 Definitions 1.12 and1.14 and Section 2 for additional guidance on grandfather applicability)? 3. Are total facility uncontrolled VOC emissions greater than 2 WY, NOx greater than 5 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.2)? You have indicated that source is in the Attainment Area Colorado Regulation 7, Section XII.C-F 1. Is this storage tank located in the 8 -hr ozone control area or any ozone non -attainment area or attainment/maintenance area? 2. Is this storage tank located at an oil and gas exploration and production operation', natural gas compressor station or natural gas drip station? 3. Is this storage tank located upstream of a natural gas processing plant? Storage Tank is not subject to Regulation 7, Section Section XII C.1 - General Requirements for Air Pollution Control Equipment - Prevention of Leakage Section XII.C.2 - Emission Estimation Procedures Section XII D - Emissions Control Requirements Section XII E - Monitoring Section XII F - Recordkeeping and Reporting Colorado Regulation 7, Section XII.G 1. Is this storage tank located in the 8 -hr ozone control area or any ozone non -attainment area or attainment/maintenance area? 2. Is this storage tank located at a natural gas processing plant? 3. Does this storage tank exhibit "Flash" (e.g. storing non -stabilized liquids) emissions and have uncontrolled actual emissions greater than or equal to 2 tons per year VOC? Ste -age Tank is not subject to Regulation 7, Section XII.G Yrs Source Req Go to next Source Req -, Storage Tar No Storage Tar No Yes Section XII G.2 - Emissions Control Requirements Section XII C.1 - General Requirements for Air Pollution Control Equipment - Prevention of Leakage Section XII.C.2 - Emission Estimation Procedures Colorado Regulation 7, Section XVII 1. Is this tank located at a transmission/storage facility? 2. Is this condensate storage tank' located at an oil and gas exploration and production operation , well production facility , natural gas compressor station' or natural gas processing plant? 3. Is this condensate storage tank a fixed roof storage tank? 4. Are uncontrolled actual emissions of this storage tank equal to or greater than 6 tons per year VOC? Storage tank k subject to Regulation 7, Section XVII, B. L.1 & C.3 Section XVII.B - General Provisions for Air Pollution Control Equipment and Prevention of Emissions Section XVII.C.1 • Emissions Control and Monitoring Provisions Section XVII.C.3 - Recordkeeping Requirements 5. Does the condensate storage tank contain only "stabilized" liquids? No Yes Yes Yes No Storage tank is subject to Regulation 7, Section XVII.C.2 Section XVII.C.2 - Capture and Monitoring for Storage Tanks fitted with Air Pollution Control Equipment 40 CFR, Part 60, Subpart Kb, Standards of Performance for Volatile Organic Liquid Storage Vessels 1. Is the individual storage vessel capacity greater than or equal to 75 cubic meters (m') ("472 BBLs]? 2. Does the storage vessel meet the following exemption in 60.111b(d)(4)? a. Does the vessel has a design capacity less than or equal to 1,589.874 m' ('10,000 BBL) used for petroleum' or condensate stored, processed, or treated prior to custody transfer' as defined in 60.111b? 3. Was this condensate storage tank constructed, reconstructed, or modified (see definitions 40 CFR, 6412) after July 23, 1984? 4. Does the tank meet the definition of "storage vessel"' in 60.11 lb? 5. Does the storage vessel store a "volatile organic liquid (VOL)"' as defined in 60.111b? 6. Does the storage vessel meet any one of the following additional exemptions: a. Is the storage vessel a pressure vessel designed to operate in excess of 204.9 kPa (`29.7 psi) and without emissions to the atmosphere (60.110b(d)(2))?; or b. The design capacity is greater than or equal to 151 m' ['950 BBL] and stores a liquid with a maximum true vapor pressure' less than 35 kPa (60.110b(b))?; or c. The design capacity is greater than or equal to 75 M' (`472 BBLi but less than 151 m' ('950 BBL] and stores a liquid with a maximum true vapor pressure' less than 15.0 kPa(60.110b(b))? Storage Tar Continue-' Go to the n Go to the n Source is st Source is st 1 Storage Tar Storage Tank is not subject to NSPS Kb Subpart A, General Provisions §60.112b - Emissions Control Standards for VOC §60.113b - Testing and Procedures §60.115b - Reporting and Recordkeeping Requirements 460.116b - Monitoring of Operations 40 CFR, Part 60, Subpart 0000, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution 1. Is this condensate storage vessel located at a facility in the onshore oil and natural gas production segment, natural gas processing segment or natural gas transmission and storage segment of the industry? 2. Was this condensate storage vessel constructed, reconstructed, or modified (see definitions 40 CFR, 60.2) between August 23, 2011 and September 18, 2015? 3. Are potential VOC emissions' from the individual storage vessel greater than or equal to 6 tons per year? 4. Does this condensate storage vessel meet the definition of "storage vessel" per 60.5430? 5. Is the storage vessel subject to and controlled in accordance with requirements for storage vessels in 40 CFR Part 60 Subpart Kb or 40 CFR Part 63 Subpart HH? Storage Tank is not subject to NSPS 0000 No Subpart A, General Provisions per §60.5425 Table 3 §60.5395 - Emissions Control Standards for VOC §60.5413 - Testing and Procedures 460.5395(g) - Notification, Reporting and Recordkeeping Requirements §60.5416(c) - Cover and Closed Vent System Monitoring Requirements §60.5417 - Control Device Monitoring Requirements [Note: If a storage vessel is previously determined to be subject to NSPS 0000 due to emissions above 6 tons per year VOC on the applicability determination date, It should remain subject to NSPS 0000 per 60.5365(e)(2) even if potential VOC emissions drop below 6 tons per year] 40 CFR, Part 63, Subpart MACT Hit Oil and Gas Production Facilities 1. Is the storage tank located at an oil and natural gas production facility that meets either of the following criteria: a. A facility that processes, upgrades or stores hydrocarbon liquids' (63.760(a)(2)); OR b. A facility that processes, upgrades or stores natural gas prior to the point at which natural gas enters the natural gas transmission and storage source category or is delivered to a final end user' (63.760(a)(3))? 2. Is the tank located at a facility that is major' for HAPs? 3. Does the tank meet the definition of "storage vessel"' in 63.761? 4. Does the tank meet the definition of "storage vessel with the potential for flash emissions"' per 63.761? 5. Is the tank subject to control requirements under 40 CFR Part 60, Subpart Kb or Subpart 0000? No Storage Tank is not subject to MACT HH Subpart A, General provisions per §63.764 (a) Table 2 §63.766 - Emissions Control Standards §63.773 - Monitoring §63.774 - Recordkeeping §63.775 - Reporting RACT Review RACT review is required if Regulation 7 does not apply AND if the tank is in the non -attainment area. If the tank meets both criteria, then review RACT requirements. Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations. and Air Quality Control Commission regulations This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act,, its implementing regulations, and Air Quality Control Commission regulations. the language of the statute or regulation will control. The use of non -mandatory language such as 'recommend. " 'may.' 'should, ' and 'can,' is intended to describe APCD interpretations and recommendations Mandatory terminology such as 'must' and "required are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself Continue-' Storage Tar Continue - Storage la; Condensate Storage Tank(s) Emissions Inventory 022 Condensate Tank Facility AIRs ID: 12 County A020 Plant 022 Point Section 02 - Equipment Description Details Detailed Emissions Unit Description: s. tt-as� w� x ..oco ₹xx a. vans a* v Two 1000 981 tanks for Storage of stabilized condensate if ulds «.«axe. x "• ;=^�~x x Y � x x 4x0 p - x.xxwxaC rxxxwxs.Js��(c,:.,-.,xxa..tY5.%xx x:� �... %xx ^ ^ 9 ��'2.fXYn'f.�ih>x9'RSC`'.214Xx F.3"'�1MF'YQ'Z%1 •••• • Emission Control Device Enclosed combustor(s) Description: Requested Overall VOC & HAP Control Efficiency %: Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Storage Tank(s) Actual Condensate Throughput = 730,000 Barrels (bbl) per year Actual Condensate Throughput While Emissions Controls Operating = Requested Permit Limit Throughput = 730,000 Barrels (bbl) per year Requested Monthly Throughput = 62000 Barrels (bbl) per month Potential to Emit (PTE) Condensate Throughput <S6,0-003 Barrels (bbl) per year Secondary Emissions - Combustion Device(s) Heat content of waste gas = 4059 Btu/scf Volume of waste gas emitted per BBL of liquids produced = 1.33 scf/bbl Actual heat content of waste gas routed to combustion device = Requested heat content of waste gas routed to combustion device = Potential to Emit (PTE) heat content of waste gas routed to combustion device = Secondary Emissions - Combustion Device(s) pilot Pilot Volume to ECD = Pilot Fuel HHV = 166.6666667 scfh 1.46 MMscf/yr 1030 btu/scf Requested heat content of pilot fuel routed to combustion device = Section 04 - Emissions Factors & Methodologies Will this storage tank emit flash emissions? 0 MMBTU per year 3,941 MM BTU per year 4,729 MMBTU per year 1,504 MMBTU per year Emission Factors Condensate Tank Pollutant Uncontrolled Controlled (lb/bbl) (lb/bbl) Emission Factor Source (Condensate Throughput) (Condensate Throughput) VOC 0.259 1.30E-02 Este S dfft: EPA TANKS £.'F. 41forkirig and Breat Benzene 0.0040 2.00E-04 Site Specific EPA TANKS ES, Working and Bf ea . Toluene 0.0017 8.50E -0S Site Specific EPA TANKS E.F. Working and areas Ethylbenzene 0+0001 5.75E-06 Site Specific EPA TANKS E.F.. Working and areat Xylene 0.0002 8.22E-06 Site Specific EPA TANKS E.F. Working and 8reat`. n -Hexane 0.00E+00 Site Specific EPA TANKS E.F. Working and Rreat: 224 TMP O.QOE+00 Site Specific EP wl{ ( 5( -? Yi ••d n?i L"' .>, >.. _`f?c EPA , ;, n s,.?5 ?...P, ��, �a'k .:. £zcr �• I Control Device Uncontrolled Uncontrolled Pollutant (lb/MMBtu) (lb/bbl) Emission Factor Source (waste heat combusted) (Condensate Throughput) PM10 0.0075 0.0000 Air' -42 fat e 1.s°-:2 PM Z /PM.L.5i AP-42Tab e 1;42" (PN110/r. AP -42 Chapte:r 13.5 inthistrn L iore':i , ; _< AR -42 C'h : PM2.5 0.0075 0.0000 NOx 0.0680 0.0004 CO 03100 0.0017 Control Device Pilot Emission Factor Source Uncontrolled Uncontrolled Pollutant (lb/MMBtu) (lb/MMscf) (Fuel gas combusted) (Fuel gas combusted) PM10 0.0075 7.6745 AP -42 Table 1.4-2 (PM10/PM.2.5) AP -42 Table 1.4-2 (PM10/PM,2.5) AP -42 Chapter 13.5 Industrial Flares (NOx) AP -42 Chapter 13.5 Industrial Flares (CO) PM2.5 0.0075 7.6745 NOx 0.0680 70.0400 CO 0.3100 319.3000 Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) VOC 113.4 94.5 94.5 94.5 4.7 803 PM10 PM2.5 NOx 0.0 0.0 0.0 0.0 0.0 3 0.0 0.0 0.0 0.0 0.0 3 0.2 0.0 0.0 0.2 0.2 31 CO 0.7 0.0 0.0 0.8 0.8 143 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Barrels (bbl) per year 73 of 76 K:\PA\2019\19WE0081.CP1.xlsm Condensate Storage Tank(s) Emissions Inventory Benzene Toluene Ethylbenzene 3504 2920 2920 2920 146 1489 1241 1241 1241 62 101 84 84 84 4 Xylene 144 120 120 120 6 n -Hexane 0 0 0 0 0 224 TMP 0 0 0 0 0 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit Regulation 7, Section XII.C, D, E, F Storage Tank is not subject to Regulation 7, Section XII.C-F Regulation 7, Section XII.G, C Storage Tank is not subject to Regulation 7, Section XII.G Regulation 7, Section XVII.B, C.1, C.3 Storage tank is subject to Regulation 7, Section XVII, B, C.1 & C.3 Regulation 7, Section XVII.C.2 Storage Tank is not subject to Regulation 7, Section XVII.C.2 Regulation 6, Part A, NSPS Subpart Kb Storage tank is subject to NSPS Kb Regulation 6, Part A, NSPS Subpart OOOO Storage Tank is not subject to NSPS OOOO Regulation 8, Part E, MACT Subpart HH Storage Tank is not subject to MACT HH (See regulatory applicability worksheet for detailed analysis) 74 of 76 K:\PA\2019\19WE0081.CP1.xlsm Condensate Storage Tank(s) Emissions Inventory Section 07 - Initial and Periodic Sampling and Testing Requirements Does the company use the state default emissions factors to estimate emissions? If yes, are the uncontrolled actual or requested emissions estimated to be greater than or equal to 80 tons VOC per year? If yes, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor based on guidelines in PS Memo 05-01. Yes Does the company use a site specific emissions factor to estimate emissions? If yes and if there are flash emissions, are the emissions factors based on a pressurized liquid sample drawn at the facility being permitted? This sample should be considered representative which generally means site -specific and collected within one year of the application received date. However, if the facility has not been modified (e.g., no new wells brought on-line), then it may be appropriate to use an older site -specific sample. If no, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor based on guidelines in PS Memo 05-01. Does the company request a control device efficiency greater than 95% for a flare or combustion device? If yes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling Section 08 - Technical Analysis Notes Source used EPA tanks for working and breathing emisisons with an RVP of 9.4 psia. I believe that this is sufficiently conservative that I will not require testing. Source does not expect flashing emissions. Source tanks are larger than 950 BBL, storing a liquid with greater than 3.5 kPA true vapor pressure. Calculating pilot light emissions still do not bring secondary emissions for combustor to reportable levels, although combustion emissions for pilot lights were calculated on this point. Source suggested grouping secondary emissions for these tanks and the corresponding loadout, but I have maintained them as separate emisisons points, even for secondary emissions. Therefore, CO emissions for this point do not rise to reportable thresholds. Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 022 Process # 01 SCC Code Uncontrolled Emissions Pollutant Factor Control % Units PM10 0.00 0 Ib/1,000 gallons condensate throughput PM2.5 0.00 0 lb/1,000 gallons condensate throughput NOx 0.01 0 lb/1,000 gallons condensate throughput VOC 6.2 95 lb/1,000 gallons condensate throughput CO 0.06 0 lb/1,000 gallons condensate throughput Benzene 0.10 95 lb/1,000 gallons condensate throughput Toluene 0.04 95 lb/1,000 gallons condensate throughput Ethylbenzene 0.00 95 lb/1,000 gallons condensate throughput Xylene 0.00 95 lb/1,000 gallons condensate throughput n -Hexane 0.00 95 lb/1,000 gallons condensate throughput 224 TMP 0.00 95 Ib/1,000 gallons condensate throughput 75 of 76 K:\PA\2019\19WE0081.CP1.xlsm Condensate Tank Regulatory Analysis Worksheet Colorado Regulation 3 Parts A and B - APEN and Permit Requirements Source is in the Attainment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Is the construction date (service date) prior to 12/30/2002 and not modified after 12/31/2002 (See PS Memo 0501 Definitions 1.12 and1.14 and Section 2 for additional guidance on grandfather applicability)? 3. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section II.D.3)? Source requires a permit Yes No NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Is the construction date (service date) prior to 12/30/2002 and not modified after 12/31/2002 (See PS Memo 05-01 Definitions 1.12 and1.14 and Section 2 for additional guidance on grandfather applicability)? 3. Are total facility uncontrolled VOC emissions greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section 11.0.2)? No iou have indicrtcd that source is in the Attainment Area Colorado Regulation 7, Section XII.C-F 1. Is this storage tank located in the 8 -hr ozone control area or any ozone non -attainment area or attainment/maintenance area? 2. Is this storage tank located at an oil and gas exploration and production operation', natural gas compressor station or natural gas drip station? 3. Is this storage tank located upstream of a natural gas processing plant? y£ No Storage Tank is not subject to Regulation 7, Section XII.C-F Section XII CA - General Requirements for Air Pollution Control Equipment - Prevention of Leakage Section XII C.2 - Emission Estimation Procedures Section XII.D - Emissions Control Requirements Section XII.E - Monitoring Section XII F - Recordkeeping and Reporting Colorado Regulation 7, Section XII.G 1. Is this storage tank located in the 8 -hr ozone control area or any ozone non -attainment area or attainment/maintenance area? 2. Is this storage tank located at a natural gas processing plant? 3. Does this storage tank exhibit "Flash" (e.g. storing non -stabilized liquids) emissions and have uncontrolled actual emissions greater than or equal to 2 tons per year VOC? Storage Tank is not subject to Regulation 7, Section XII.G No Yes Section XI1.6.2 - Emissions Control Requirements Section XII.C.1 - General Requirements for Air Pollution Control Equipment - Prevention of Leakage Section XII.C.2 - Emission Estimation Procedures Colorado Regulation 7, Section XVII 1. Is the tank located at a transmission/storage facility? 2. Is this condensate storage tank' located at an oil and gas exploration and production operation , well production facility', natural gas compressor station' or natural gas processing plant? 3. Is this condensate storage tank a fixed roof storage tank? 4. Are uncontrolled actual emissions` of this storage tank equal to or greater than 6 tons per year VOC? Storage tank is subject to Regulation 7. Section XVII, B. C.1 & C.3 No No Yes Section XVII.B - General Provisions for Air Pollution Control Equipment and Prevention of Emissions Section XVII.C.1 - Emissions Control and Monitoring Provisions Section XVII.C.3 - Recordkeeping Requirements 5. Does the condensate storage tank contain only "stabilized" liquids? Yes Yes Storage Tank is not subject to Regulation 7, Section XVII.C.2 Section XVII.C.2 - Capture and Monitoring for Storage Tanks fitted with Air Pollution Control Equipment 40 CFR, Part 60, Subpart Kb, Standards of Performance for Volatile Organic Liquid Storage Vessels 1. Is the individual storage vessel capacity greater than or equal to 75 cubic meters (nt3) [`472 BBLs)? 2. Does the storage vessel meet the following exemption in 60.111b(d)(4)? a. Does the vessel has a design capacity less than or equal to 1,589.874 m' [`10,000 BBL] used for petroleum' or condensate stored, processed, or treated prior to custody transfer' as defined in 60.111b? 3. Was this condensate storage tank constructed, reconstructed, or modified (see definitions 40 CFR, 60.2) after July 23, 1984? 4. Does the tank meet the definition of "storage vessel'' in 60.111b? 5. Does the storage vessel store a "volatile organic liquid (VOL)"' as defined in 60.111b? 6. Does the storage vessel meet any one of the following additional exemptions: a. Is the storage vessel a pressure vessel designed to operate in excess of 204.9 kPa (`29.7 psi) and without emissions to the atmosphere (60.11ob(d)(2))?; or b. The design capacity is greater than or equal to 151 m' [`950 BBL] and stores a liquid with a maximum true vapor pressure' less than 35 kPa (60.110b(b))?; or c. The design capacity is greater than or equal to 75 M' [`472 BBL] but less than 151 m3 (`950 BBL) and stores a liquid with a maximum true vapor pressure' less than 15.0 kPa(60.110b(b))? yes Na Yes Yes Yes No Source Req Go to next Source Req Storage Tar Storage Tar Storage Tar Storage Tai Continue-' Go to then Go to the n Source is st Storage Tar Go to then Go to then Go to then Go to then Go to then Source is st Storage tank is subject to NSPS Kb Subpart A, General Provisions §60.112b - Emissions Control Standards for VOC §60.113b - Testing and Procedures §60.115b - Reporting and Recordkeeping Requirements §60.116b - Monitoring of Operations 40 CFR, Part 60. Subpart 0000, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution 1. Is this condensate storage vessel located at a facility in the onshore oil and natural gas production segment, natural gas processing segment or natural gas transmission and storage segment of the industry? 2. Was this condensate storage vessel constructed, reconstructed, or modified (see definitions 40 CFR, 60.2) between August 23, 2011 and September 18, 2015? 3. Are potential VOC emissions= from the individual storage vessel greater than or equal to 6 tons per year? 4. Does this condensate storage vessel meet the definition of "storage vessel"' per 60.5430? 5. Is the storage vessel subject to and controlled in accordance with requirements for storage vessels in 40 CFR Part 60 Subpart Kb or 40 CFR Part 63 Subpart HH? No No No Storage Tank Is not subject to NSPS 0000 Subpart A, General Provisions per §605425 Table 3 §60.5395 - Emissions Control Standards for VOC 460.5413 - Testing and Procedures §60.5395(g) - Notification, Reporting and Recordkeeping Requirements 460.5416(c) - Cover and Closed Vent System Monitoring Requirements §60.5417 • Control Device Monitoring Requirements (Note: If a storage vessel Is previously determined to be subject to NSPS 0000 due to emissions above 6 tons per year VOC on the applicability determination date, It should remain subject to NSPS OOOO per 60.5365(e)(2) even if potential VOC emissions drop below 6 tons per year) 40 CFR, Part 63, Subpart MACT NH, Oil and Gas Production Facilities 1. Is the storage tank located at an oil and natural gas production facility that meets either of the following criteria: a. A facility that processes, upgrades or stores hydrocarbon liquids= (63.760(a)(2)); OR b. A facility that processes, upgrades or stores natural gas prior to the point at which natural gas enters the natural gas transmission and storage source category or is delivered to a final end user' (63.760(a)(3))? 2. Is the tank located at a facility that is major' for HAPs? 3. Does the tank meet the definition of "storage vessel'` in 63.761? 4. Does the tank meet the definition of "storage vessel with the potential for flash emissions"' per 63.761? 5. Is the tank subject to control requirements under 40 CFR Part 60, Subpart Kb or Subpart 0000? Storage Tank is not subject to MAC Hh Subpart A, General provisions per 463.764 (a) Table 2 §63.766 • Emissions Control Standards §63.773 • Monitoring §63.774 - Recordkeeping §63.775 - Reporting RACT Review RACT review is required if Regulation 7 does not apply AND if the tank is in the non -attainment area. If the tank meets both criteria, then review RACT requirements. Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act. its implementing regulations. and Alf Quality Control Commission regulations. This document is not a rule or regulation. and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable In the event of any conflict between the language of this document and the language of the Clean Air Act.. its implementing regulations, and Air Quality Control Commission regulations. the language of the statute or regulation will control. The use of non -mandatory language such as 'recommend,' 'may.' 'should.' and 'can,' is intended to describe APCD interpretations and recommendations Mandatory terminology such as 'must" and 'required' are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself No Continue -' Storage Tar Continue Storage Tar Permit number: Date issued: Issued to: COLORADO Air Pollution Control Division Department of Public Health & Environment CONSTRUCTION PERMIT 19WE0081 Facility Name: Plant AIRS ID: Physical Location: County: General Description: Issuance: Cureton Front Range LLC Hookside Gas Plant 123/A020 SE SEC 30 T9N R60W Weld County Natural Gas Processing Plant, Equipment or activity subject to this permit: Facility Equipment ID AIRS Point Equipment Description Emissions Control Description Amine1 001 One (1) Methyldiethanolamine (MDEA) natural gas sweetening unit (Make: TBD, Model: TBD, Serial Number: TBD) with a design capacity of 20O MMscf per day. This emissions unit is equipped with 2 (Make: TBD, Model: TBD) amine pump with a design capacity of 800 gallons per minute. This natural gas sweetening unit is equipped with a still vent, flash tank, and amine regeneration heat source (AIRS Point 011). Emissions from the still vent are routed to the Thermal Oxidizer. Emissions from the flash tank are routed directly to the closed -loop system. Amine2 002 One (1) Methyldiethanolamine (MDEA) natural gas sweetening unit (Make: TBD, Model: TBD, Serial Number: TBD) with a design capacity of 60 MMscf per day. This emissions unit is equipped with 2 (Make: TBD, Model: TBD) amine pump with a design capacity of 250 gallons per minute. This natural gas sweetening unit is equipped with a still vent, flash tank, and amine regeneration heat source (AIRS Point 008). Emissions from the still vent are routed to the Thermal Oxidizer. Emissions from the flash tank are routed directly to the closed -loop system. Amine3 003 One (1) Methyldiethanolamine (MDEA) natural gas sweetening unit (Make: TBD, Model: TBD, Serial Number: TBD) with a design capacity of 20 MMscf per day. This emissions unit is equipped with 2 (Make: TBD, Model: TBD) amine pump with a design capacity of 100 gallons per minute. This natural gas sweetening unit is equipped with a Emissions from the still vent are routed to the Thermal Oxidizer. Emissions from the flash tank are routed directly COLORADO Air Pollution Control Division (htP3ttrtb?r8 0! W[:,c -Hratth tJ E w rtlnment Page 1 of 34 still vent, flash tank, and amine regeneration heat source (AIRS Point 013). to the closed -loop system. TEG1 004 One (1) Triethyilene glycol (TEG) natural gas dehydration unit (Make: TBD, Model: TBD, Serial Number: TBD) with a design capacity of 30 MMscf per day. This emissions unit is equipped with 1 (Make: TBD, Model: TBD) electric driven glycol pump with a design capacity of 3.75 gallons per minute. This dehydration unit is equipped with a still vent, flash tank, and reboiler burner. Emissions from the still vent are routed to the Enclosed Flare. Emissions from the flash tank are routed directly to the closed -loop system. TEG2 005 One (1) Triethyiene glycol (TEG) natural gas dehydration unit (Make: TBD, Model: TBD, Serial Number: TBD) with a design capacity of 30 MMscf per day. This emissions unit is equipped with 1 (Make: TBD, Model: TBD) electric driven glycol pump with a design capacity of 3.75 gallons per minute. This dehydration unit is equipped with a still vent, flash tank, and reboiler burner. Emissions from the still vent are routed to the Enclosed Flare. Emissions from the flash tank are routed directly to the closed -loop system. TK1 006 One (1) 400 BBL Emergency tank for off -spec stabilized condensate'' Enclosed Combustor TK2 - TK6 007 Five (5) 400 bbl produced water tanks Enclosed Combustor HTR2 008 One (1) natural gas heater(s) (Make: TBD, Model: TBD, Serial Number: TBD) each with a design heat input rate of 17.5 MMBtu/hr. Each unit is equipped with low-N0x burners. Each unit is an amine regeneration heater. None HTR3 009 One (1) natural gas heater(s) (Make: TBD, Model: TBD, Serial Number: TBD) each with a design heat input rate of 11 MMBtu/hr. Each unit is equipped with low-N0x burners. Each unit is a hot oil heater. None HTR4 010 One (1) natural gas heater(s) (Make: TBD, Model: TBD, Serial Number: TBD) each with a design heat input rate of 16.5 MMBtu/hr. Each unit is equipped with low-NOx burners. Each unit is a molecular sieve regeneration heater. None HTR5 011 One (1) natural gas heater(s) (Make: TBD, Model: TBD, Serial Number: TBD) each with a design heat input rate of 55 MMBtu/hr, Each unit is equipped with low-N0x burners. Each unit is an amine regeneration heater. None HTR6 012 One (1) natural gas heater(s) (Make: TBD, Model: TBD, Serial Number: TBD) each with a design heat input rate of 18 MMBtu/hr. Each unit is equipped with low-N0x burners. Each unit is a hot oil heater. None Pigging 014 Venting of gas from four (4) pig receivers during depressurization. None FUG1 015 Fugitive emission component leaks from a natural gas processing plant, including components from all process trains, totaling 280 MMSCFD of gas processed NSPS 0000a- compliant leak detection and repair program TK7 017 One (1) 750 bbl methanol storage tank None COLORADO Air Pollution Control Division De-aarmeni of Pubbc Health Er E w ronmet Page 2 of 34 LOAD4 018 Unloading of condensate from pressurized tanks to pressurized tank trucks. Loadout occurs via vapor balance and emissions are only released to the atmosphere during hose disconnect. None LOAD3 019 Loadout of stabilized condensate in trucks by submerged fill. Enclosed Combustor LOAD2 020 Loading of mixed condensate liquids into tank trucks by submerged fill Enclosed Combustor TK8 - TK9 021 Two (2) 400 BBL tanks for storage of mixed liquids (condensate and produced water) Enclosed Combustor TK10 - TK11 022 Two (2) 1000 BBL tanks for storage of stabilized condensate liquids Enclosed Combustor This permit is granted subject to all rules 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 seq), to the specific general terms and conditions included in this document and the following specific terms and conditions. REQUIREMENTS TO SELF -CERTIFY FOR FINAL AUTHORIZATION YOU MUST notify the Air Pollution Control Division (the Division) no later than fifteen days of the latter of commencement of operation or issuance of this permit, by submitting a Notice of Startup form to the Division for the equipment covered by this, permit. The Notice of Startup form may be downloaded online at www.colorado.gov/pacific/cdphe/other-air-permitting- notices. Failure to notify the Division of startup of the permitted source is a violation of Air Quality Control Commission (AQCC) Regulation Number 3, Part B, Section III.G.1. and can result in the revocation of the permit. 2. Within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit, compliance with the conditions contained in this permit shall be demonstrated to the Division. it is the owner or operator's responsibility to self -certify compliance with the conditions. Failure todemonstrate compliance within 180 days may result in revocation of the permit. A self certification form and guidance on how to self -certify compliance as required by this permit may be obtained online at www.colorado.gov/pacific/cdphe/air-permit-setf- certification. (Regulation Number 3, Part B, Section 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 commenceconstruction/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. (Regulation Number 3, Part B, Section III.F.4.) 4. 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. (Regulation Number 3, Part B, Section III.E.) 5. Point 001, 002, 003: The following information shall be provided to the Division within fifteen (15) days of the latter of commencement of operation or issuance of this permit. • The amine unit manufacturer name, model number and serial number • The amine circulation pump manufacturer name and model number COLORADO Air Pollution Control Division ,)EEattinelt8 at Pub,c Health $ Eraatonment Page 3 of 34 This information shall be included with the Notice of Startup submitted for the equipment. (Reference: Regulation Number 3, Part B, III.E.) 6. Point 004, 005: The following information shall be provided to the Division within fifteen (15) days of the latter of commencement of operation or issuance of this permit. • The dehydrator manufacturer name, model number and serial number • The glycol circulation pump manufacturer name and model number This information shall be included with the Notice of Startup submitted for the equipment. (Reference: Regulation Number 3, Part B, III.E.) 7. Point 008, 009, 010, 011, 012: The following information shall be provided to the Division within fifteen (15) days of the latter of commencement of operation or issuance of this permit. • Manufacturer • Model Number • Serial Number This information shall be included with the Notice of Startup submitted for the equipment. (Regulation Number 3, Part B, III.E.) 8. 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 9. Emissions of air pollutants shall not exceed the following limitations. (Regulation Number 3, Part B, Section II.A.4.) Monthly Limits: Facility Equipment ID AIRS Point Process Pounds per Month Emission Type PMZ,5 PMtp SOX H2S NO), VOC CO Aminel 001 01 -- 1,017 11 203 572 170 Point 02 --- --- --- --- 1,577 62 1,320 Amine2 002 01 --- --- --- --- --- 192 --- Point Amine3 003 01 --- --- --- --- --- 88 --- Point TEG1 004 01 --- --- --- --- --- 705 --- Point TEG2 005 01 --- --- --- --- --- 705 --- Point TK1 006 01 --- --- --- --- --- 96 --- Point TK2 - TK6 007 01 --- --- --- --- --- 264 336 Point HTR2 008 01 --- --- --- --- 638 --- 521 Point HTR3 009 01 --- --- --- --- 401 --- --- Point HTR4 010 01 --- --- --- --- 602 --- 491 Point COLORADO Air Pollution Control Division L7C^m inert o1 F.:'tdr: He3'ii'13J Er:won r n Page 4 of 34 Facility Equipment ID AIRS Point Process Pounds per Month Emission Type PM2.s PMtp SO,, HiS N0,V0C CO HTR5 011 01 --- --- --- --- 2006 --- 1637 Point HTR6 012 01 --- --- --- --- 656 --- 536 Point Pigging 014 01 --- --- --- --- --- 344 --- Point 02 03 04 FUG1 015 01 --- --- --- --- --- 3,153 --- Fugitive L0AD4 018 01 --- --- --- --- --- 564 --- Point L0AD3 019 01 --- --- --- -- --- 732 --- Point L0AD2 020 01 --- --- --- --- --- 79 --- Point TK8 - TK9 021 01 --- --- --- --- --- 4,587 1,142 . Point TK10 - TK11 022 01 --- --- --- --- --- 804 --- Point Note: 1. Monthly limits are based • on a 31 -day month.' 2. Process 01 and 02 for the amine unit covered under Point 001, are as follows: a. Process 01: Still tent waste gas routed to the thermal oxidizer. b. Process 02: Combustion of assist gas by the thermal oxidizer. 3 Process 01 04 for the pigging operation covered under Point 014 are as follows: a ;Process 01: Depressurization of 6" pig receiver b. Process 02: Depressurization of 8" pig receiver c. Process 03: Depressurization of 10" pig receiver d. Process 04: Depressurization of 16" pig receiver The owner or operator shall calculate monthly emissions based on the calendar month. Facility wide emissions of each individual hazardous air pollutant shall not exceed 1,359 pounds per month. Facility -wide emissions of total hazardous air pollutants shall not exceed 3,398 pounds per month. The facility -wide emissions limitation for hazardous air pollutants shall apply to all permitted emission units at this facility. COLORADO Air Pollution Control Division Depamnent of iubbc Health zr &llama-mem Page 5 of 34 Annual Limits: Facility Equipment ID AIRS Point Process Tons Per Year Emission Type PM2.5 PM10 SO4� H2S N0,� V0C CO Amine1 001 01 --- --- 6.0 0.1 1.2 3.4 1.0 Point 02 --- --- --- --- 9.3 0.4 7.8 Amine2 002 01 --- --- --- --- --- 1.1 --- Point Amine3 003 01 --- --- --- --- ---" _ 0.5 --- Point TEG1 004 01 --- --- --- --- --- 4.2 --- Point TEG2 005 01 --- --- --- --- --- 4.2 --- Point TK1 006 01 --- --- --- --- --- 0.6 --- Point TK2 - TK6 007 01 --- --- --- --- --- 1.6 2.0 Point HTR2 008 01 --- --- --- --- '' 3.8 --- 3.1 Point HTR3 009 01 --- --- --- --- 2.4 --- --- Point HTR4 010 01 --- --- --- --- 3.5 --- 2.9 Point HTR5 011 01 --- --- --- --- 11.8 --- 9.6 Point HTR6 012 01 --- --- --- --- 3.9 --- 3.2 Point Pigging 014 01 --- --- --- --- --- 2.0 --- Point 02 03 04 FUG1 015 01 --- --- --- --- --- 18.6 --- Fugitive LOAD4 018 01 --- --- --- --- --- 3.3 --- Point LOAD3 019 01 --- --- --- --- --- 4.3 --- Point LOAD2 020 01 --- --- --- --- --- 0.5 --- Point TK8 - TK9 021 01 --- --- --- --- --- 27.0 6.7 Point TK10 - TK11 022 01 --- --- --- --- --- 4.7 --- Point Note: 1. See "Notes to Permit Holder" for information on emission factors and methods used to calculate limits. 2. Process 01 and 02 for the amine unit covered under Point 001, are as follows: COLORADO Air Pollution Control Division atth U E^t,tOilTx@S Page 6 of 34 a. Process 01: Still vent waste gas routed to the thermal oxidizer. b. Process 02: Combustion of assist gas by the thermal oxidizer. 3. Process 01 - 04 for the pigging operation covered under Point 014 are as follows: a. Process 01: Depressurization of 6" pig receiver b. Process 02: Depressurization of 8" pig receiver c. Process 03: Depressurization of 10" pig receiver d. Process 04: Depressurization of 16" pig receiver Facility -wide emissions of each individual hazardous air pollutant shall not exceed 8.0 tons per year. Facility -wide emissions of total hazardous air pollutants shall not exceed 20.0 tons per year. The facility -wide emissions limitation for hazardous air pollutants shall apply to all permitted emission units at this facility. During the first twelve (12) months of operation, compliance with both the monthly and annual emission limitations is required. After the first twelve (12) months of operation, compliance with only the annual limitation is required. Compliance with the annual limits, for criteria and hazardous air pollutants, 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 actual emissions each month and keep a compliance record on site or at a local field office with site responsibility for Division review. 10. Point 001, 002, 003: Compliance with the emission limits in this, permit shall be determined by using the last measured still vent waste gas sample composition, per the required sampling frequency as stated in this permit for each unit, and monthly measured waste gas flow volumes for each amine unit. 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 and monthly measured waste gas flow volume for each amine unit. A control efficiency of 9.8%, based on operating the control device in accordance with the OIM Plan, shall be applied to the uncontrolled VOC, HAP and H2S emissions. 11. Point 001, 002, 003: 100% of emissions that result from the flash tank associated with the amine unit shall be recycled to the plant inlet or sent to the plant fuel system. 12. Points 004, 005: Compliance with the emission limits in this permit shall be demonstrated by running the GRI GlyCalc model version 4.0 or higher on a monthly basis using the most recent extended wet gas analysis and recorded operational values, including: dry gas throughput, lean glycol recirculation rate, wet gas inlet temperature, and wet gas inlet pressure. Recorded operational values, except for gas throughput, shall be averaged on a monthly basis for input into the model and be provided to the Division upon request. 13. Points 004, 005: On a weekly basis, the owner or operator shall monitor and record operational values including: Wet gas inlet temperature and pressure. These records shall be maintained for a period of five years. 14. Point 015: The owner or operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent inlet gas analysis, as required in the Compliance Testing and Sampling section of this permit. The owner or 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. COLORADO Air Pollution Control Division De,yarrmelt of P.;; tc ;Health Er EMIT0il.^,3ert Page 7 of 34 15. The owner or operator shall operate and maintain the emission points in the table below with the emissions control equipment as listed in order to reduce emissions to less than or equal to the limits established in this permit. (Regulation Number 3, Part B, Section III.E.) Facility Equipment ID AIRS Point Control Device Pollutants Controlled Amine1 001 Still Vent: Thermal Oxidizer (TO) VOC £t HAP Flash Tank: Recycled to Fuel Gas System N/A Amine2 002 Still Vent: Thermal Oxidizer (TO) VOC Et HAP Flash Tank: Recycled to Fuel Gas System N/A Amine3 003 Still Vent: Thermal Oxidizer (TO) VOC £t HAP Flash Tank: Recycled to Fuel Gas System N/A TEG1 004 Still Vent: Enclosed Combustor VOC a HAP Flash Tank: Recycled to Fuel Gas System N/A TEG2 005 Still Vent: Enclosed Combustor VOC Et HAP Flash Tank: Recycled to Fuel Gas System N/A TK1 006 Still Vent: Thermal Oxidizer (TO) VOC Et HAP TK2 - TK6 007 Enclosed Combustor VOC Et HAP LOAD4 018 Enclosed Combustor VOC Et HAP LOAD3 019 Enclosed Combustor VOC a HAP LOAD2 020 Enclosed Combustor VOC a HAP TK8 - TK9 021 Enclosed Combustor VOC Et HAP TK10 - TK11 022 Enclosed Combustor VOC &t HAP PROCESS! LIMITATIONS AND RECORDS 16. This source shall be limited to the following maximum processing rates as listed below. Monthly records of the actua processingrates shall be maintained by the owner or operator and made available to the Division for inspection upon request. (Regulation Number 3, Part B, Section I I . A.4. ) COLORADO Air Pollution Control Division Deortfrfer•;tremorment Page 8 of 34 Facility Equipment ID AIRS Point Process Process Parameter Annual Limit Monthly Limit (31 days) AMINE1 001 --- Natural Gas Throughput 73,000 MMSCF 6,200 MMSCF 01 Still vent waste gas routed to the thermal oxidizer 1,810.2 MMSCF 153.7 MMSCF 02 Combustion of assist gas and pilot gas by the thermal oxidizer 184.0 MMSCF 15.6 MMSCF AMINE2 002 --- Natural Gas Throughput 21,900 MMSCF 1,860 MMSCF 01 Still vent waste gas routed to the thermal oxidizer 658.7 MMSCF 55.9 MMSCF AMINE3 003 -- Natural Gas Throughput 7,300 MMSCF 620 MMSCF 01 Still vent waste gas routed to the thermal oxidizer 181.5 MMSCF 15.4 MMSCF TEG1 004 01 Dry Gas Throughput 30 MMscf 2.55 MMscf TEG2 005 01 Dry Gas Throughput 30 MMscf 2.55 MMscf TK1 006 01 Throughput of stabilized condensate 9,125 BBL 775 BBL TK2 - TK6 007 01 Throughput of produced water '' 237,250 BBL 20150 BBL HTR2 008 01 Consumption of Natural Gas as fuel 148.8 MMSCF 12.6 MMSCF HTR3 009 01 Consumption of Natural Gas as fuel 93.6 MMSCF 7.9 MMSCF HTR4 010 01 Consumption of Natural Gas as fuel 140.3 MMSCF 11.9 MMSCF HTR5 011 01 Consumption of Natural Gas as fuel 467.8 MMSCF 39.7 MMSCF HTR6 012 01 Consumption of Natural Gas as fuel 153.1 MMSCF 13.0 MMSCF PIGGING 014 01 365 events 31 events 02 Depressurization Events 365 events 31 events 03 365 events 31 events 04 365 events 31 events TK7 017 01 Throughput of methanol 8,873 BBL 754 BBL LOAD4 018 01 Pressurized NGL loading events 3066 events 261 events LOAD3 019 01 Loadout of Stabilized Condensate 730,000 BBL 62,000 BBL LOAD2 020 01 Loadout of mixed condensate liquids 78,840 BBL 6,696 BBL TK8 - TK9 021 Q1 Throughput of mixed condensate liquids 78,840 BBL 6,696 BBL TK10 - TK11 022 01 Throughput of stabilized condensate liquids 730,000 BBL 62,000 BBL Note: 1. Process 01 and 02 for the amine unit covered under Point 001, are as follows: a. Process 01: Still vent waste gas routed to the thermal oxidizer. b. Process 02: Combustion of assist gas by the thermal oxidizer. 2. Process 01 - 04 for the pigging operation covered under Point 014 are as follows: a. Process 01: Depressurization of 6" pig receiver b. Process 02: Depressurization of 8" pig receiver (COLORADO Air Pollution Control Division Lk^..asia-5es:i ti! P --obit r+eatch & i=,n.stonmerc Page 9 of 34 c. Process 03: Depressurization of 10" pig receiver d. Process 04: Depressurization of 16" pig receiver The owner or operator shall monitor monthly process rates based on the calendar month. During the first twelve (12) months of operation, compliance with both the monthly and annual throughput limitations is required. After the first twelve (12) months of operation, compliance with only the annual limitation is 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 throughput each month and keep a compliance record on site or at a local field office with site responsibility, for Division review. 17. Point 001: The owner or operator shall continuously monitor and record the following amine unit emission streams using continuous operational flow meters: • Total amine unit still vent waste gas volume routed to the thermal oxidizer, • Total assist gas volume routed to the thermal oxidizer. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in the permit and to calculate emissions as described in this permit. 18. Point 001: This unit shall be limited to the maximum lean amine circulation rate of 800 gallons per minute. The lean amine recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. (Regulation Number 3, Part B, Section II.A.4) 19. Point 002: This unit shall be limited to the maximum lean amine circulation rate of 250 gallons per minute. The lean amine recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. (Regulation Number 3, Part B, Section II.A.4) 20. Point 002, 003: The owner or operator shall continuously monitor and record the following amine unit emission stream using a continuous operational flow meter for each amine unit: • Total amine unit still vent waste gas volume routed to the thermal oxidizer, The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in the permit and to calculate emissions as described in this permit. 21. Point 003: This unit shalt be limited to the maximum lean amine circulation rate of 100 gallons per minute. The lean amine recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. (Regulation Number 3, Part B, Section II.A.4) 22. Point 001, 002, 003: The owner or operator shall continuously monitor and record the volumetric flow rate of natural gas processed by each amine unit contactor using an operational continuous flow meter at the inlet to the amine contactor. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 23. Point 004, 005: Each unit shall be limited to the maximum lean glycol circulation rate of 3.75 gallons per minute. The lean glycol recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. Glycol recirculation rate shall be monitored by one of the following methods: assuming maximum design pump rate, using glycol flow meter(s), or recording strokes per minute and converting to circulation rate. This maximum glycol circulation rate does not preclude compliance with the optimal glycol circulation rate (l.oPt) provisions under MACT HH. (Reference: Regulation Number 3, Part B, II.A.4) COLORADO Air Pollution Control Division I Dewvilent of Public Health ₹r Enwonment Page 10 of 34 24. Point 008, 009, 010, 011, 012: The owner or operator shall continuously monitor and record the volumetric flow rate of natural gas combusted as fuel for each heater using an operational continuous flow meter at the inlet of each heater. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 25. Point 014: The owner or operator shall record the following information during each pigging event. Records shall be maintained by the applicant and made available to the Division for inspection upon request. (Reference: Regulation No. 3, Part B, II.A.4) • Date and time of each pigging event. • Estimated volume of each pigging event. In order to demonstrate compliance with the emission limitations of this permit, emissions due to pigging activities shall be calculated on an annual basis. The emissions calculations shall be based on the information collected above. VOC and HAP emissions calculated from each event shall be summed to obtain emissions from vented pigging activities. The estimated volume of each pigging event shall correspond to the volumes listed in the following table: Pigging Event Type Gas Released! per Event (Scf/Event) Depressurization of 6" pig receiver 49.90 Depressurization of 8" pig receiver 95.98 Depressurization of 10" pig receiver 158.96 Depressurization of 16" pig receiver 449.35 26. Point 015: The operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent gas analysis, 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 bequest. 27. Point 019, 020: Condensate loading to truck tanks must be conducted by submerged fill. (Reference: Regulation Number 3, Part B, III.E) STATE AND FEDERAL REGULATORY REQUIREMENTS 28. This source is subject to the odor requirements of Regulation Number 2. (State only enforceable) 29. Visible emissions shall 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. (Regulation Number 1, Section II.A.1. It 4.) 30. Point 001 - 012, 014, 017 - 022: The permit number and ten digit AIRS ID number assigned by the Division (e.g. 123/4567/001) shall be marked on the subject equipment for ease of identification. (Regulation Number 3, Part B, Section III.E.) (State only enforceable) 31. Point 004, 005: The combustion device covered by this permit is subject to Regulation Number 7, Section XVII.B.2 General Provisions (State only enforceable). If a flare or other combustion device is used to control emissions of volatile organic compounds to comply with Section XVII, it shall be enclosed; have no visible emissions during normal operations, as defined under COLORADO Air Pollution Control Division aeta•mene of Nutt?i= Health ft E.nWar ent Page 11 of 34 Regulation Number 7, XVII.A.17; and be designed so that an observer can, by means of visual observation from the outside of the enclosed flare or combustion device, or by other convenient means approved by the Division, determine whether it is operating properly. This flare must be equipped with an operational auto -igniter according to the following schedule: • All combustion devices installed on or after May 1, 2014, must be equipped with an operational auto -igniter upon installation of the combustion device; 32. Point 004, 005: The glycol dehydration unit covered by this permit is subject to the emission control requirements in Regulation Number 7, Section XVII.D.3. Beginning May 1, 2015, still vents and vents from any flash separator or flash tank on a glycol natural gas dehydrator located at an oil and gas exploration and production operation, natural gas compressor station, or gas - processing plant subject to control requirements pursuant to Section XVII.D.4., shall reduce uncontrolled actual emissions of hydrocarbons by at least 95% on a rolling twelve-month basis through the use of a condenser or air pollution control equipment. 33. Point 004, 005: The glycol dehydration unit at this facility is subject to National Emissions Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities, Subpart HH. This facility shall be subject to applicable area source provisions of this regulation, as stated in 40 C.F.R Part 63, Subpart A and HH. (Regulation Number 8, Part E, Subpart A and HI -I) COLORADO Air Pollution Control Division De;sar neat of Public iitasir: #e E-aaronnsent Page 12 of 34 MACT HH Applicable Requirements Area Source Benzene emissions exemption 563.764 - General Standards 863.764 (e)(1) - The owner or operator is exempt from the requirements of paragraph (d) of this section if the criteria listed in paragraph (e)(1)(i) or (ii) of this section are met, except that the records of the determination of these criteria must be maintained as required in §63.774(d)(1). 563.764 (e)(1)(ii) - The actual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere are less than 0.90 megagram per year, as determined by the procedures specified in §63.772(b)(2) of this subpart. 563.772 - Test Methods, Compliance Procedures and Compliance Demonstration §63.772(b) - Determination of glycol dehydration unit flowrate or benzene emissions. The procedures of this paragraph shall be used by an owner or operator to determine glycol dehydration unit natural gas flowrate or benzene emissions to meet the criteria for an exemption from control requirements under §63.764(e)(1)., §63.772(b)(2) - The determination of actual average benzene emissions from a glycol dehydration unit shall be made using the procedures of either paragraph (b)(2)(i) or (b)(2)(ii) of this section. Emissions shall be determined either uncontrolled, or with federally enforceable controls in place. 563.772(b)(2)(i) - The owner or operator shall determine actual average benzene emissions using the model GRI-GLYCaIc TM, Version 3.0 or higher, and the procedures presented in the associated GRI-GLYCalc TM Technical Reference Manual. Inputs to the model shall be representative of actual operating conditions of the glycol dehydration unit and may be determined using the procedures documented in the Gas Research Institute (GRI) report entitled "Atmospheric Rich/Lean Method for Determining Glycol Dehydrator Emissions" (GRI-95/0368.1); or 563.772(b)(2)(ii) - The owner or operator shall determine an average mass rate of benzene emissions in kilograms per hour through direct measurement using the methods in §63.772(a)(1)(i) or (ii), or an alternative method according to §63.7(f). Annual emissions in kilograms per year shall be determined by multiplying the mass rate by the number of hours the unit is operated per year. This result shall be converted to megagrams per year. 563.774 - Recordkeeping Requirements §63.774 (d)(1) - An owner or operator of a glycol dehydration unit that meets the exemption criteria in §63.764(e)(1)(i) or §63.764(e)(1)(ii) shall maintain the records specified in paragraph (d)(1)(i) or paragraph (d)(1)(ii) of this section, as appropriate, for that glycol dehydration unit. 563.774 (d)(1)(ii) - The actual average benzene emissions (in terms of benzene emissions per year) as determined in accordance with §63.772(b)(2). COLORADO Air Pollution Control Division Deaattmert of' pubic Heaah Envaor ent Page 13 of 34 b. 34. Point 002: This source is subject to Regulation Number 7, Section XII.G.1 (State only enforceable). For fugitive V0C emissions from leaking equipment, the leak detection and repair (LDAR) program as provided at 40 CFR Part 60, Subpart KKK (July 1, 2016) 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, Subparts 0000 or 0000a (July 1, 2016). The operator shall comply with all applicable requirements of Section XII. 35. Point 006, 007: The combustion device covered by this permit is subject to Regulation Number 7, Section XVII.B.2. General Provisions (State only enforceable). If a flare or other combustion device is used to control emissions of volatile organic compounds to comply with Section XVII, it must be enclosed; have no visible emissions during normal operations, as defined under Regulation Number 7, XVII.A.16; and be designed so that an observer can, by means of visual observation from the outside of the enclosed flare or combustion device, or by other convenient means approved by the Division, determine whether it is operating properly. This flare must be equipped with an operational auto -igniter according to the following schedule: • All combustion devices installed on or after May 1, 2014, must be equipped with an operational auto -igniter upon installation of the combustion device; 36. Point 006, 007, 021, 022: The storage tank covered by this permit is subject to the emission control requirements in Regulation Number 7, Section XVII.C.1. The owner or operator must install and operate air pollution control equipment that achieves an average hydrocarbon control efficiency of 95%. If a combustion device is used, it must have a design destruction efficiency of at least 98% for hydrocarbons except where the combustion device has been authorized by permit prior to May 1, 2014. The source must follow the inspection requirements of Regulation Number 7, Section XVII.C.1.d. and maintain records of the inspections for a period of two years, made available to the Division upon request. This control requirement must be met within 90 days of the date that the storage tank commences operation. 37. Point 007, 021: The storage tanks covered by this permit are subject to the venting and Storage Tank Emission Management System ("STEM") requirements of Regulation Number 7, Section XVII.C.2. 38. Point 008, 009, 010, 011, 012: This source is subject to the Particulate Matter and Sulfur Dioxide Emission Regulations of Regulation 1 including, but not limited to, the following (Regulation 1, Section III.A.1 and VI.B.5. ): a. 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 III.A.1): (i) 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 )-0.26 Where:' PE = Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. New sources of sulfur dioxide shall not emit or cause to be emitted sulfur dioxide in excess of the following process -specific limitations: (i) Limit emissions to not more than two (2) tons per day of sulfur dioxide. (Regulation 1 Section VI.B.5.a.) 39. Point 008, 009, 010, 011, 012: This source is subject to the New Source Performance Standards requirements of Regulation Number 6, Part B including, but not limited to, the following (Regulation Number 6, Part B, Section II.C.): COLORADO Air Pollution Control Division Lh atmen Ct 1, -,bhp: Health & Envuonment Page 14 of 34 a. Standard for Particulate Matter - On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere of any particulate matter which is: (i) For fuel burning equipment generating greater than one million but less than 250 million Btu per hour heat input, the following equation will be used to determine the allowable particulate emission limitation: PE=0.5(FI )-0.26 Where: PE is the allowable particulate emission in pounds per million Btu heat input. Fl is the fuel input in million Btu per hour. If two or more units connect to any opening, the maximum allowable emission rate shall be the sum of the individual emission rates. (ii) Greater than 20 percent opacity. 40. Point 008, 009, 010, 011, 012: This source is subject to the New Source Performance Standards requirements of Regulation Number 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 Reporting and recordkeeping requirements: o §60.48c(a) - The owner or operator of each affected facility shall submit notification of the date of construction or reconstruction and actual startup, as provided by §60.7 of this part. This notification shall include: ■ §60.48c(a)(1) - The design heat input capacity of the affected facility and identification of fuels to be combusted in the affected facility. o §60.48c(g)(1) - Except as provided under paragraphs (g)(2) and (g)(3) of this section, the owner or operator of each affected facility shall record and maintain records of the amount of each fuel combusted during each operating day. §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 may elect to record and maintain records of the amount of each fuel combusted during each calendar month. o §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. 41. Points 013, 014, 015: This equipment is subject to the control requirements for stationary and portable engines in the 8 -hour ozone control area under Regulation No. 7, Section XVI.B.2. For lean burn reciprocating internal combustion engines, an oxidation catalyst shall be required. 42. Point 017: This source is subject to Monitoring Provisions of the New Source Performance Standards requirements of Regulation Number 6, Part A, Subpart Kb, Standards of Performance for Volatile Organic Liquid Storage Vessels for which construction, reconstruction or modification commenced after July 23, 1984, as follows (Regulation Number 6, Subparts A and Kb): • 40 CFR, Part 60, Subpart A - General Provisions o §60.116b - Monitoring of operations • §60.116b(c) Except as provided in paragraphs (f) and (g) of this section, the owner or operator of each storage vessel either with a design capacity greater than or equal to 151 m3 storing a liquid with a maximum true vapor pressure greater than or equal to 3.5 kPa or with a design capacity greater than or equal (COLORADO 31 Air Pollution Control Division Deaar r era cf 944itat Health e Enworfnent Page 15 of 34 to 75 m3 but less than 151 m3 storing a liquid with a maximum true vapor pressure greater than or equal to 15.0 kPa shall maintain a record of the VOL stored, the period of storage, and the maximum true vapor pressure of that VOL during the respective storage period. 43. Points 018, 019, 20: All hydrocarbon liquid loading operations, regardless of size, shall be designed, operated and maintained so as to minimize leakage of volatile organic compounds to the atmosphere to the maximum extent practicable. 44. Points 018, 019, 20: The owner or operator shall follow loading procedures that minimize the leakage of VOCs to the atmosphere including, but not limited to (Regulation Number 3, Part B, III.E.): a) Hoses, couplings, and valves shall be maintained to prevent dripping, leaking, or other liquid or vapor loss during loading and unloading. b) All compartment hatches at the facility (including thief hatches) shall be closed and latched at all times when loading operations are not active, except for periods of maintenance, gauging, or safety of personnel and equipment. c) The owner or operator shall inspect onsite loading equipment during loading operations to monitor compliance with above conditions. The inspections shall occur at least monthly. Each inspection shall be documented in a log available to the Division on request. 45. Points 018, 019, 20: The owner or operator shall: a. Install and operate the vapor collection and return equipment to collect vapors during loading of tank compartments of outbound transport trucks. b. Include devices to prevent the release of vapor from vapor recovery hoses not in use. c. Use operating procedures to ensure that hydrocarbon liquid cannot be transferred unless the vapor collection equipment is in use. d. Operate all recovery and disposal equipment at a back -pressure less than the pressure relief valve setting of transport vehicles. 46. Point 022: This source is subject to the New Source Performance Standards requirements of Regulation Number 6, Part A, Subpart Kb, Standards of Performance for Volatile Organic Liquid Storage Vessels for which construction, reconstruction or modification commenced after July 23, 1984, including, but not limited to, the following (Regulation Number 6, Subparts A and Kb): •' 40 CFR, Part 60, Subpart A - General Provisions • §60.112b - Standard for volatile organic compounds (VOC) O §60.112b(a) The owner or operator of each storage vessel with a....design capacity greater than or equal to 151 m3 containing a VOL that, as stored, has a maximum true vapor pressure equal to or greater than 5.2 kPa but less than 76.6 kPa, shall equip each storage vessel with one of the following: ■ §60.112b(a)(3) A closed vent system and control device meeting the following specifications: • §60.112b(a)(3)(i) The closed vent system shall be designed to collect all VOC vapors and gases discharged from the storage vessel and operated with no detectable emissions as indicated by an instrument reading of less than 500 ppm above background and visual inspections, as determined in part 60, subpart VV, §60.485(b). • §60.112b(a)(3)(ii) The control device shall be designed and operated to reduce inlet VOC emissions by 95 percent or greater. If a flare is used as COLORADO Air Pollution Control Division c Health U f..'RSrc,^eff enc Page 16 of 34 the control device, it shall meet the specifications described in the general control device requirements (§60.18) of the General Provisions. o §60.113b - Testing and procedures The owner or operator of each storage vessel as specified in §60.112b(a) shall meet the requirements of paragraph (a), (b), or (c) of this section. The applicable paragraph for a particular storage vessel depends on the control equipment installed to meet the requirements of $60.112b. ■ §60.113b(c) The owner or operator of each source that is equipped with a closed vent system and control device as required in §60.112b (a)(3) or (b)(2) (other than a flare) is exempt from §60.8 of the General Provisions and shall meet the following requirements. • §60.113b(c)(1) Submit for approval by the Administrator as an attachment to the notification required by §60.7(a)(1) or, if the facility is exempt from §60.7(a)(1), as an attachment to the notification required by §60.7(a)(2), an operating plan containing the information listed [in §60.113b(c)(1)(i) and §60.113b(c)(1)(ii)]. • §60.113b(c)(2) Operate the closedvent system and control device and monitor the parameters of the closed vent system and control device in accordance with the operating plan submitted to the Administrator in accordance with paragraph (c)(1) of this section, unless the plan was : modified by the Administrator during the review process. In this case, the modified plan applies. o §60.115b - Reporting and recordkeeping requirements ■ §60.115b(c) After installing control equipment in accordance with §60.112b (a)(3) or (b)(1) (closed vent system and control device other than a flare), the owner or operator shall keep the following records. ■ §60.115b(c)(1) A copy of the operating plan. • §60.115b(c)(2) A record of the measured values of the parameters monitored in accordance with §60.113b(c)(2). o §60.116b - Monitoring of operations ■ §60.116b(a) The owner or operator shall keep copies of all records required by this section, except for the record required by paragraph (b) of this section, for at least 2 years. The record required by paragraph (b) of this section will be kept for the life of the source. ............. • §60.11'6b(b) The owner or operator of each storage vessel as specified in §60.110b(a) shall keep readily accessible records showing the dimension of the storage vessel and an analysis showing the capacity of the storage vessel. §60.11'6b(g) The owner or operator of each vessel equipped with a closed vent system and control device meeting the specification of §60.112b or with emissions reductions equipment as specified in 40 CFR 65.42(b)(4), (b)(5), (b)(6), or (c) is exempt from the requirements of paragraphs (c) and (d) of this section 47. Point 026: No owner or operator of a smokeless flare or other flare for the combustion of waste gases shall allow or cause emissions into the atmosphere of any air pollutant which is in excess of 30% opacity for a period or periods aggregating more than six minutes in any sixty consecutive minutes. (Regulation Number 1, Section II.A.5.) OPERATING Et MAINTENANCE REQUIREMENTS 48. Points 001, 002, 003, 004, 005, 006, 007, 019, 020, 021, 022: Upon startup of these points, the owner or operator shall follow the most recent operating and maintenance (O&M) plan and COLORADO Air Pollution Control Division 1 De -Delmont c: i'+f art:c Hof ih b E +.aronment Page 17 of 34 record keeping format approved by the Division, in order to demonstrate compliance on an ongoing basis with the requirements of this permit. Revisions to the O&M plan are subject to Division approval prior to implementation. (Regulation Number 3, Part B, Section III.G.7.) 49. Point 001, 002, 003: The combustion chamber temperature of the thermal oxidizer used to control emissions from the amine unit still vent 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 daily average minimum operating temperature shall be achieved at all times that any amine unit emissions are routed to the thermal oxidizer in order to meet the emission limits in this permit. 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. COMPLIANCE TESTING AND SAMPLING Initial Testing Requirements 50. Point 001: The owner or operator shall complete the initial extended gas analysis of amine unit still vent waste gas (i.e. Point 001, Process 01) required by this permit and submit the results to the Division as part of the self -certification process to ensure compliance with the emission limits. (Reference: Regulation No. 3, Part B, Section III.E.) . 51. Point 001: The owner/operator shall complete an initial site specific extended gas analysis ("Analysis") within one hundred and eighty days (180) after commencement of operation or issuance of this permit, whichever comes later, of the residue gas combusted as assist gas for the thermal oxidizer (i.e. Point 001, Process 02) in order to verify the VOC content (weight fraction) of this emission stream. Results of the Analysis shall be used to calculate site -specific emission factors for VOC (in units of lb/MMSCF gas vented) using Division approved methods. Results of the Analysis shall be submitted to the Division as part of the self -certification and must demonstrate the emissions factors established through the Analysis are less than or equal to, the emissions factors submitted with the permit application and established herein in the "Notes to Permit Holder" for this emissions point. If any site specific emissions factor d eveloped through this Analysis is greater than the emissions factors submitted with the permit application and established in the "Notes to Permit Holder" the operator shall submit to the Division within 60 days, or in a timeframe as agreed to by the Division, a request for permit modification to address this/these inaccuracy(ies). 52. Point 001, 002, 003: 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 in this permit. The emission rate(s) shall demonstrate compliance with the sum of emission limits from Point 001 - process 01 and process 02, Point 002 - process 1, and Point 003 - process 01. The operator shall also demonstrate that the thermal oxidizer (TO) achieves a minimum destruction efficiency of 98.0% for VOC. The operator shall measure and record, using EPA approved methods, VOC mass emission rates at the thermal oxidizer inlet and outlet to determine the destruction and removal efficiency of the thermal oxidizer. The mass emission rate at the thermal oxidizer inlet shall be measured and recorded by summing the mass emission rates from Point 001 - process 01 and process 02, Point 002 - process 1, and Point 003 - process 01, derived from the individually metered throughputs of each point. (Each process shall be operating during the initial compliance test?) The natural gas throughput, assist gas throughput, lean amine recirculation rate, MDEA concentration in lean amine stream, sulfur content of the sour gas entering the amine unit, and thermal oxidizer combustion chamber 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 COLORADO Air Pollution Control Division Deozrmena of Pabbb Meaux b or i ent Page 18 of 34 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 Number 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. 53. Point 002: The owner or operator shall complete the initial extended gas analysis of amine unit still vent waste gas (i.e. Point 002, Process 01) required by this permit and submit the results to the Division as part of the self -certification process to ensure compliance with the emission limits. (Reference: Regulation No. 3, Part B, Section III.E.) . 54. Point 003: The owner or operator shall complete the initial extended gas analysis of amine unit still vent waste gas (i.e. Point 003, Process 01) required by this permit and submit the results to the Division as part of the self -certification process to ensure compliance with the emission limits. (Reference: Regulation No. 3, Part B, Section TILE.) . 55. Point 004, 005: The owner or operator shall complete the initial extended wet gas analysis within one hundred and eighty days (180) of the tatter of commencement of operation or issuance of this permit. The owner or operator shall use this analysis to calculate actual emissions, as prescribed in the Emission Limitation and Records section of this permit, to verify initial compliance with the emission limits. The owner or operator shall submit the analysis and the emission calculation results to the Division as part of the self -certification process. (Reference: Regulation Number 3, Part B, Section III.E.) 56. Point 008, 009, 010, 011, 012: 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 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 (Regulation Number 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods. Carbon Monoxide using EPA approved methods. 57. Point 014: The owner/operator shall complete an initial extended gas analysis ("Analysis") within one hundred and eighty days (180) after commencement of operation or issuance of this permit, whichever comes later, of the inlet gas vented during pigging depressurization in order to verify the VOC content (weight fraction) of this emission stream. Results of the Analysis shall be used to calculate emission factors for VOC (in units of lb/event), using methods provided in the "notes to permit holder". Results of the Analysis shall be submitted to the Division as part of the self - certification and must demonstrate the emissions factors established through the Analysis are less than or equal to, the emissions factors submitted with the permit application and established herein in the "Notes to Permit Holder" for this emissions point. If any site specific emissions factor developed through this Analysis is greater than the emissions factors submitted with the permit application and established in the "Notes to Permit Holder" the operator shall submit to the Division within 60 days, or in a timeframe as agreed to by the Division, a request for permit modification to address this/these inaccuracy(ies). 58. Point 014: Within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit, the operator shall confirm that pigging volumes at the source for all different pigging receivers, as built, do not exceed the per event pigging receiver volumes as COLORADO Air Pollution Control Division osov feat 6f Fjh.' C Health f, Env:Torment Page 19 of 34 stated in this permit. The operator shall submit the results to the Division as part of the self - certification process to ensure compliance with emissions limits. 59. Point 015: Within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit, the owner or operator shall complete the initial extended gas analysis of gas samples that are representative of volatile organic compound (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas analysis shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. The operator shall submit the results of the gas analysis and emission calculations to the Division as part of the self -certification process to ensure compliance with emissions limits. 60. Point 015: Within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit, the operator shall complete a hard count of components at the source and establish the number of components that are operated in "heavy liquid service", "light liquid service", "water/oil service" and "gas service". The operator shall submit the results to the Division as part of the self -certification process to ensure compliance with emissions limits. 61. Point 021: The owner or operator must complete site specific sampling including a compositional analysis of the pre -flash pressurized condensate routed to these storage tanks and, if necessary for emission factor development, a sales oil analysis to determine RVP and API gravity. Testing must be in accordance with the guidance contained in PS Memo 05-01. Results of testing must be used to determine site -specific emissions factors for VOC and Hazardous Air Pollutants using Division approved methods. Results of site -specific sampling and analysis must be submitted to the Division as part of the self -certification and used to demonstrate compliance with the emissions factors chosen for this emissions point. Periodic Testing Requirements 62. Point 001: At a minimum frequency of once per calendar month, the owner or operator shall sample and complete an extended gas analysis of this amine unit's still vent waste gas routed to the thermal oxidizer. This sample shall ! be analyzed for total VOC, Benzene, Toluene, Ethylbenzene, Xylene, n -Hexane, 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, H2S, and SO2 emissions specified in this permit. If an amine unit is not operated during a calendar month, monthly sampling is not required..... 63. Point 002: At a minimum frequency of twice per 12 -month period, where there must be at least 5 months between sampling events for two of the samples, the owner or operator shall sample and complete an extended gas analysis of this amine unit's still vent waste gas routed to the thermal oxidizer. This sample shall be analyzed for total VOC, Benzene, Toluene, Ethylbenzene, Xylene, n -Hexane, 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, H2S, and SO2 emissions specified in this permit. If an amine unit is not operated during a calendar month, monthly sampling is not required. 64. Point 003: The owner or operator shall sample and complete an extended gas analysis of this amine unit's still vent waste gas routed to the thermal oxidizer on an annual basis. This sample shall be analyzed for total VOC, Benzene, Toluene, Ethylbenzene, Xylene, n -Hexane, 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, H2S, and SO2 emissions specified in this permit. If an amine unit is not operated during a calendar month, monthly sampling is not required. 65. Point 004, 005: The owner or operator shall complete an extended wet gas analysis prior to the inlet of the dehydration unit an an annual basis. Sampling of the inlet to one dehydration unit can be used to represent the gas to the other unit. Results of the wet gas analysis shall be used (COLORADO Air Pollution Control Division onrnent Page 20 of 34 to calculate emissions of criteria pollutants and hazardous air pollutants per this permit and be provided to the Division upon request. 66. Point 014: On an annual basis, the owner or operator shall complete an extended gas analysis of gas samples that are representative of volatile organic compounds (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas analysis shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. ADDITIONAL REQUIREMENTS 67. A revised Air Pollutant Emission Notice (APEN) shalt be filed: (Regulation Number 3, Part A, Section II.C.) • Annually by April 30th whenever a significant increase in emissions occurs as follows: 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'', (NOr) 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. Within 14 calendar days of commencing operation of a permanent replacement engine under the alternative operating scenario outlined in this permit as Attachment A. The APEN shall include the specific manufacturer, model and serial number and horsepower of the permanent replacement engine, the appropriate APEN filing fee and a cover letter explaining that the owner or operator is exercising an alternative -operating scenario and is installing a permanent replacement engine. 68. The requirements of Colorado Regulation Number 3, Part D shall apply at such time that any stationary source or modification becomes a major stationary source or major modification solely by virtue of a relaxation in any enforceable limitation that was established after August 7, 1980, on the capacity of the source or modification to otherwise emit a pollutant such as a restriction on hours of operation (Regulation Number 3, Part D, Section V.A.7.B). GENERAL TERMS AND CONDITIONS COLORADO Air Pollution Control Division Department Of F'bh Hee3ih a cm7orme??C Page 21 of 34 69. 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 Number 3, Part B, Section II.B. upon a request for transfer of ownership and the submittal of a revised APEN and the required fee. 70. 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 Number 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. 71. This permit is issued in reliance upon the accuracy and completeness of information supplied by the owner or operator 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 owner or operator or owner or operators agents. It is valid only for the equipment and operations or activity specifically identified on the permit. 72. 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. 73. 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 owner or operator, or the Division revokes a permit, the owner or operator of a source may request a hearing before the AQCC for review of the Division's action. 74. 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. 75. Violation of the terms of a permit or of the provisions of the Colorado Air Pollution Prevention and Control Act or 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 Permit History COLORADO Mr Pollution Control Division Ueda -serer . of P b1,t Health e En+.trorenens Page 22 of 34 Issuance Date Description Issuance 1 This Issuance Issued to Cureton Front Range, LLC COLORADO Air Pollution Control Division Deoarftnent Of Ffubbc f.leafth U Envftoment Page 23 of 34 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. (Regulation Number 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 owner or operator 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 complete 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 owner or operator 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: https://www.colorado.gov/pacific/cdphe/aqcc-regs 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. Facility Equipment ID AIRS Point Pollutant CAS # Uncontrolled Emissions (lb/yr) Controlled Emissions (lb/yr) Amine1 001 Benzene 71432 102445 1978 Toluene 108883 50915 993 Ethylbenzene 100414 6581 129 Xylenes 1330207 14779 292 n -Hexane 110543 4473 14 Hydrogen Sulfide 7783064 6377 127 Amine2 Benzene 71432 46469 864 002 Toluene 108883 11625 218 Ethylbenzene 100414 77 1 Xylenes 1330207 445 8 n -Hexane 110543 6404 11 2,2,4- Trimethylpentane 540841 35 0 Amine3 003 Benzene 71432 15496 299 Toluene 108883 8128 159 Ethylbenzene 100414 1061 21 Xylenes 1330207 2348 46 n -Hexane 110543 726 3 COLORADO Air Pollution Control Division beurtenent O! Ha411c Hewth EP E:rt^vnn:; t;t Page 24 of 34 Hydrogen Sulfide 7783064 638 13 TEG1 Et TEG2 004- 005 Benzene 71432 6218 311 Toluene 108883 327 16 Ethylbenzene 100414 7 0 Xylenes 1330207 4 0 n+lexane 110543 3245 162 2,2,4- Trimethylpentane 540841 5 0 TK1 006 Benzene 71432 54 18 Toluene 108883 152 8 Ethylbenzene 100414 20 1 ){ylenes 1330207 28 1 2,2,4- Trimethylpentane 540841 2 0 TK2 - TK6 007 Benzene 71432 1661 83 n -Hexane 110543 5220 261 HTR2 008 Formaldehyde 50000 11 11 Benzene 71432 0 0 Toluene 108883 1 1 n+lexane 110543 271 271 HTR3 HTR4 010 Formaldehyde 50000 7 7 Benzene 71432 0 0 Toluene 108883 0 0 n+Iexane 110543 170 170 Formaldehyde 50000 11 11 Benzene 71432 0 0 Toluene 108883 0 0 n -Hexane 110543 255 255 HTR5 011 Formaldehyde 50000 35 35 Benzene 71432 1 1 Toluene 108883 2 2 n -Hexane 110543 850 850 HTR6 012 Formaldehyde 50000 12 12 Benzene 71432 0 0 Toluene 108883 1 1 COLORADO Air Pollution Control Division De-da rtmen; of vubbicHealth -Fr Em ronment Page 25 of 34 n -Hexane 110543 278 278 Pigging 014 Benzene 71432 0 0 Toluene 108883 2 2 Ethylbenzene 100414 0 0 Xylenes 1330207 1 1 n -Hexane 110543 39 39 2,2,4- Trimethylpentane 540841 3 3 FUG1 015 Benzene 71432 2206 398 Toluene 108883 2238 406 Ethylbenzene 100414 2208 398 Xylenes 1330207 2211 399 n -hexane 110543 2858 562 TK7 017 Methanol 67561 997 997 L0AD4 018 Benzene 71432 6 6 Toluene 108883 3 3 Xylenes 1330207 1 1 n -hexane 110543 56 56 L0AD3 019 Benzene 71432 299 15 n -Hexane 110543 2628 131 L0AD2 020 Benzene 71432 32 2 n -Hexane 110543 284 14 TK8 - TK9 021 Benzene 71432 1892 95 n -Hexane 110543 16556 828 TK10 - TK11 022 Benzene 71432 2920 146 Toluene 108883 1241 62 Ethylbenzene 100414 84 4 Xylene 1330207 120 6 Notes: 1. Emission rates for Point 004, 005 represent emissions from each emission point individually. 2. All non -criteria reportable pollutants in the table above with uncontrolled emission rates above 250 pounds per year (lb/yr) are reportable and may result in annual emission fees based on the most recent Air Pollution Emission Notice. 5) The emission levels contained in this permit are based on the following emission factors: Point 001: COLORADO Air Pollution Control Division Demrtmer; of P bli: Nexth a Ens Ionment Page 26 of 34 Process 01: Emissions from the amine unit result from venting of acid gas (still vent overhead). Additionally, emissions result from the combustion of thermal oxidizer (TO) assist gas. Actual VOC, HAP and H2S emissions from the venting of still vent acid gas shall be calculated based on the most recent monthly still vent waste gas sampling and the most recent monthly measured still vent waste gas flow volume as required by the permit. The following equation shall be used to in conjunction with the sample and flow volume data to calculate actual emissions: Weight %x Sample MW, lb lb — mole 1.0x106 scf Metered Still Vent Volume, MMscf Emission Ratex = 100 x lb — mole x 379 scf x 1 MMscf x Controlled emissions are as follows: Month Point Source Control Efficiency Stilt vent controlled by thermal oxidizer 98% Flash tank recycled to plant inlet or routed to plant fuel system 100% SO2 emissions resulting from the combustion of H2S emissions in the still vent waste gas stream are based on a mass balance. The mass balance utilizes molecular weights of 64.07 lb 5O2/lb-mol and 34.08 lb H2S/lb-mol. The calculation assumes 100% of H2S in the still vent waste gas stream is converted to SO2 when combusted by the thermal oxidizer. The following equation shall be used to calculate actual SO2 emissions: ( lb ll _ H2S Still Vent Emission Rate, lb 64.07 lb SO2 lb — mol SO2 Emission Rate month month month x lb — mol x 34.08 lb H25 Emissions associated with the combustion of still vent waste gas by the thermal oxidizer are calculated using the following emission factors: CAS # Pollutant Uncontrolled Emission Factors (lb/MMSCF waste gas combusted) Controlled Emission Factors (lb/MMSCF waste gas combusted) Source NOx 1.3195 1.3195 Manufacturer CO 1.1040 1.1040 Manufacturer Note: Emission factors in the table above are based on a still vent waste gas heat content of 13.46 Btu/scf. Actual emissions are calculated by multiplying the emission factors in the table above by the total metered amine unit still vent waste gas routed to the thermal oxidizer. Process 02: Combustion of assist gas and pilot gas at thermal oxidizer: CAS # Pollutant Uncontrolled Emission Factors (lb/MMSCF assist and pilot gas combusted) Controlled Emission Factors (Ib/MMSCF assist and pilot gas combusted) Source NOx 100.94 100.94 AP 42 Chapter 1.4 Table 1.4-1 CO 84.46 84.46 AP -42 Chapter 1.4 Table 1.4-1 VOC 3.96 3.96 Mass Balance ICOLORADO Air Pollution Control Division De,arvner.: 01 Ehasrnnert Page 27 of 34 Note: NOx and CO emission factors in the table above are based on a residue gas heat content of 1,030 Btu/scf. Actual emissions are calculated by multiplying the emission factors in the table above by the assist gas volume for the thermal oxidizer (as measured by flow meter). The VOC emission factors in the table above were calculated based on the residue gas composition in the ProMax simulation (0.45% VOC by weight, molecular weight of16.68 lb/lbmol), standard molar volume of 379 scf/lbmol and VOC destruction efficiency of 98% for the thermal oxidizer. Point 002: Process 01: Emissions from the amine unit result from venting of acid gas (still vent overhead). Actual VOC and HAP emissions from the venting of still vent acid gas shall be calculated based on the most recent monthly still vent waste gas sampling and the most recent monthly measured still vent waste gas flow volume as required by the permit. The following equation shall be used to in conjunction with, the sample and flow volume data to calculate actual emissions: Weight %x Sample MW, lb lb — mole 1.0x106 scf Metered Still Vent Volume, MMscf Emission Rates — 100 x lb — mole x 379 scf x x 1 MMscf Controlled emissions are as follows: Point Source Month Control Efficiency Still vent controlled by thermal oxidizer 98% Flash tank recycled to plant inlet or routed to plant fuel system Emissions associated with the combustion of still vent waste gas alone, are below reportable thresholds, and all supplemental fuel to the thermal oxidizer are calculated under amine1 (Point 001). The operator has indicated that the gas processed by this amine unit does not contain H25. Point 003: Process 01: Emissions from the amine unit result from venting of acid gas (still vent overhead). Actual VOC, HAP and H25 emissions from the venting of still vent acid gas shall be calculated based on the most recent monthly still vent waste gas sampling and the most recent monthly measured still vent waste gas flow volume as required by the permit. The following equation shall be used to in conjunction with the sample and flow volume data to calculate actual emissions: Weight %x. Sample MW, lb lb — mole 1.0x106 scf Metered Still Vent Volume, MMscf Emission Rates = x x x x 100 lb — mole 379 scf 1 MMscf Month Controlled emissions are as follows: Point Source Control Efficiency Still vent controlled by thermal oxidizer 98% Flash tank recycled to plant inlet or routed to plant fuel system 100% SO2 emissions resulting from the combustion of H25 emissions in the still vent waste gas stream are based on a mass balance. The mass balance utilizes molecular weights of 64.07 lb S02/lb-mol and 34.08 lb HZS/lb-mol. The calculation assumes 100% of H25 in the still vent waste gas stream is COLORADO Air Pollution Control Division Dt.,-Dattnientai vub c Hemll Er E. -a momaent Page 28 of 34 converted to 502 when combusted by the thermal oxidizer. The following equation shall be used to calculate actual 502 emissions: lb l _ H2S Still Vent Emission Rate, lb 64.07 lb SO2 lb — mol SO2 Emission Rate (month) month x lb — mol x 34.08 lb H2S Emissions associated with the combustion of still vent waste gas alone, are below reportable thresholds, and all supplemental fuel to the thermal oxidizer are calculated under amine1 (Point 001) Point 004, 005: The emission levels contained in this permit are based on information provided in the application and the GRI GlyCalc 4.0 model. Controlled emissions are based on an enclosed flare control efficiency of 95.0%. Total actual still vent combustion emissions are based on the sum of the emissions for the still vent primary control. Total combustion emissions are based on the following emission factors: Still Vent Primary Control: Combustion emission factors for this point are below reportable thresholds Flash Tank Primary Control: Flash tank emissions are considered 100% controlled, as they are routed directly to a closed - loop system. Point 006: CAS # Pollutant Uncontrolled Emission Factors lb/bbl Controlled Emission Factors lb/bbl Source VOC 2.47 0.12 EPA TANKS 71432 Benzene 0.039 0.002 EPA TANKS Note: The controlled emissions factors for this point are based on a control efficiency of 95%. Point 007: CAS # Pollutant Uncontrolled Emission Factors lb/bbl Controlled Emission Factors lb/bbl Source CO 0.0167 0.0167 AP -42 Ch. 13.5 VOC 0.262 1.31E-02 Produced Water State EF 71432 Benzene 0.007 3.50E-04 Produced Water State EF 110543 n -Hexane 0.022 1.10E-03 Produced Water State EF Note: The controlled emissions factors for this point are based on a control efficiency of 95%. Point 008 - 012: CAS # Pollutant Uncontrolled Emission Factors lb/MMscf Source PM10 7.67 AP -42 Chapter 1.4 Table 1.4- 2 PM2.5 7.67 N0x 50.49 CO 41.20 Manufacturer COLORADO Air Pollution Control Division DCD3ttment Of FJb! c HeLtth & En VITUr lertt Page 29 of 34 CAS # Pollutant Uncontrolled Emission Factors lb/MMscf Source VOC 5.55 AP -42 Chapter 1.4 Table 1.4- 1 110543 n -hexane 1.82 Note: The emissions factors for this point are based on a fuel higher heating value of 1,030 Btu/scf. Emission factors from AP -42 are originally developed based on a fuel heating value of 1,020 Btu/scf and have been scaled to the stated fuel heating value. Point 014: Process 01 (6" receiver) CAS # Pollutant Uncontrolled Emission Factors lb/event Controlled Emission Factors lb/event Source VOC 0.7341 0.7341 Engineering calculation Note: Emissions are based on volumetric flow of 49.89 scf/event, vapor molecular weight of 22.3 lb/lbmol and composition of 25.03% by weight VOC. Process 02 (8" receiver) CAS # Pollutant Uncontrolled Emission Factors lb/event ___ Controlled Emission Factors lb/event Source VOC 1.4120 1.4120 Engineering calculation Note: Emissions are based on volumetric flow of 95.98 scf/event, vapor molecular weight of 22.3 lb/lbmol and composition of 25.03% by weight VOC. Process 03 (10" receiver) CAS # Pollutant Uncontrolled Emission Factors lb/event Controlled Emission Factors lb/event Source VOC 2.3387 2.3387 Engineering calculation Note: Emissions are based on volumetric flow of 158.96 scf/event, vapor molecular weight of 22.3 lb/lbmol and composition of 25.03% by weight VOC. Process 04 (16" receiver) CAS # Pollutant Uncontrolled Emission Factors lb/event Controlled Emission Factors lb/event Source VOC 6.6110 6.6110 Engineering calculation Note: Emissions are based on volumetric flow of 449.35 scf/event, vapor molecular weight of 22.3 lb/lbmol and composition of 25.03% by weight VOC. Point 015: Component Gas Service Heavy Oil Light Oil Water/Oil Service Connectors 4,799 2,136 2,776 0 Flanges 2,337 1,086 1,526 0 Open-ended Lines 7 0 9 0 Pump Seals 0 46 49 0 1COLORADO Air Pollution Control Division Dearment of N:bhc Hea.ch a E^alrorrttent Page 30 of 34 Valves 2,327 1,099 1,535 0 Other* 213 51 56 0 VOC Content (wt. fraction) 0.2630 1 1 1 Benzene Content (wt. fraction) 1.60E-5 2.00E-2 2.00E-2 2.00E-2 Toluene Content (wt. fraction) 1.30E-4 2.00E-2 2.00E-2 2.00E-2 Ethylbenzene (wt. fraction) 2.10E-5 2.00E-2 2.00E-2 2.00E-2 Xylenes Content (wt. fraction) 3.20E-5 2.00E-2 2.00E-2 2.00E-2 n Hexane Content (wt. fraction) 2,39E-3 2.00E-2 2.00E-2 2.00E-2 2, 2,4-Trimethylpentane Content (wt. fraction) --- --- --- --- *Other equipment type includes compressors, pressure relief valves, relief valves, diaphragms, drains, dump arms, hatches, instrument meters, polish rods and vents TOC Emission Factors (kg/hr-component): Component Gas Service Heavy Oil Light Oil Water/Oil Service Connectors 2.0E-04 7.5E-06 2.1E-04 1.1E-04 Flanges 3.9E-04 3.9E-07 1'.1 E-04 2.9E-06 Open-ended Lines 2.0E-03 1.4E-04 1.4E-03 2.5E-04 Pump Seals 2.4E-03 NA 1.3E-02 2.4E-05 Valves 4.5E-03 8.4E-06 2.5E-03 9.8E-05 Other 8.8E-03 3.2E-05 7.5E-03 1.4E-02 Source: EPA -453/R95-017 Table 2-4 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 gas and liquids analyses. Point 017: CAS # Pollutant Emission Factors Uncontrolled Source lb/bbl 67561 Methanol 0.112 EPA TANKS Note: Emissions are uncontrolled COLORADO Air Pollution Control Division Deort Ti&K?i Qt k bbc Wealth y Dwgonment Page 31 of 34 Point 018: Emissions associated with the pressurized loadout of NGL result from gases that are released from hoses during disconnect. Emission factors in the table below are based on vapor and liquid line volumes and specific gravity of the liquid unloaded. Pollutant Emission (lb/loadout event) Factors - Uncontrolled Source V0C 2.170 Engineering Calculation Emission factors are based on depressurized liquid and vapor line volumes of 0.0736 ft /hose and 0.0436 ft3/hose respectively, vapor molecular weight of 12.1 lb/lbmol, and liquid density of 29.35 lb/ ft3. NGL liquid and vapor properties are based on facility ProMax simulation. Point 019, 020: Pollutant CAS # Uncontrolled Emission Factors lb/bbl Controlled Emission Factors lb/bbl Source VOC 2.36E-01 1.18E-02 Condensate State Emission Factor Benzene 71432 4.10E-04 2.05E-05 n -Hexane 110543 3.60E-03 1.80E-04 Controlled emission factors are based on a flare efficiency of 95% and a collection efficiency of 100%. Point 021: CAS # Pollutant Uncontrolled Emission Factors lbibbl Controlled Emission Factors lb/bbl Source CO --- 0.1706 AP -42 Chapter 13.5 VOC 13.70 0.69 Condensate State E.F. (includes flash) -Front Range 71432 Benzene 0.024 0.001 110543 n -Hexane 0.210 0.011 Note: The controlled emissions factors for this point are based on a control efficiency of 95%. Point 022: Tank waste gas: CAS # Pollutant Uncontrolled Emission Factors lb/bbl Controlled Emission Factors lb/bbl Source V0C 0.259 1.30E-02 EPA Tanks 71432 Benzene 0.0040 2.00E-04 108883 =Toluene 0.0017 8.50E-05 100414 Ethylbenzene 0.0001 5.75E-06 1330207 Xylenes 0.0002 8.22E-06 Note: The controlled emissions factors for this point are based on the enclosed combustion device control efficiency of 95%. The site specific V0C and HAP emission factors in the table above were developed a stable oil (stabilized condensate) compositions from ProMax and EPA Tanks 4.09d for working and breathing emissions. 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 COLORADO Air Pollution Control Division Deaartment hi Pubbc Heath & &wtrorme :t Page 32 of 34 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 regarding a specific expiration date call the Division at (303)-692- 3150. 7) Point 001, 002, 003 : This source 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 (See June 3, 2016 Federal Register posting - effective August 02, 2016). This rule has not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 6. A copy of the complete subpart is available on the EPA website at: https://www.gpo.gov/fdsys/pkg/FR-2016-06-03/pdf/2016-11971.pdf This unit is subject to requirements 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 §60.5423a(c) but are not required to comply with §§60.5405a through 60.5407a and §§60.5410a(g) and 60.5415a(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. 8) Point 015, : This source is subject to 40 CFR, Part 60, Subpart0000a-Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification or Reconstruction Commenced After September 18, 2015 (See June 3, 2016 Federal Register posting - effective August 02, 2016). This rule has not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 6. A copy of the complete subpart is available on the EPA website at: https://www.gpo.gov/fdsys/pkg/FR-2016-06-03/pdf/2016-11971.pdf 9) This permit fulfills the requirement to hold a valid permit reflecting the storage tank and associated control device per the Colorado Oil and Gas Conservation Commission rule 805b(2)(A) when applicable. 10) This facility is classified as follows: Applicable Requirement Status Operating Permit Synthetic Minor Source of: V0C, benzene, toluene, n -hexane and total HAPs PSD/NANSR ` Synthetic Minor Source of: V0C MACT HH Major Source Requirements: Not Applicable Area Source Requirements: Applicable (Points 004 Et 005) MACT DDDDD Not applicable NSPS Dc Applicable to point 008 - 012 NSPS Db Not applicable NSPS Kb Applicable to point 017, 022 ICOLORADO Air Pollution Control Division Deoa!tment Of Puh;tc Meath V E'ivm.7nMent Page 33 of 34 NSPS KKK Not applicable NSPS LLL Not applicable NSPS OOOO Not applicable NSPS 0000a Applicable to point 001 - 003, 015 11) Full text of the Title 40, Protection 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 I 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 611440-63.6175 Subpart QQQ- Subpart YYYY MACT 63.6580-63.8830 Subpart ZZZZ - Subpart MMMMM MACT 63.8980 -End Subpart NNNNN - Subpart XXXXXX COLORADO Air Pollution Control Division (ht."✓3f;Mort Of Public ilealih E'4tvcnment Page 34 of 34 JA4 2 • Dr -I) Amine Sweetening Unit - Form APCD-206 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 amine sweetening units only. If your emission unit does not fall into this category, there may be a more specific APEN available for your source (e.g. glycol dehydration unit, hydrocarbon liquid loading, condensate storage tanks, 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.00v/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: fq 1k) Eo Rl AIRS ID Number: (13 1A02.01 gyp' [Leave blank unless APCD has already assigned a permit # and AIRS ID) Section 1 - Administrative Information Company Name': Cureton Front Range LLC Site Name: Hookside Gas Plant Site Location: SE Sec. 30, T9N, R60W Mailing Address: (Include Zip Code) 518 17th Street, Suite 650 Site Location County: Weld NAICS or SIC Code: 1321 Denver, CO 80202 Contact Person: Phone Number: Nick Holland 303-324-5967 E -Mail Address2: nick.holland@curetonmidstream.com I 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 392372 COLOR A DO 1 I ,V;h, mnwnc b EnrkGni.'wai 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 -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment O Change company name3 O Add point to existing permit o Change permit limit O Transfer of ownership4 O Other (describe below) OR - ▪ APEN submittal for update only (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) Additional Info Et Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Amine sweetening unit to remove CO2 and trace amounts of H2S. All TO combustion emissions included on this APEN. Company equipment Identification No. (optional): Aminel For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TBD 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: Will this equipment be operated in any NAAQS nonattainment area? hours/day Does this facility have a design capacity less than 2 long tons/day of H2S in the acid gas? Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 ❑� days/week Yes Yes ❑✓ weeks/year No No ;COLORADO �; b . t c 2 I iYxph&FnYOlstelr.t Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Amine Unit Equipment Information Manufacturer: TBD Model No.: TBD Serial Number: TBD Absorber Column Stages: 7 stages Amine Type: O MEA Pump Make and Model: TBD O DEA O TEA MDEA O DGA # of pumps: 2 Sour Gas Throughput: Design Capacity: 200 MMSCF/day Requested5: 73,000 MMSCF/year Actual: MMSCF/year Sour Gas: Pressure: 1000 psig Temperature: 59.9 °F Lean Amine Stream: Pressure: 14 psia Flowrate: ;0(J gal/min Mole loading H2S: 2.6E-5% Temperature: Wt. % amine: Mole Loading CO2: 252.6 °F 50.2 0.11% NGL Input: Pressure: Flowrate: psia Gal/min Temperature: °F Flash Tank: O No Flash Tank Pressure: 65 psia Temperature: 100 °F Additional Required Information: ❑✓ Attach a Process Flow Diagram ✓❑ Attach the simulation model inputs Et emissions report O Attach composition reports for the rich amine feed, sour gas feed, NGL feed, a outlet stream (emissions) 0 Attach the extended gas analysis (including BTEX Et n -Hexane, H25, CO2, temperature, and pressure) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Form APCD-206 - Amine Sweetening Unit AP€N - Revision 7/2018 ® COLORADO any°A;:, Permit Number: AIRS ID Number: [Leave blank unless APCD has already -assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 Op erator Stack iD No -, Discharge, Height`. Above round Level _ (feet) Temp• ( F _= Flow Rate (ACF Velocity t/sec) TO TBD TBD TBD TBD Indicate the direction of the stack outlet: (check one) 0 Upward 0 Horizontal ❑ Downward ❑ Other (describe): 0 Upward with obstructing raincap Indicate the stack opening and size: (check one) ❑✓ Circular Interior stack diameter (inches): TBD ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): Section 6 - Control Device Information ❑ Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. O VRU: Used for control of: Size: Make/Model: Requested Control Efficiency: % VRU Downtime or Bypassed: ❑ Combustion Device: Used for control of: VOC and HAPs from still vent Rating: 27.5 MMBtu/hr Type: Thermal Oxidizer Make/Model: TBD Requested Control Efficiency: 98 Manufacturer Guaranteed Control Efficiency: 99+ Minimum Temperature: °F Waste Gas Heat Content: "'12 Btu/scf Constant Pilot Light: 0 Yes 0 No Pilot Burner Rating: MMBtu/hr Supplemental Fuel Flow: 184 MMscf/year Supplemental Fuel Heat Content: 1030 Btu/scf Closed 0 Loop System: Used for control of: Flash tank Description: Closed loop to fuel or inlet System Downtime: 0 O Other: Used for control of: Description: Requested Control Efficiency: Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 ,COLORADO 4 I ta.nntrentn.nrro Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach alt emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Pollutant Description of Control Method(s) Overall Requested Control Efficiency (9‘ reduction in emissions) PM SOx H25 TO 98% NO. CO VOC TO 98% HAPs TO 98% Other: From what year is the following reported actual annual emissions data? 2019 Criteria Pollutant Emissions Inventory Pollutant Emission Factor Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (tons/year) Controlled Emissions6 (tons/year) Uncontrolled Emissions (tons/year) Controlled Emissions (tons/year) PM SOx 0•1(0(, Ib/MMSCF Mass Balance (° . 0 6 O H25 0.087 Ib/MMSCF Promax 3.18 0.06 NOx 0.098 Ib/MMBtu Mfg. 10.50 10.50 CO 0.082 Ib/MMBtu Mfg. 8.79 8.79 VOC l b • `6 Ib/MMSCF Promax Cola . $ 3 ---4- Non-Criteria Reportable Pollutant Emissions Inventory Chemical Name Chemical Abstract Service CAS ( ) Number Emission Factor Actual Annual Emissions Uncontrolled Basis Units Source (AP -42, M etc.) ) Uncontrolled Emissions (pounds/year) Controlled Emissions6 (pounds/year) Benzene 71432 1.4017 lb/MMSCF Promax loay-l6 1978 Toluene 108883 0.6gl Ib/MMSCF Promax 50'16 5 993 Ethylbenzene 100414 0-0'10 Ib/MMSCF Promax (,c21( 129 Xylene 1330207 6-a0a Ib/MMSCF Promax Ic{'9'•q 292 n -Hexane 110543 O.Ot.I Ib/MMSCF Promax u4-45 14 2,2,4- Trimethylpentane 540841 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 COLORADO 5, Ablor uepa+everc:d}un,. f' H4n[tl.h Enri19immx 1 Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. Signature of Legally Authorized Person (not a vendor or consultant) ate Nick Holland Director EHS&R Name (print) Title Check the appropriate box to request a copy of the: �✓ Draft permit prior to issuance ❑✓ 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 $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B 1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: //www.colorado.gov/cdphe/apcd Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 pp COLORADO 6j �►�;�dt F3txN1•k F.nrugt•mErt CEIVED JAN 2 2 2019 APCD S tional Amine Sweetening Unit - Form APCD-206 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 amine sweetening units only. If your emission unit does not fall into this category, there may be a more specific APEN available for your source (e.g. glycol dehydration unit, hydrocarbon liquid loading, condensate storage tanks, 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. 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: / J WF 00g j AIRS ID Number: 113 /A0Z0 /0 6 7 — [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name: Cureton Front Range LLC Site Name: Hookside Gas Plant Site Location: SE Sec. 30, T9N, R60W Mailing Address: (Include Zip code) 518 17th Street, Suite 650 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nicicholland@curetonmidstream.com I 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 392373 COLORADO 1 I I�Me� bEMVHgTRNM Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action El 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 name3 O Add point to existing permit ❑ Change permit limit 0 Transfer of ownership4 0 Other (describe below) OR- ❑ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - El Limit Hazardous Air Pollutants (HM's) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Ft Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Amine sweetening unit to remove CO2 and trace amounts of H2S. Company equipment Identification No. (optional): Amine2 For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TBD fJ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: Will this equipment be operated in any NAAQS nonattainment area? hours/day Does this facility have a design capacity less than 2 long tons/day of H2S in the acid gas? 'Form APCD-206 - Amine Sweetening Unit APl3'I - Revision 7/2018 ❑✓ days/week Yes Yes a weeks/year No No COLORADO 2 I maw Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Amine Unit Equipment Information Manufacturer: TBD Model No.: TBD Serial Number: TBD Absorber Column Stages: 7 stages Amine Type: O MEA Pump Make and Model: TBD O DEA O TEA 0 MDEA O DGA # of pumps: 2 Sour Gas Throughput: Design Capacity: 60 MMSCF/day Requested5: 21 ,900 MMSCF/year Actual: MMSCF/year Sour Gas: Pressure: 1100 psig Temperature: 116.3 ° F Lean Amine Stream: Pressure: 14 psia Flowrate: 250 gal/min Mole loading H2S: 0.0% Temperature: 252.6 °F Wt. % amine: 50.1 Mole Loading 0.11 % CO2: NGL Input: Pressure: Flowrate: psia Gal/min Temperature: °F Flash Tank: O No Flash Tank Pressure: 65 psia Temperature: 148.5 °F Additional Required Information: O Attach a Process Flow Diagram O Attach the simulation model inputs Et emissions report 0 Attach composition reports for the rich amine feed, sour gas feed, NGL feed, Et outlet stream (emissions) O Attach the extended gas analysis (including BTEX Et n -Hexane, H2S, CO2, temperature, and pressure) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 3 I AV COLORADO Form APCD-206 - Amine Sweetening Unit APC I - Revision 7/2018 Permit Number: AIRS ID Number: / / O Upward ❑ Horizontal [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 4` OperatorFlow Stack ID No Discharge; Height ff ` Above roux Level (feet) ( F) r Rate ' (ACFhI) � Vet9-c.1 (ft/sea) , ... TO TBD TBD TBD TBD Indicate the direction of the stack outlet: (check one) ❑ Downward 0 Other (describe): 0 Upward with obstructing raincap Indicate the stack opening and size: (check one) O Circular Interior stack diameter (inches): TBD ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): Section 6 - Control Device Information ❑ Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. O VRU: Used for control of: Size: Make/Model: Requested Control Efficiency: % VRU Downtime or Bypassed: % O Combustion Device: Used for control of: VOC and HAPs from still vent Rating: 27.5 Type: Thermal Oxidizer MMBtu/hr Make/Model: TBD Requested Control Efficiency: 98 Manufacturer Guaranteed Control Efficiency: 99+ Minimum Temperature: °F Waste Gas Heat Content: —12 Btu/scf Constant Pilot Light: 0 Yes 0 No Pilot Burner Rating: MMBtu/hr Supplemental Fuel Flow: 184 MMscf/year Btu/scf Supplemental Fuel Heat Content: 1030 Closed O Loop System: Used for control of: Flash tank Description: Closed loop to fuel or inlet System Downtime: 0 O Other: Used for control of: Description: Requested Control Efficiency: Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 COLOR ADO 4 I AV Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Pollutant Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) PM SOX H 25 TO 98% NO. CO VOC TO 98% HAPs TO 98% Other: From what year is the following reported actual annual emissions data? 2019 Criteria Pollutant Emissions Inventory Pollutant Emission Factor Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (tons/year) Controlled Emissions6 (tons/year) Uncontrolled Emissions (tons/year) Controlled Emissions (tons/year) PM SOX H2S NO. CO VOC 15J1 Ib/MMSCF Promax a.go.5 1.13 Non -Criteria Reportable Pollutant Emissions Inventory Chemical Name Chemical Abstract Service (CAS) Emission Factor Actual Annual Emissions Uncontrolled Basis Number Mfgetc.) Units Source (AP -42, Uncontrolled Emissions (pounds/year) Controlled Emissionsf' (pounds/year) Benzene 71432 2 • la?. Ib/MMSCF Promax (4646'C 864 Toluene 108883 6,577 I Ib/MMSCF Promax I1W-5 218 Ethylbenzene 100414 Xylene 1330207 .62 O ' Ib/MMSCF Promax 49 S 8 n -Hexane 110543 .24,2 Ib/MMSCF Promax ft104 11 2,2,4- Trimethylpentane 540841 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 COLORADO I A-. Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. Signature of Legally Authorized Person (not a vendor or consultant) Nick Holland Director EHS&R Name (print) Title Check the appropriate box to request a copy of the: �✓ Draft permit prior to issuance ❑✓ 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 $191.13 to: 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 AW COLORADO Amine Sweetening Unit - Form APCD-206 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 amine sweetening units only. If your emission unit does not fall into this category, there may be a more specific APEN available for your source (e.g. glycol dehydration unit, hydrocarbon liquid loading, condensate storage tanks, 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/aped. 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: r r O is $ ! AIRS ID Number: (Z3 /f{ (per / O63 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Cureton Front Range LLC Site Name: Hookside Gas Plant Site Location: SE Sec. 30, T9N, R60W Mailing Address: (Include Zip Code) 518 17th Street, Suite 650 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick.holland@curetonmidstream.com I Please use the full, legal company name registeed 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 the APCD via e-mail to the address provided. Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 392374 COLORADO n r�x o 1 I ANT H��bEnrt�grvn.u:i 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 -OR - ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment 0 Change company name3 0 Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership4 0 Other (describe below) OR - ▪ APEN submittal for update only (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) Additional Info Et Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Amine sweetening unit to remove CO2 and trace amounts of H2S. Company equipment Identification No. (optional):' Amine3 For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TBD 0 Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source hours/day days/week Operation: Will this equipment be operated in any NAAQ5 Yes nonattainment area? Does this facility have a design capacity less than 2 long tons/day of H25 in the acid gas? Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 0 Yes 0 weeks/year No No COLORADO 2 I ' Ne�'mi�nvogx�mwra Permit Number: AIRS ID Number: [Leave blank unless ARCD has already assigned a permit # and AIRS ID] Section 4 - Amine Unit Equipment Information Manufacturer: TBD Model No.: TBD Absorber Column Stages: 7 stages Amine Type: O MEA Pump Make and Model: TBD O DEA ❑ TEA Serial Number: TBD 0 MDEA O DGA # of pumps: 2 Sour Gas Throughput: Design Capacity: 20 MMSCF/day Reaquested5: 7,300 MMSCF/year Actual: MMSCF/year Sour Gas: Pressure: 1000 psig Temperature: 59.9 °F Lean Amine Stream: Pressure: 14 psia Temperature: Flowrate: 100 gal/min Wt. % amine: Mole Loading CO2: Mole loading H2S: 1.2E-5% 253.0 °F 50.1 0.11% NGL Input: Pressure: Flowrate: psia Gal/min Temperature: °F Flash Tank: ❑ No Flash Tank Pressure: 65 psia Temperature: 108 °F Additional Required Information: El Attach a Process Flow Diagram ❑✓ Attach the simulation model inputs Et emissions report O Attach composition reports for the rich amine feed, sour gas feed, NGL feed, Et outlet stream (emissions) • Attach the extended gas analysis (including BTEX Et n -Hexane, H2S, CO2, temperature, and pressure) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 COLORADO 3 I AViF' :, Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 Operatof *K Stack ID No: Discharge Height Aboye Ground Level (feet) Temp ( ir) Flow Rate (A[FM) Velocity (ftlsec) TO TBD TBD TBD TBD indicate the direction of the stack outlet: (check one) ❑✓ Upward 0 Horizontal ❑ Downward ❑ Other (describe): 0 Upward with obstructing raincap Indicate the stack opening and size: (checkone) ❑ Circular Interior stack diameter (inches): TBD ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): Section 6 - Control Device Information 0 Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. O VRU: Used for control of: Size: Make /Model: Requested Control Efficiency: % VRU Downtime or Bypassed: % ❑ Combustion Device: Used for control of: VOC and HAPs from still vent Rating: 27.5 MMBtu/hr Type: Thermal Oxidizer Make/Model: TBD Requested Control Efficiency: 98 Manufacturer Guaranteed Control Efficiency: 99+ Minimum Temperature: °F Waste Gas Heat Content: ^'12 Btu/scf Constant Pilot Light: 0 Yes 0 No Pilot Burner Rating: MMBtu/hr Supplemental Fuel Flow: 184 MMscf/year Supplemental Fuel Heat Content: 1030 Btu/scf Closed O Loop System: Used for control of: Flash tank Description: Closed loop to fuel or inlet System Downtime: 0 O Other: Used for control of: Description: Requested Control Efficiency: Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 COLORADO x 4 „ I ° Win,,,for>nm.n, Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (%reduction): Pollutant Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) PM SOX H2S TO 98% NO. CO VOC TO 98% HAPs TO 98% Other: From what year is the following reported actual annual emissions data? 2019 Criteria Pollutant Emissions Inventory Pollutant Emission Factor Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (tons/year) Controlled Emissions6 (tons/year) Uncontrolled Emissions (tons/year) Controlled Emissions (tons/year) PM SOX H2S 0.087 Ib/MMSCF Promax 0.32 0.006 NOX CO VOC 15,12 Ib/MMSCF Promax c I . ( 0.52 Non -Criteria reportable Pollutant Emissions Inventory Chemical Name Chemical Abstract Service (CAS) Number Emission Factor Actual Annual Emissions Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (pounds/year) (P y ) Controlled Emissionsb (pounds/year) Benzene 71432 2. a Ib/MMSCF Promax 15c-15.(0 299 Toluene 108883 1. l I Ib/MMSCF Promax cbi?ti, 159 Ethylbenzene 100414 , .1.45_ Ib/MMSCF Promax 10(J 21 Xylene 1330207 • ''LZ Ib/MMSCF Promax 2.17q`b 46 n -Hexane 110543 . 01 ti Ib/+x M%i " " }a (O 3 2,2,4- Trimethylpentane 540841 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 COLORADO 5IAY ryv::, Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. Signature of Legally Authorized Person (not a vendor or consultant) Date Nick Holland Director EHS&R Name (print) Title Check the appropriate box to request a copy of the: 0 Draft permit prior to issuance 0 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 $191.13 to: 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 6 I AffiFia«5mpEnut nvtnme+tl COLORADO Glycol Dehydration Unit APEN - Form APCD-202 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 Glycol Dehydration (Dehy) Units only. If your emission unit does not fall into this category, there may be a more specific APEI1 for your source. In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will riot satisfy your reporting needs. A list of all available APEN forms can be find on the Air Pollution Control Division (APCD) website at: www.cotorado.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: 19 IA/ CPO 3 AIRS ID Number: I Z3 /A02p ibot f [Leave blank unless APCD has already assigned a permit tt and AIRS ID] gcc zI1 /19 Company equipment Identification: TEG2 - TE 1 pa.,r Next- pale [Provide Facility Equipment ID to identify how this equipment is referenced within your organization] Section 1 - Administrative Information Company Name': Cureton Front Range LLC Site Name: Hookside Gas Plant Site Location: SE Sec. 30, R9N, T60W Mailing Address: (Include Zip Code) 518 17th Street, Suite 650 Denver, CO 80202 E -Mail Address2: nick.holland@curetonmidstrem.com Site Location County: Weld NAICS or SIC Code: 1321 Permit Contact: Nick Holland Phone Number: 303-324-5967 1Please 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 livoices will be issued by APCD via e-mail to the address provided. Form APCD-202 - Glycol Dehydration Unit AP'EN - Revision 02/2017 392375 COLORADO 1 I V �� Permit Number: AIRS ID Number: / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2- Requested Action r❑ NEW permit OR newly -reported emission source -OR- ❑ MODIFICATION to existing permit (check each box below that applies) El Change fuel or equipment O Change company name O Add point to existing permit O Change permit limit ❑ Transfer of ownership3 O 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) Additional Info Et Notes: 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: 30 MMSCFD TEG Dehydration unit equipped with a Combustor for 95% control (design destruction efficiency of 98%) Facility equipment Identification: For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TEG1 / / TBD / / 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 Will this equipment be operated in any NAAQS nonattainment area Is this unit located at a stationary source that is considered a Major Source of (HAP) Emissions Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 O O days/week Yes Yes 0 weeks/year No No COLORADO 2I H�e�T4� b [+nVa�wiw Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Dehydration Unit Equipment Information Manufacturer: Dehydrator Serial Number: Glycol Used: TBD TBD El Ethylene Glycol (EG) Glycol Pump Drive: El Electric ❑ Gas Pump Make and Model: TBD Model Number: TBD Reboiler Rating: 1 .5 ❑ (DEG) DiEthylene Glycol If Gas, injection pump ratio: MMBTU/hr TriEthylene Glycol (TEG) # of pumps: Glycol Recirculation rate (gal/min): Max: 3.75 Lean Glycol Water Content: Wt.% Requested: 3,75 Acfm/gpm 1 Dehydrator Gas Throughput: Design Capacity: 30 MMSCF/day Requested: 10950 MMSCF/year Actual: MMSCF/year Inlet Gas: Water Content: Flash Tank: Pressure: 60 Cold Separator: Pressure: Pressure: 1100 Wet Gas: psig lb/MMSCF psig psig Stripping Gas: (check one) El None ❑ Flash Gas 0 Dry Gas 0 Nitrogen Flow Rate: scfm Temperature: ❑� Saturated Temperature: Temperature: 120 °F Dry gas: 7.0 lb/MMSCF 135 ° F 0 NA °F El NA Additional Required Information: ❑ Attach a Process Flow Diagram Attach GRI-GLYCaIc 4.0 Input Report Et Aggregate Report (or equivalent simulation report/test results) El Attach the extended gas analysis (i.cluding BTEX Et n -Hexane, temperature, and pressure) Form APCD-202 -Glycol Dehydration Unit APE1 - Revision 02/2017 COLORADO 3I ,V � Nw:hb Tnvlte°M.wal' Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned.a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates" (Latitude/Longitude or UTM) 40.714669/-104.131155 0 erator P Stack ID No Discharge Height Above Ground Level (Feet) Temp (' F) Flow Rate (ACFM) Velocity t/sec Combustor 12 1000 Variable Variable Indicate the direction of the stack outlet (check one) O Upward 0 Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑ Upward with obstructing raincap ❑✓ Circular Interior stack diameter (inches): 48 ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 COLORADO 4 I Y aep®oncm m Pubbc AY �..,a,.e�,u�,Pn,��, Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Control Device Information Used for control of: O Condenser: Type: Make/Model: Maximum Temp Average Temp Requested Control Efficiency O VRU: Used for control of: Size: Make/Model: Requested Control Efficiency % VRU Downtime or Bypassed % ❑ Combustion Device: Used for control of: VOC, HAPs from Still vent Rating: MMBtu/hr Type: Combustor Make/Model: TBD Requested Control Efficiency: Manufacturer Guaranteed Control Efficiency Minimum Temperature: NA 95 98+ % % Waste Gas Heat Content 1906 Btu/scf Constant Pilot Light: ❑✓ Yes O No Pilot burner Rating —0.2 MMBtu/hr Closed O Loop System: Used for contra:l of: Flash tank Description: Routed back to process System Downtime 0 0 ❑ Other: Used for control of: Description: Control Efficiency Requested Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 5 ,VCOLORADO rb� AIRS ID Number: Permit Number: [Leave blank unless APCD has already assigned a permit Y and AIRS ID] 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? El Yes O No If yes, please describe the control equipment AND state the overall control efficiency (% reduction): Pollutant Control Equipment Description Overall Requested Control Efficiency, (% reduction in emissions) PM SOX NO), CO VOC Combustor 95% HAPs Combustor 95% Other: From what year is the following reported actual annual emissions data? 2019 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 Emission Factor Units Emission Factor Source (AP -42, Mfg. etc) .ctual Annual Emission Uncontrolled (Tons/year) Controlled (Tons/year) Uncontrolled (Tons/year) Controlled5 (Tons/year) PM SOX NO„ CO VOC 15.17 Ib/MMSCF Glycalc 83.06 4.15 Benzene 0.5671 lb/MMSCF Glycalc 3.11 0.16 Toluene 0.0298 Ib/MMSCF Glycalc 0.16 0.008 Ethylbenzene Xylenes n -Hexane 0.2963 Ib/MMSCF Glycalc 1.62 0.08 2,2,4- Trimethylpentane Other: a Requested values will become permit limitations. Requested limit(s) should consider future process growth. AAnnual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 6 I rY COLORADO at Public Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. //f/r Signatur of Legally Authorized Person (not a vendor or consultant) - ate Nick Holland Director of EHS&R Name (please print) Title Check the appropriate box to request a copy of the: 0 Draft permit prior to issuance Q Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) Send this form along with $152.90 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B 1 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-202 -Glycol Dehydration Unit APEN - Revision 02/2017 COLORADO 7 I AV of wnu� ��b P.nruoni�n� Glycol Dehydration Unit APEN - Form APCD-202 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 Glycol Dehydration (Dehy) Units only. If your emission unit does not fall into this category, there may be a more specific APEN for your source. 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. 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: (al I, E gAIRS ID Number: 1z3 /kph/6O5 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Company equipment Identification: TEG2 [Provide Facility Equipment ID to identify how this equipment is referenced within your organization] Section 1 - Administrative Information Company Name': Cureton Front Range LLC Site Name: Hookside Gas Plant Site Location: SE Sec. 30, R9N, T60W Mailing Address: (Include Zip Code) 518 17th Street, Suite 650 Denver, CO 80202 E -Mail Address2: nick.holland@curetonmidstrem.com Site Location County: Weld NAICS or SIC Code: 1321 Permit Contact: Nick Holland Phone Number: 303-324-5967 1Please 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-202 - Glycol Dehydration Unit APEN - Revision 02/2017 392376 COLORADO Skpv aAfrc Permit Number: AIRS ID Number: / [Leave blank unless APCD has already assigned a permit #t and AIRS ID] Section 2- Requested Action CI NEW permit OR newly -reported emission source -OR- ❑ MODIFICATION to existing permit (check each box below that applies) O Change fuel or equipment 0 Change company name 0 Add point to existing permit ❑ Change permit limit 0 Transfer of ownership3 ❑ Other (describe below) OR - • APEN submittal for update only (Please note blank APENs will not be accepted) -ADDITIONAL PERMIT ACTIONS - ▪ Limit Hazardous Air Pollutants (HA?s) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Et Notes: 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: 30 MMSCFD TEG Dehydration unit equipped with a Combustor for 95% control (design destruction efficiency of 98%) Facility equipment Identification: For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TEG2 / / TBD / 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 Will this equipment be operated in any NAAQS nonattainment area Is this unit located at a stationary source that is considered a Major Source of (HAP) Emissions 0 days/week Yes Yes Form APCD-202 -Glycol Dehydration Unit AP'I - Revision 02/2017 2 l33� weeks/year No No COLORADO Department et HBaI<A b EteVINIVIv. Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Dehydration Unit Equipment Information Manufacturer: Dehydrator Serial Number: Glycol Used: TBD TBD ❑ (EG) Glycol Pump Drive: Electric ❑ Gas Ethylene Glycol Pump Make and Model: TBD Model Number: TBD Reboiler Rating: 1 .5 ❑ (DEG) DiEthylene Glycol If Gas, injection pump ratio: E] (TEG) # of pumps: Glycol Recirculation rate (gal/min): Max: 3.75 Lean Glycol Water Content: Wt.% Requested: 3.75 MMBTU/hr TriEthylene Glycol Acfm/gpm 1 Dehydrator Gas Throughput: Design Capacity: 30 MMSCF/day Requested: 10950 MMSCF/year Actual: MMSCF/year Inlet Gas: Water Content: Wet Gas: Flash Tank: Pressure: 60 Cold Separator: Pressure: Pressure: 1100 psig lb/MMSCF psig psig Stripping Gas: (check one) El None ❑ Flash Gas ❑ Dry Gas El Nitrogen Flow Rate: scfm Temperature: ❑✓ Saturated Temperature: Temperature: 120 Dry gas: 135 °F 7.0 °F °F lb/MMSCF ❑ NA ❑ NA Additional Required Information: ❑ Attach a Process Flow Diagram ❑r Attach GRI-GLYCaIc 4.0 Input Report a Aggregate Report (or equivalent simulation report/test results) O Attach the extended gas analysis (including BTEX a n -Hexane, temperature, and pressure) Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 COLORADO 3I om� Permit Number: AIRS ID Number: (Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 Q P erator- StN Discharge,' Height Above Ground Level ,. (Feel Temp F ( ) Flow Rate (ACFM) Velocity (ft/sec)-: Combustor 12 1000 Variable Variable Indicate the direction of the stack outlet (check one) I=I Upward 0 Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) 0 Upward with obstructing raincap ❑r Circular Interior stack diameter (inches): 48 ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 1W COLORADO 4 I Hari WbZ svf q»m<5 Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Control Device Information Used for control of: O Condenser: Type: Make/Model: Maximum Temp Average Temp Requested Control Efficiency % ❑ VRU: Used for control of: Size: Make/Model: Requested Control Efficiency VRU Downtime or Bypassed % ❑ Combustion Device: Used for control of: VOC, HAPs from Still vent Rating: MMBtu/hr Type: Combustor Make/Model: TBD Requested Control Efficiency: 95 % Manufacturer Guaranteed Control Efficiency 98+ % Minimum Temperature: NA Waste Gas Heat Content 1906 Btu/scf Constant Pilot Light: 0 Yes O No Pilot burner Rating —0.2 MMBtu/hr Closed 0 Loop System: Used for control of: Flash tank Description: Routed back to process System Downtime 0 0 O Other: Used for control of: Description: Control Efficiency Requested Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 COLORADO 5j V tbab3�. b Yr, vNgn,..en� Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit 11 and AIRS ID] 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? ❑r Yes O No If yes, please describe the control equipment AND state the overall control efficiency (% reduction): Pollutant Control Equipment Description Overall Requested Control Efficiency (% reduction in emissions) PM Sox NO„ CO VOC Combustor 95% HAPs Combustor 95% Other: From what year is the following reported actual annual emissions data? 2019 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 Emission Factor Units Emission Factor Source (AP -42, Mfg. etc) Controlled5 (Tons/year) mission Limit Uncontrolled (Tons/year) Uncontrolled (Tons/year) Controlled (Tons/year) PM SO. NO,, CO VOC 15.17 Ib/MMSCF Glycalc 83.06 4.15 Benzene 0.5671 Ib/MMSCF Glycalc 3.11 0.16 Toluene 0.0298 Ib/MMSCF Glycalc 0.16 0.008 Ethylbenzene Xylenes n -Hexane 0.2963 Ib/MMSCF Glycalc 1.62 0.08 2,2,4- Trimethylpentane Other: 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 5Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 6 I COLORADO 9eportravvtstVunuc WFII:H 43IVIOV NOVI Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. gnature of Legally Authorized Person (not a vendor or consultant) Nick Holland Director of EHS&R Name (please print) Title Check the appropriate box to request a copy of the: ❑r 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) Send this form along with $152.90 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B 1 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-202 -Glycol Dehydration Unit APEN - Revision 02/2017 COLORADO 7I A.117• Condensate Storage Tank(s) APEN Form APCD-205 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 tanks that store condensate associated with oil and gas industry operations. If your emission source does not fall into this categpry, there may be a more specific APEN available for your source (e.g. crude oil storage tanks, produced water storage tanks, hydrocarbon liquid loading, 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 and associated addendum forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.Rov/pacific/cdphe/air-permits. This emission notice is valid for five (5) yeaes. 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: 9W Erp(13' ) AIRS II) Number: (Z3 /A'Q52J/ 66‘, [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Cureton Front Range LLC Site Name: Hookside Gas Plant Site Location: SE Sec. 30, T9N, R60W Mailing Address: (Include Zip Code) 518 17th Street, Suite 650 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick.holland@curetonmidstream.com 1 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 the APCD via e-mail to the address provided. Form APCD-205 - Condensate Storage Tank(s!j APEN - Revision 7/2018 392377 COLORADO 1j N+.>sl.iE,lroi.onmwq 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 ❑✓ Request coverage under traditional construction permit O Request coverage under a General Permit O GP01 0 GP08 If General Permit coverage is requested, the General Permit registration fee of $312.50 must be submitted along with the APEN filing fee. -OR - ❑ MODIFICATION to existing permit (deeck each box below that applies) ❑ Change in equipment 0 Change company name3 ❑ Change permit limit 0 Transfer of ownership4 0 Other (describe below) - OR • APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ APEN submittal for permit exempt/grandfathered source ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Et Notes: Emergency tank for off spec stabilized condensate 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: 400 bbl stabilized condensate tanks Company equipment Identification No. (optional): TK1 For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: Normal Hours of Source Operation: 24 Storage tank(s) located at: hours/day 7 days/week 52 weeks/year ❑ Exploration Et Production (EEtP) site ❑✓ Midstream or Downstream (non EftP) site Will this equipment be operated in any NAAQS nonattainment area? • Yes 12 No Are Flash Emissions anticipated from these storage tanks? • Yes GI No Is the actual annual average hydrocarbon liquid throughput ≥ 500 bbl/day? ■ Yes rA No If "yes", identify the stock tank gas -to -oil ratio: m3/liter Are these storage tanks subject to Colorado Oil and Gas Conservation Commission (COGCC) 805 series rules? If so, submit Form APCD-105. Yes No • 4 Are you requesting ≥ 6 ton/yr VOC emissions (per storage tank), or are uncontrolled actual emissions ≥ 6 ton/yr (per storage tank)? Yes No 0 • COLORADO Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit fi and AIRS ID] Section 4 - Storage Tank(s) Information Actual Annual Amount (bbl/year) Requested Annual Permit Limits (bbl/year) Condensate Throughput: 9125 From what year is the actual annual amount? 2019 Average API gravity of sales oil: 73.3 degrees O Internal floating roof Tank design: 0 Fixed roof RVP of sales oil: 9.4 ❑ External floating roof Storage Tank ID # of Liquid Manifold Storage Vessels in Storage Tank Total Volume of Storage Tank (bbl) Installation Date of Most Recent Storage Vessel in Storage Tank (month/year) Date of First Production (month/year) TK-1 1- 400 Wells Serviced by this Storage Tank or Tank Battery6 (ErtP Sites On y) API Number Name of Well Newly Reported Well _ • - ■ - ■ - ■ _ • 5 Requested values will become permit limitations. Requested limit(s) should consider future growth. 6 The EEtP Storage Tank APEN Addendum (Form APCD-212) should be completed and attached when additional space is needed to report all wells that are serviced by the equipment reported on this APEN form. Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 Operator Stack ID No. Discharge Height Above Ground Level (feet) Temp. (°F) Flow Rate (ACFM) Velocity (ft/sec) Combustor 12 1000 Variable Variable Indicate the direction of the stack outlet: (check one) ❑� Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑� Circular ❑ Square/rectangle ❑ Other (describe): ❑ Upward with obstructing raincap Interior stack diameter (inches): 48 Interior stack width (inches): Interior stack depth (inches): Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 �j COLORADO 3 I �� Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit rr and AIRS ID] Section 6 - Control Device Information ❑ Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. Vapor ❑ Recovery Unit (VRU): Pollutants Controlled: Size: Requested Control Efficiency: VRU Downtime or Bypassed (emissions vented): Make/Model: % ❑ Combustion r Device: Pollutants Controlled: VOC and HAPs Rating: Type: Enclosed Combustor MMBtu/hr Make/Model: I TB Requested Control Efficiency: 95 % Manufacturer Guaranteed Control Efficiency: 98+ Minimum Temperature: NA Waste Gas Heat Content: Constant Pilot Light: ❑✓ Yes 0 No Pilot Burner Rating: 1906 0.2 Btu/scf MMBtu/hr O Closed Loop System Description of the closed loop system: 0 Other: Pollutants Controlled: Description: Control Efficiency Requested: Section 7 - Gas/Liquids Separation Technology Information (E&P Sites Only) What is the pressure of the final separator vessel prior to discharge to the storage tank(s)? psig Describe the separation process between the well and the storage tanks: Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 COLORADO 4 �., Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit /r and AIRS ID] Section 8 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Pollutant Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) VOC Combustor 95% NOx CO HAPs Combustor 95% Other: From what year is the following reported actual annual emissions data? 201 9 Criteria Pollutant Emissions Inventory Pollutant Emission Factor Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units Source (AP -42, Mfg. etc) Uncontrolled Emissions (Tons/year) Controlled Emissions8 (Tons/year) Uncontrolled Emissions (Tons/year) Controlled Emissions (Tons/year) VOC 2.467 lb/bbl E&P Tanks 11.26 0.56 NOx CO Non -Criteria Reportable Pollutant Emissions Inventory Chemical Name Chemical Abstract Service CAS (CAS) Number Emission Factor Actual Annual Emissions Uncontrolled Basis Units Source (AP -42, Mfg. etc) Uncontrolled Emissions (Pounds/year) Controlled Emissions8 (Pounds/year) Benzene 71432 3.879E-2 lb/bbl E&P Tanks 354 18 Toluene 108883 Ethylbenzene 100414 Xylene 1330207 n -Hexane 110543 2,2,4- Trimethylpentane 540841 5 Requested values will become permit limitations. Requested limit(s) should consider future growth. 7 Attach condensate liquid laboratory analysis, stack test results, and associated emissions calculations if you are requesting site specific emissions factors according to the guidance in PS Memo 14-03. 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 COLORADO 5j .nt 11W11,Enr�wnment 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. If this is a registration for coverage under General Permit GP01 or GP08, I further certify that this source is and will be operated in fu Ycompliance with each condition of the applicable General Permit. Signature of Legally Authorized Person (not a vendor or consultant) Nick Holland Date Director EHS&R Name (print) Title Check the appropriate box to request a copy of the: �✓ Draft permit prior to issuance ID 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 $191.13 and the General Permit registration fee of $312.50, if applicable, to: 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 COLORADO d Pum,c 6 I ' n�r•e€nrvo, E&P TANK V2.0 Calculation Report--- Developed by DB Robinson & Associates Ltd. 2019.0107 Project Setup Information Project File. Model Calculation Method Control Efficiency Filed Name. Well Name Well ID Date * Data Input Separator Pressure Separator Temperature Ambient Pressure Ambient Temperature C10+ SG C10+ MW -- Stable Oil C:\Lasers\ashle\OneDrive\Documents\Projects\Cureton\Hookside\Stabilized Condensate Ta : Stable Oil Tank AP42 : 95.0% stabilized oil : Hookside : Off spec tank : 2019.0104 : 23.00[psig] : 85.00[F] 14.70[psia] 70..00[F] :-0:8990 : 166.00 No. Component mol %, 1 H2S 0.0000 2 02 0.0000 3 CO2 0.0000 4 N2 0.0000 5 Cl 0.0000 6 C2 0.0000 7 C3 0.0032 a i-C4 0.2564 9 n -C4 4.7842 10 i-05 11.6437 11 n -05 20,5035 12 C6 27.7824 13 C7 19.0972 14 C8 3.6947 15 C9 2.3960. 16 C10+ 1.6955 17 Benzene 2'.7785 18 Toluene 2.9805 19 E -Benzene 0.9168 20 Xylenes 1.4457 21 n -C6 -0.0000 22 224Trimethylp 0:.0217 -- Sa/es Oil Production Rate : 25[bbl/clay] Days of Annual Operation : 365 [days/year]. API Gravity : 73.3 Reid Vapor Pressure : 9.40[psia] Bulk Temperature 114.00[F] -- Tank and Shell Data Diameter Shell Height Cone Roof Slope Average Liquid Height Vent Pressure Range Solar Absorbance -- Meteorological Data 12.00 [ft] 20.00 [ft] : 0.08 : 10.00(ft] : 0.03 [psi.] 0.54 page 1 E&P TANK V2.0 Calculation Report--- Developed by DB Robinson & Associates Ltd. 2019.01.07 City Ambient Pressure Ambient Temperature Min Ambient Temperature Max Ambient Temperature Total Solar Insolation Denver,- CO 14.70[ps.ia] 70.00[F] 36,20[F] 64.30 [F] 1568.001[Btu/ft^2*day] * Calculation Results * Emission Summary -- --- Item Total BAPs Total EC. VOCs, C2+ VOCs, C3+ Uncontrolled [ton/yr] 0.280 11.255 11.255 11.255 Uncontrolled alb/hr] D.064 2.570 2.570 2.570 Uncontrolled Recovery Info. Vapor 316.1100 x1E-3 [MSCFD] BC Vapor. 316.1100 x1E-3 [MSCFD] GOR 12.64 [SCF/bbl] Emission Composition Controlled Controlled [ton/yr] [lb%hr] 0.014 0.003 0..563 0.128 0.563 0.128 0.563 0.128 No Component Uncontrolled [ton/yr] 1 32S 0.000 2 02 0.000 3 CO2. 0.000 4 N2 0.000 5 Ci 0.000 6 C2 0.000 7 C3 0.001 8 1-C4 0.094. 9 n -C4 1.455 10 i-05 2.443 11 n -05 3..486 12 C6 2.584 13 C7 0.824 14 C8 0.068 15 C9 0.019 16 C10+ 0.001 17 Benzene 0.1/7 18 Toluene 0.076 19 E -Benzene 0.010 2D Xylenes 0.014 21 n -05 0.000 22 224Trimethylp 0.001 Total 11.253 — Stream Data No. Component 1 32S 2 02 3 CO2 4 N2 5 Cl 6 C2 7 C3 8 i-C4 9 n -C4 10 i-05 11 n -05 12 C6 13 C7 Uncontrolled [lb/hr] 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.021 0.332 0.558. 0.796, 0.590 0.188 0.016 0.004 4.000 0.040 0.017 0.002 0.003 8.000 8.000 2.569 Controlled Controlled [ton/yr] [lb/hr] 0.000 0.000 0.000 0.000 0.000 0..000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.005 0.001 0.073 0.017 0.122 0.028 0.174 0.040 0.129 0..029 0.041 0.009 0.003 0.001 0.001 0.000 0.000 0.000 0.009 0.002 0.004 0..001 `0.001 0.000 0.001 0.000 0.000 0.000 0.000 0.000 0.563 0.128 MW Stable Oil Sales Oil mol mol 34.80 0.9508 0.0000 32.00 0.0000 0.0000 44.01 .0..2437 0.0000 28.01 0.0102 0.0000 16.04 0.4543 0.0000 30.07 0.6701 0.0000 44.10 2.1627 0.0028 58.12 1.1269 0.2353 58.12 4.0091 4.4790 72.15 3.1066 11.3709 72.15 5.0558 20.2162 86.16 4.1726 27.9806 100.20 10,3655 19.4456 rage 2 Total Emissions mol % 0.0000 0.0000 0.0000 0.0.000 0.0000 0=0000 0_0189 1,0574 16.4474 22.2398 91.7392 20.2107 5.5820 E&P TANK V2..0 Calculation Report--- Developed by DB Robinson & Associates Ltd. 2019.01,07 14 C8. 114.23 10.8426 3.7793 0.4020 15 C9 128.28 5.5127 2.4549 0.1040 16 C10+ 166.00 45.9695 1.7389 0.0040 17 Benzene 78.11 0.5685 2.8119 1.4919 18 Toluene 92.13 0.2132 3.0432 0.5446 19 E -Benzene 106.17 0.0711 0.9387 0.0637 20 Xylenes 106.17 0,6802 1.4805 0.0894 21 n -C6 86.18 3.5939 0.0000 0.0000 22 224Trimethylp 114.24 0..0000 0.0221 0.0051 MW 8530 85.45 73.94 Stream Mole Ratio 1.4000 0.9879 0.01.21 Heating Value [BTU/SCFJ 4064.81 Gas Gravity (Gas/Air] 2.55 Bubble Pt: 5 100F[psia] 10.38 10.14 RVP @ 100F [psis] 70.41 68.80 SG @ 100F 0.664 0.665 Produced Water Storage Tank(s) APEN - Form APCD-207 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 my 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 tanks that store produced water associated with oil and gas industry operations. If your emission source does not fall into this category, there may be a more specific APEN available for your source (e.g. crude oil storage tanks, condensate storage tanks, hydrocarbon liquid loading, 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 and associated addendum forms can be found on the Air Pollution Control Division (APCD) website at: www.cotorado.Rov/pacific/cdphe/air-permits. 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: I qtAIP081 AIRS ID Number: 1Z3 'A `4b2o' od 7 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Cureton Front Range LLC Site Name: Hookside Gas Plant Site Location: SE Sec. 30, R9N, T60W Mailing Address: (Include Zip Code) 518 17th Street, Suite 650 Denver, CO 802 D2 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick.holland@curetonmidstream.com t 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 the APCD via e-mail to the address provided. Form APCD-207 - Produced Water Storage Tank(s) APEN - Revision 7/2018 392373 COLORADO 1 I ,V n,. 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 El Request coverage under traditional construction permit O Request coverage under a General Permit ❑ GP05 O GP08 If General Permit coverage is requested, the General Permit registration fee of $312.50 must be submitted along with the APEN filing fee. -OR- ❑ MODIFICATION to existing permit (check each box below that applies) O Change in equipment O Change company name3 ❑ Change permit limit O Transfer of ownership4 O Other (describe below) OR- ❑ APEN submittal for update only (Nate blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ APEN submittal for permit exemptfgrandfathered source ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info £t Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Company equipment Identification No. (optional): For existing sources, operation began on: Five 400 bbl produced water tanks TK2 and TK6 For new or reconstructed sources, the projected start-up date is: TBD Normal Hours of Source Operation: 24 hours/day 7 Storage tank(s) located at: O Exploration & Production (E&P) site days/week 52. weeks/year ❑✓ Midstream or Downstream (non E&P) site Will this equipment be operated in any NAAQS nonattainment area? ❑ Yes No ✓ Are Flash Emissions anticipated from these storage tanks? Yes No ✓ • Are these storage tanks located at a commercial facility that accepts oil production wastewater for processing? ❑ Yes No ✓ Do these storage tanks contain less than 1% by volume crude oil on an annual average basis? ✓ Yes • No Are these storage tanks subject to Colorado Oil and Gas Conservation Commission (COGCC) 805 series rules? If so, submit Form APCD-1D5. ❑ Yes No ✓ Are you requesting ≥ 6 ton/yr VOC emissions (per storage tank), or are uncontrolled actual emissions ≥ 6 ton/yr (per storage tank)? Yes ❑ No ✓ COLORADO Form APCD-207 - Produced Water Storage Tank(s) APEN - Revision 7/2018 Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Storage Tank(s) Information Actual Annual Amount (bbl/year) Requested Annual Permit Limits (bbl/year) Produced Water Throughput: 237250 From what year is the actual annual amount? Tank design: ❑✓ Fixed roof 2019 O Internal floating roof O External floating roof Storage Tank ID # of Liquid Manifold Storage Vessels in Storage Tank Total Volume of Storage Tank (bbl) Installation Date of Most Recent Storage Vessel in Storage Tank (month/year) Date of First Production (month/year) TK2-6 5 2000 TBD TBD Wells Serviced by this Storage Tank or Tank Battery6 (EEtP Sites On y) API Number Name of Well Newly Reported Well - - ❑ - ❑ _ ❑ _ ❑ 5 Requested values will become permit limitations. Requested limit(s) should consider future growth. 6 The EEtP Storage Tank APEN Addendum (Form APCD-212) should be completed and attached when additional space is needed to report alt wells that are serviced by the equipment reported on this APEN form. Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 Operator Stack ID No. Discharge Height Above Ground Level (feet) Temp. (°F) Flow Rate (ACFM) Velocity (ft/sec) Combustor 12 1000 Variable Variable Indicate the direction of the stack outlet: (check one) ❑✓ Upward ❑ Horizontal ❑ Downward ❑Other (describe): 0 Upward with obstructing raincap Indicate the stack opening and size: (check one) ❑✓ Circular Interior stack diameter (inches): 48 ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): O Other (describe): Form APCD-207 - Produced Water Storage Tank(s) APEN - Revision 7/2018 COLORADO 3 I � M1 aurato>s�ynmri+i Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit 11 and AIRS ID] Section 6 - Control Device Information O Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. Pollutants Controlled: Vapor O Recovery Unit (VRU): Size: Requested Control Efficiency: VRU Downtime or Bypassed (emissions vented): Make/Model: 0 Combustion Device: Pollutants Controlled: VOC and HAPs Rating: Type: Enclosed MMBtu/hr Make/Model: 1 T B D Requested Control Efficiency: 95 Manufacturer Guaranteed Control Efficiency: Minimum Temperature: Constant Pilot Light: NA 98+ Waste Gas Heat Content: Yes O No Pilot Burner Rating: tale 0.2 Btu/scf MMBtu/hr O Closed Loop System Description of the closed loop system: O Other: Pollutants Controlled: Description: Control Efficiency Requested: Section 7 - Gas/Liquids Separation Technology Information (E&tP Sites Only) What is the pressure of the final separator vessel prior to discharge to the storage tank(s)? psig Describe the separation process between the well and the storage tanks: Form APCD-2O7 - Produced Water Storage Tank(s) APEN - Revision 7/2018 COLORADO 4 I AV �'rynxnpkF.nvs�9rvn�'n:1 Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit f and AIRS ID] Section 8 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction ): Pollutant Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) VOC Combustor 95% NOx CO HAPs Combustor 95% Other: From what year is the following reported actual annual emissions data? 201 9 Criteria Pollutant Emissions Inventory Pollutant Emission Factor Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (tons/ ear y ) Controlled Emissiores8 (tons/year) Uncontrolled Emissions (tons/year) Controlled Emissions (tons/year) VOC 0.262 lb/bbl Stale default 31.08 1.55 NOx CO O.6(lol. 11/4/bb( AP-4).}`?kG a . 0 ) . o Non -Criteria Reportable Pollutant Emissions Inventory Chemical Name Chemical Abstract Service (CAS) Number Emission Factor Actual Annual Emissions Uncontrolled Basis Units Source (AP -42, mfg., etc. I Uncontrolled Emissions (pounds/year) (pounds/ ear(pounds/year) Controlled Emissions8 Benzene 71432 0.007 lb/bbl State default 1661 83 Toluene 108883 Ethylbenzene 100414 Xylene 1330207 n -Hexane 110543 0.022 lb/bbl State default 5220 261 2,2,4- Trimethylpentane 540841 5 Requested values will become permit limitations. Requested limit(s) should consider future growth. 7 Attach produced water laboratory analysis, stack test results, and associated emissions calculations if you are requesting site specific emissions factors according to the guidance in PS Memo 14-03. 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-207 - Produced Water Storage Tank(s) APEN - Revision 7/2018 5 mom„n. I AV r�na�nvno,.,a COLORADO Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit t 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. If this is a registration for coverage under General Permit GP05 or GP08, I further certify that this source is and will be operated in full compliance with each condition of the applicable General Permit. //1:://7 De Signature of Legally Authorized Person (not a vendor or consultant) Nick Holland Director of EHS&R 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 $191.13 and the General Permit registration fee of $312.50, if applicable, to: 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-207 - Produced Water Storage Tank(s) APEN - Revision 7/2018 AV,,,„ -.7,174,74,„„:.c4, COLORADO 6 I JAN 222 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. print shop, 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 are 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.Qov/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: p AIRS ID % -(uJE pO8 Number: 1 Z3 'Adzcp 1008 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Cureton Front Range LLC Site Name: Hookside Gas Plant Site Location: SE Sec. 30, T9N, R60W Mailing Address: (include Zip Code) 518 17th Street, Suite 650 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick.holland@curetonmidsream.com 1 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address rovided. 39 38C Form APCD-220 - Boiler APEN - Revision 7/2018 A COLOR A, DO 1 181' ku.nnb Fr..riepnm�m Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit /t 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 name3 O Add point to existing permit ❑ Change permit limit O Transfer of ownership4 O Other (describe below) - OR ❑ APEN submittal for update only (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 Et Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Amine Reboiler Manufacturer: TBD Model No.: TBD Serial No.: TBD Company equipment Identification No. (optional): For existing sources, operation began on: For new, modified, or reconstructed sources, the projected start-up date is: HTR2 TBD ❑✓ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: Seasonal use Dec- Mar- June - percentage: Feb: May: Aug: hours/day Are you reporting multiple identical boilers on this APEN? O Yes r❑ No days/week weeks/year Sept - Nov: 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 7/2018 COLORADO ct xx Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit N and AIRS ID] Section 4 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 operator Stack ID No r Discharge;Height Above Ground Level (F eet)) temp ( F) Flow Ra te' (ACFM) Velocity` (ft/sec HTR2 TBD 800 2540 8.63 Indicate the direction of the stack outlet: (check one) Q Upward El Horizontal O Downward o Other (describe): Indicate the stack opening and size: (check one) ❑✓ Circular Interior stack diameter (inches): 0 Upward with obstructing raincap 30 O Square/rectangle Interior stack width (inches): Interior stack depth (inches): 0 Other (describe): Section 5 - Fuel Consumption Information Design Input Rate (MMBTU/hr) Actual Annual Fuel Use5 (Specify Units) Requested Annual Permit Limit6 (Specify Units) 17.5 148.8 MMSCF/yr From what year is the actual annual fuel use data? Fuel consumption values entered above are for: 0 Each Boiler 0 All Boilers ❑� N/A Indicate the type(s) of fuel used': ❑ Pipeline Natural Gas ❑✓ Field Natural Gas ❑ Ultra Low Sulfur Diesel 0 Propane o Coal o Other (describe): (assumed fuel heating value of 1,020 BTU/SCF) Heating value: 1030 BTU/SCF (assumed fuel heating value of 138,000 BTU/gallon) (assumed fuel heating value of 2,300 BTU/SCF) Heating value: BTU/lb Ash content: Sulfur Content: Heating value (give units): 5 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. 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. ' If fuel heating value is different than the listed assumed value, please provide this information in the "Other" field. Form APCD-220 - Boiler APEN - Revision 7/2018 COLORADO 3 „ �� Y�a.3iAEFnoIdoMFni1 Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Criteria Pollutant Emissions Information Attach all emissions calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? O Yes ❑✓ No If yes, please describe the control equipment AND state the overall control efficiency (% reduction ): Pollutant Control Equipment Description Overall Control'' Efficiency (% reduction in emissions) TSP (PM) PMio PM2.5 SOX NO. CO VOC From what year is the following reported actual annual emissions data? 2019 Use the following tables to report the criteria pollutant emissions from source: (Use the data reported in Section 5 to calculate these emissions.) Primary Fuel Type - (natural gas, #2 diesel, etc.) Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg., etc.) annual Emissions , ested Annual mission, Limit Uncontrolled (tons/year) Controlled8 (tons/year) Uncontrolled (tons/year) Controlled (tons/year) Natural Gas TSP (PM) 7.6 AP -42 0.57 PMio 7.6 AP -42 0.57 PM2.5 7.6 AP -42 0.57 SOX 0.6 AP -42 NO. 50 AP -42 0.04 3-'}c! CO 41 Mfg. 3.07 VOC 5.5 AP -42 0.41 0 Check this box if multiple fuels were NOT fired 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 pollutant emissions table below: Secondary Fuel Type (#2 diesel, waste oil, etc.) Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg., etc.) missions equested Annua :mission. Limit, Uncontrolled (tons/year) Controlled8 (tons/year) Uncontrolled (tons/year) Controlled (tons/year) TSP (PM) PMto PM2.5 SOX NO. CO VOC 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. $ Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 7/2018 COLORADO 4 I Wes.1, 1r tee. Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID} 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 s Pollutant =4 Actua�rAnrival Emissions, r requested Annual Permit r Emission Limits) Uncontrolled (tons/year) Controlled8 (tons/year) Uncontrolled (tons/year) Controlled (tons/year) TSP (PM) PM10 PM2.5 SOX NO. CO VOC 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. 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: Primary Fuel Type (natural gas, #2 diesel, etc.) Natural Gas CAS Number Chemical Name Overall '- Control Efficiency Uncontrolled Emission Factor (specify units) Emission Factor Source ., .) (AP 42; Mfgetc Uncontrolled Actual Emissions (lbs/year) Controlled Actual Emissions e (lbs/year) n -Hexane 1.8 Ib/MMSCF AP -42 268 ❑✓ Check this box if multiple fuels were NOT fired during this reporting period and skip to Section 8. If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total non -criteria pollutant (HAP) emissions table below: Secondary Fuel Type (#2 diesel, waste oil, etc.) CAS Number Chemical Name Overall Control Efficiency Uncontrolled Emission Factor (specify units) Factor Emission F Source (AP -42, Mfg., etc.) Uncontrolled " Actual Emissions (lbs/ ear y ) Controlled Actual , Emissions8 (lbs/year) 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-22D - Boiler APEN - Revision 7/2018 COLORADO 5 a ti4getn.mcl Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] If multiple fuels were fired during this reporting period, use the following table to report the TOTAL non -criteria pollutant (HAP) 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 7: nnual Emissio Controlled8 (tons/year) Uncontrolled (tons/year) 8 Annual emissions 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. r1/ Signature bf Legally Authorized Person (not a vendor or consultant) D Nick Holland Director EHS&R Name (please print) Title Check the appropriate box if you want: 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 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 $191.13 to: 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-220 - Boiler APEN - Revision 7/2018 COLORADO 6i l:wia.s HaxYA 6E1+'+i;o IV flI JAN222U's 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. print shop, 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/aped. 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 are 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.i;ov/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: AIRS ID /R WEI7543 ( Number: I23 /Ack243'O0 j' [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name1: Site Name: Site Location: Cureton Front Range LLC Hookside Gas Plant Site Location SE Sec. 30, T9N, R60W County: Weld Mailing Address: (Include Zip Code) 518 17th Street, Suite 650 Denver, CO 80202 NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick.holland@curetonmidsream.com I 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to e Nretsy r1vided. Form APCD-220 - Boiler APEN - Revision 7/2018 �y COLORADO 1 I El. 1=1=41 Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit N and AIRS ID] Section 2 - Requested Action O NEW permit OR newly -reported emission source -OR - ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment 0 Change company name3 0 Add point to existing permit ❑ Change permit limit 0 Transfer of ownership4 0 Other (describe below) - OR ❑ APEN submittal for update only (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/ggrandfathered source Additional Info Et Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Stabilizer heater Manufacturer: TBD Model No.: TBD Serial No.: TBD Company equipment Identification No. (optional): For existing sources, operation began on: For new, modified, or reconstructed sources, the projected start-up date is: HTR3 TBD O Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: Seasonal use Dec- Mar- June - percentage: Feb: May: Aug: hours/day Are you reporting multiple identical boilers on this APEN? ❑ Yes 0 No days/week weeks/year Sept - Nov: 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): .COLORADO Form APCD-220 - Boiler APEN - Revision 7/2018 Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit q and AIRS ID] Section 4 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 0 tor P era , Stack ID No Discharge Height Above Ground Level' -.• (Feed Ternp (S ) Flow Rate (ACFM) Velocity .(ft/sec) HTR3 TBD 1250 1597 10.08 Indicate the direction of the stack outlet: (check one) ❑✓ Upward o Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑✓ Circular Interior stack diameter (inches): o Square/rectangle Interior stack width (inches): ❑ Other (describe): 0 Upward with obstructing raincap 22 Interior stack depth (inches): Section 5 - Fuel Consumption Information Design Input Rate (MMBTU/hr) Actual Annual Fuel Use5 (Specify Units) Requested Annual Permit Limit6 (Specify, Units) 11.00 93.6 MMSCF/yr From what year is the actual annual fuel use data? Fuel consumption values entered above are for: 0 Each Boiler 0 All Boilers ❑✓ N/A Indicate the type(s) of fuel used: ❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑r Field Natural Gas Heating value: 1 030 BTU/SCF ❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) o Propane (assumed fuel heating value of 2,300 BTU/SCF) o Coal Heating value: BTU/lb Ash content: Sulfur Content: o Other (describe): Heating value (give units): 5 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. 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 7 If fuel heating value is different than the listed assumed value, please provide this information in the "Other" field. Form APCD-220 - Boiler APEN - Revision 7/2018 .COLOR 400 3 1 tc Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Criteria Pollutant Emissions Information Attach all emissions calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? 0 Yes 0 No If yes, please describe the control equipment AND state the overall control efficiency (% reduction): Pollutant Control Equipment Description Overall Control Efficiency (% reduction in emissions) TSP (PM) PM10 PM2.5 SO. NO. CO VOC From what year is the following reported actual annual emissions data? 2019 Use the following tables to report the criteria pollutant emissions from source: (Use the data reported in Section 5 to calculate these emissions.) Primary Fuel Type (natural gas, #2 diesel, etc.) Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg., etc.) Actual Annual Emissions equested Annual 6:14.00,Riumjti Uncontrolled (tons/year) Controlled8 (tons/year) Uncontrolled (tons/year) Controlled (tons/ year) Natural Gas TSP (PM) 7.6 AP -42. 0.36 PM10 7.6 AP -42 0.36 PM2.5 7.6 AP -42 0.36 SO. 0.6 AP -42 NO. 50 AP -42 CO 41 Mfg. 0.03 1.93 VOC 5.5 AP -42 0.26 ❑✓ Check this box if multiple fuels were NOT fired 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 pollutant emissions table below: Secondary Fuel Type (#2 diesel, waste oil, etc.) Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg:, etc.) Controlled8 (tons/year) Uncontrolled (tons/year) Uncontrolled (tons/year) Controlled (tons/year) TSP (PM) PM10 PM2.5 SO. NO. CO VOC 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 7/2018 4I ATCOLORADO �o«_ Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] 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 Actual Annual Emissions , Requested Annual Permit f Emi441orr Limit(s)6 :- Uncontrolled (tons/year) Controlled 8` (tons/year) Uncontrolled (tons/year) ' ` Controlled (tons/year) ; TSP (PM) PM10 PM2.5 SOx NOX CO VOC 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. 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: Primary Fuel Type (natural gas, #2 diesel, etc.) Natural Gas CAS Number Chemical Name Overall Control Efficiency Uncontrolled Emission Factor (specify units) Emission Factor Source (AP -42, Mfg., etc. /. Uncontrolled Actual Emissions (lbs/year) Controlled Actual Emissions (lbs/year) ❑✓ Check this box if multiple fuels were NOT fired during this reporting period and skip to Section 8. If multiple fuels were fired during this reporting period, comp ete this secondary fuel emissions table and the total non -criteria pollutant (HAP) emissions table below: Secondary Fuel Type (#2 diesel, waste oil, etc.) CAS Number Chemical Name Overall Control Efficiency Uncontrolled Emission Factor (specify units) Emission Factor Source i (AP -42, Mfg., etc) Uncontrolled Actual - Emissions (lbs/year) Controlled Actual Emissions8 (lbs/year) 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 7/2018 COLORADO 5 l =7:.V,72:„„ Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] If multiple fuels were fired during this reporting period, use the following table to report the TOTAL non -criteria pollutant (HAP) 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 7: CAS Number Chemical Name Actual Annual „t:. Emissions _�. Uncontrolled (tons/year) Controlled8 (tons/year) S Annual emissions 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. Signature of Legally Authorized Person (not a vendor or consultant) D Nick Holland Name (please print) e 1 a Director EHS&R Title Check the appropriate box if you want: El 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 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 $191.13 to: 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.Rov/cdphe/apcd Form APCD-220 - Boiler APEN - Revision 7/2018 6 I AV:COLOR ADO i "qe_a,itlbEmi Hvennivumi 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. print shop, 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 are 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: AIRS ID tvr g( ' Number: /ZS /AOZO 6(D [Leave blank unless APCD has already assigned a permit ft and AIRS ID] Section 1 - Administrative Information Company Name': Cureton Front Range LLC Site Name: Hookside Gas Plant Site Location: SE Sec. 30, T9N, R60W Mailing Address: (Include Zip Code) 518 17th Street, Suite 650 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick.holland@curetonmidsream.com 1 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. 392382 Form APCD-220 - Boiler APEN - Revision 7/2018 COLORADO F:wdfA4Ef1v5:anfxrtnl Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit 1 and AIRS ID] Section 2 - Requested Action O NEW permit OR newly -reported emission source -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment 0 Change company name3 0 Add point to existing permit ❑ Change permit limit 0 Transfer of ownership4 O Other (describe below) -OR- ❑ APEN submittal for update only (Nate 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: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Mol sieve regen gas heater Manufacturer: TBD Model No.: TBD Serial No.: TBD Company equipment Identification No. (optional): For existing sources, operation began on: For new, modified, or reconstructed sources, the projected start-up date is: HTR4 TBD ID Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: Seasonal use Dec- Mar- June - percentage: Feb: May: Aug: hours/day Are you reporting multiple identical boilers on this APEN? ❑ Yes ❑✓ No days/week weeks/year Sept - Nov: 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 7/2018 COLORADO 2I �a � '. Mg.!. c�,.�.o,u..rnt Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Stack Information Geographical Coordinates (Latitude/Lonsitude or UTM) 40.714669/-104.131155 O P erator Stack ID No Discharge Height Ff Above Ground Level (Feed Temp ('FJ Flow Ra tes (ACFM) Veloct Y (ft/sec) HTR4 TBD 800 2395 8.13 Indicate the direction of the stack outlet: (check one) ❑✓ Upward O Horizontal o Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑✓ Circular Interior stack diameter (inches): o Square/rectangle Interior stack width (inches): o Other (describe): 0 Upward with obstructing raincap 30 Interior stack depth (inches): Section 5 - Fuel Consumption Information Design Input Rate (MMBTU/hr) Actual Annual Fuel Use5 (Specify Units) Requested Annual Permit Limitb (Specify Units) 16.5 140.3 MMSCF/yr From what year is the actual annual fuel use data? Fuel consumption values entered above are for: 0 Each Boiler 0 All Boilers N/A Indicate the type(s) of fuel used: o Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) El Field Natural Gas Heating value: 1030 BTU/SCF o Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) o Propane (assumed fuel heating value of 2,300 BTU/SCF) o Coal Heating value: BTU/Lb Ash content: Sulfur Content: ❑ Other (describe): Heating value (give units): 5 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. 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 7 If fuel heating value is different than the listed assumed value, please provide this information in the "Other" field. Form APCD-220 - Boiler APEN - Revision 7/2018 COLOR aao 3 otc Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Criteria Pollutant Emissions Information Attach all emissions calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? 0 Yes 0 No If yes, please describe the control equipment AND state the overall control efficiency (% reduction): Pollutant Control Equipment Description Overall Control' Efficiency (% reduction in emissions) TSP (PM) PM10 PM2.5 sax NO. CO VOC From what year is the following reported actual annual emissions data? 2019 Use the following tables to report the criteria pollutant emissions from source: (Use the data reported in Section 5 to calculate these emissions.) Primary Fuel Type (natural gas, #2 diesel, etc.) Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg., etc.) Uncontrolled (tons/year) Controlled8 (tons/year) uesfed Annual Permit Emission Limit(s)6 Uncontrolled (tans/year) Controlled (tons/year) Natural Gas TSP (PM) 7.6 AP -42 0.53 PM10 7.6 AP -42 0.53 PM2.5 7.6 AP -42 0.53 SOX 0.6 AP -42 NO. 50 AP -42 CO 41 Mfg. 0.04 )59 2.89 VOC 5.5 AP -42 0.39 0 Check this box if multiple fuels were NOT fired 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 pollutant emissions table below: Secondary Fuel Type (#2 diesel, waste oil, etc.) Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg., etc.) ActualAnnual Emissions uested Annual Permit- mission Limit(s)6 Uncontrolled (tons/year) Controlled$, (tons/year) Uncontrolled (tons/year) Controlled (tons/year) TSP (PM) PM10 PM2.5 SOX NO. CO VOC 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 7/2018 COLORADO 4 � ntc I Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] 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: Uncontrolled (tons/year) Controlled8 (tons/year) Uncontrolled (tons/year) Controlled (tons/year) TSP (PM) PMio PM2.5 SOX NO. CO VOC 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. 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: Primary Fuel Type (natural gas, #2 diesel, etc.) Natural Gas CAS Number Chemical Name Overall Control Efficiency Uncontrolled Emission Factor (specify units) Emission Factor Source . (AP -42, Mfg., etc) Uncontrolled Actual Emissions (lbs/year) Controlled d Actual Emissions8 (lbs/year) n -Hexane 1.8 Ib/MMSCF AP -42 253 ❑✓ Check this box if multiple fuels were NOT fired during this reporting period and skip to Section 8. If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total non -criteria pollutant (HAP) emissions table below: Secondary Fuel Type (#2 diesel, waste oil, etc.) CAS Number Chemical Name Overall Control Efficiency Uncontrolled Emission Factor (specify units) Emission Factor Source (AP -42, Mfg .; etc) . Uncontrolled Actual Emissions (lbs/year) Controlled Actual Emissions (lbs/year) 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 7/2018 COLORAriO 5 I hilr:�o« Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] If multiple fuels were fired during this reporting period, use the following table to report the TOTAL non -criteria pollutant (HAP) 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 7: CAS Number Chemical Name Actual Annual t + '� "r 7 a� o ��'�" �{ �� Emissions Uncontrolled (tons/year) Controlled8 (tons/year) 8 Annual emissions 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. Signature'of Legally Authorized Person (not a vendor or consultant) Nick Holland Name (please print) Director EHS&R Title Check the appropriate box if you want: 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 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 $191.13 to: 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.ov/cdphe/apcd Form APCD-22O - Boiler APEN - Revision 7/2018 COLOR 4D0 6 AV 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. print shop, 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 are 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: AIRS ID Number: 1 � ettp74 ' O( ( [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name: Site Name: Site Location: Cureton Front Range LLC Hookside Gas Plant SE Sec. 30, T9N, R60W Mailing Address: (include Zip Code) 518 17th Street, Suite 650 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick.holland@curetonmidsream.com 1 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the]aget villed. Form APCD-220 - Boiler APEN - Revision 7/2018 COLOR ADO 1 Htan. ;, adTbF w 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 -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment 0 Change company name3 ❑ Change permit limit O Transfer of ownership's OR - ▪ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - o 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: ❑ Add point to existing permit o Other (describe below) 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Amine Reboiler Manufacturer: TBD Model No.: TBD Serial No.: TBD Company equipment Identification No. (optional): For existing sources, operation began on: For new, modified, or reconstructed sources, the projected start-up date is: HTR5 TBD Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: Seasonal use Dec- Mar- June - percentage: Feb: May: Aug: hours/day Are you reporting multiple identical boilers on this APEN? 0 Yes ❑✓ No days/week weeks/year Sept - Nov: 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 7/2018 COLD R ADO 2 txpa,mene etastc. MOM, EnVin nmpm Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit 11 and AIRS ID] Section 4 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 Operator E Stack ID No' Discharge`Height s Above Ground Level (Fe'etj Temp ( F) r x } Flow Rate { (ACF/YI) a r Velocity (ftsec) HTR5 TBD 800 7984 18.8 Indicate the direction of the stack outlet: (check one) ❑✓ Upward O Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑✓ Circular ❑ Square/rectangle Interior stack width (inches): ❑ Other (describe): Interior stack diameter (inches): ❑ Upward with obstructing raincap 36 Interior stack depth (inches): Section 5 - Fuel Consumption Information Design Input Rate (MMBTU/hr) Actual Annual Fuel Use5 (Specify Units) , Requested Annual Permit Limit6 (Specify Units) 55.0 467.8 MMSCF/yr From what year is the actual annual fuel use data? Fuel consumption values entered above are for: O Each Boiler O All Boilers ❑� N/A Indicate the type(s) of fuel used: ❑ Pipeline Natural Gas D Field Natural Gas ❑ Ultra Low Sulfur Diesel O Propane ❑ Coal ❑ Other (describe): (assumed fuel heating value of 1,020 BTU/SCF) Heating value: 1030 BTU/SCF (assumed fuel heating value of 138,000 BTU/gallon) (assumed fuel heating value of 2,300 BTU/SCF) Heating value: BTU/lb Ash content: Sulfur Content: Heating value (give units): 5 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. 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 7 If fuel heating value is different than the listed assumed value, please provide this information in the "Other" field. Form APCD-220 - Boiler APEN - Revision 7/2018 COLORADO 3 I I H�wL�t .• bbFsNxonix'.oM Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Criteria Pollutant Emissions Information Attach all emissions calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? O Yes ❑✓ No If yes, please describe the control equipment AND state the overall control efficiency (% reduction): Pollutant Control Equipment Description Overall Control Efficiency (% reduction in emissions) TSP (PM) PM10 PM2.s SOX NO. CO VOC From what year is the following reported actual annual emissions data? 2019 Use the following tables to report the criteria pollutant emissions from source: (Use the data reported in Section 5 to calculate these emissions.) Primary Fuel Type (natural gas, #2 diesel, etc.) Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg., etc.) Controller's (tons/year) uested Annual Pi Emission Limits; Uncontrolled (tons/year) Uncontrolled (tons/ year) Controlled (tons/year) Natural Gas TSP (PM) 7.6 AP -42 1.78 PMio 7.6 AP -42 1.78 PM2.5 7.6 AP -42 1.78 SOX 0.6 AP -42 0.14 NO. 50 AP -42 1141 CO 41 Mfg. 9.64 VOC 5.5 AP -42 1.29 ❑✓ Check this box if multiple fuels were NOT fired 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 pollutant emissions table below: Secondary Fuel Type (#2 diesel, waste oil, etc.) Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg., etc.) Actual Annual Emissions Requested Annual . EmissionsLlimit . 1s)6 (s)e' tons/ ( year ) $_ (tons/year) Uncontrolled Controlled Uncontrolled Controlled (tons/year) (tons/year) TSP (PM) PM10 PM2.s SO. NO. CO VOC 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 Boiler APEN - Revision 7/2018 COLORADO HasYfi 6 Envioruxem Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] 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 Ac ual�Annual Emissions $$ , y „E;q..Emission Requested Annual Permit L1mlt(s) Uncontrolled (tons/year) Controlled8` (tons/year) - Uncontrolled` (tons/year) ' Controlled (tons/year) TSP (PM) PM10 PM2.5 SOX NO,, CO VOC 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. 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: Primary Fuel Type (natural gas, #2 diesel, etc.) Natural Gas CAS Number Chemical Name Overall Control Efficiency Uncontrolled Emission Factor (specify units) . Emission Factor Source (AP -42, Mfg., etc) Uncontrolled Actual Emissions ((bs/year) Controlled Actual Emissions8 (lbs/year) ) n -Hexane 1.8 Ib/MMSCF AP -42 842 0 Check this box if multiple fuels were NOT fired during this reporting period and skip to Section 8. If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total non -criteria pollutant (HAP) emissions table below: Secondary Fuel Type (#2 diesel, waste oil, etc.) CAS Number Chemical Name Overall Control Efficiency Uncontrolled Emission Factor (specify units) Emission Factor Source (AP -42, Mfg., etc.) Uncontrolled Actual Emissions ' (lbs/year) ( y ) Controlled Actual Emissions8 (lbs/year) 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 7/2018 VCOLORADO Permit Number: AIRS ID Number: / / [Leave blank unless APCD has already assigned a permit tt and AIRS ID] If multiple fuels were fired during this reporting period, use the following table to report the TOTAL non -criteria pollutant (HAP) 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 7: Uncontrolled (tons/year) Controlled8 (tons/year) 8 Annual emissions 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. Signature of Legally Authorized Person (not a vendor or consultant) Date Nick Holland Director EHS&R Name (please print) Title Check the appropriate box if you want: ❑✓ Draft permit prior to public notice El Draft of the permit prior to issuance (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 $191.13 to: 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: httos://www.colorado.gov/cdphe/apcd Form APCD-220 - Boiler APEN - Revision 7/2018 COLORADO 6 Hof Boiler APEN - Form APCD-220 ?2 `' 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. print shop, 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.Qov/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 are 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: AIRS ID 143W60)0E/ Number: IZ3 /AO 24 612 - [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Cureton Front Range LLC Site Name: Hookside Gas Plant Site Location: SE Sec. 30, T9N, R60W Mailing Address: (include Zip Code) 518 17th Street, Suite 650 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick.holland@curetonmidsream.com I 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. 332384 Form APCD-220 - Boiler APEN - Revision 7/2018 COLORADO 1 I • iii' er H�x.�itt:E£nruo:unnri Permit Number: AIRS ID Number: / [Leave blank unless APCD has already assigned a permit 11 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 0 Change company name3 0 Add point to existing permit ❑ Change permit limit 0 Transfer of ownership4 0 Other (describe below) - OR ❑ APEN submittal for update only (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 Et Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Stabilizer Heater Manufacturer: TBD Model No.: Company equipment Identification No. (optional): For existing sources, operation began on: For new, modified, or reconstructed sources, the projected start-up date is: TBD HTR6 Serial No.: TBD TBD 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: Seasonal use Dec- Mar- June - percentage: Feb: May: Aug: hours/day Are you reporting multiple identical boilers on this APEN? 0 Yes 0 No days/week weeks/year Sept - Nov: 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 7/2018 2 IAVCOLOR ADD ;trxrzz.--„,..;„ Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 4t Operator Stack ID No Discharge, Height Above Ground Level :- (FeeE) Temp = ("IF) Flow Rate (ACFM) Velocity (ft/sec HTR6 TBD 800 2613 6.2 Indicate the direction of the stack outlet: (check one) ❑f Upward O Horizontal ❑ Downward o Other (describe): Indicate the stack opening and size: (check one) Q Circular Interior stack diameter (inches): ❑ Square/rectangle Interior stack width (inches): o Other (describe): 0 Upward with obstructing raincap 36 Interior stack depth (inches): Section 5 - Fuel Consumption Information Design Input Rate (MMBTUIhr) Actual Annual Fuel .Use 5 (Specify Units) Requested Annual Permit Limit6 (Specify Units) 18.0 153.1 MMSCF/yr From what year is the actual annual fuel use data? Fuel consumption values entered above are for: ❑ Each Boiler 0 All Boilers ❑✓ N/A Indicate the type(s) of fuel used: o Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑✓ Field Natural Gas Heating value: 1030 BTU/SCF ❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) o Propane (assumed fuel heating value of 2,300 BTU/SCF) ❑ Coal Heating value: BTU/lb Ash content: Sulfur Content: o Other (describe): Heating value (give units): 5 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. 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 7 If fuel heating value is different than the listed assumed value, please provide this information in the "Other" field. Form APCD-220 - Boiler APEN - Revision 7/2018 COLORADO 3 I rL+< Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Criteria Pollutant Emissions Information Attach all emissions calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? O Yes ❑✓ No If yes, please describe the control equipment AND state the overall control efficiency 1%reduc Pollutant Control Equipment Description Overall Control Efficiency (% reduction in emissions) TSP (PM) PM10 PM2.5 Sox NOx CO VOC From what year is the following reported actual annual emissions data? 2019 Use the following tables to report the criteria pollutant emissions from source: (Use the data reported in Section 5 to calculate these emissions.) Primary Fuel Type (natural gas, #2 diesel, etc.) Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg., etc.) Actual Annual Emissions• - Uncontrolled (tons/year) Controlled8 (tons/year) Uncontrolled (tons/year) Controlled (tons/year) Natural Gas TSP (PM) 7.6 AP -42 0.58 PM10 7.6 AP -42 0.58 PM2.s 7.6 AP -42 0.58 SO. 0.6 AP -42 0.05 NOx 50 AP -42 CO 41 Mfg. 3.15 VOC 5.5 AP -42 0.42 ❑✓ Check this box if multiple fuels were NOT fired 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 pollutant emissions table below: Secondary Fuel Type. (#2 diesel, waste oil, etc.) Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg., etc.) Uncontrolled (tons/year) mission Controlled8 (tons/year) Uncontrolled (tons/year) Controlled (tons/year) TSP (PM) PMio PM2.s SO. NO. CO` VOC 6 Requested values will become permit limitations. Requested Limit(s) should consider future process growth. 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, Leave blank. Form APCD-220 - Boiler APEN - Revision 7/2018 ].COLOR ADO 4IF« cona�mnm Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] 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 r` � ' Actual Annual ` Emissions ' ��RequestedAnnualPermit Emission Limtt(b Uncontrolled (tons/year) Controlled8 (tons/year) Uncontrolled ' (tons/year) - Controlled (tons/year) TSP (PM) PM10 PM2.5 SOx NOx CO VOC 6 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Section 7 - Non -Criteria Pollutant Emissions Information Does the emissions source have any uncontrolled actual emissions of non -criteria ❑✓ Yes 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: Primary Fuel Type (natural gas, #2 diesel, etc.) Natural Gas CAS Number Chemical Name Overall Control Efficiency Uncontrolled Emission Factor (specify units) Emission Factor Source (AP 42, Mfg., etc) Uncontrolled Actual Emissions (!bs/year) Controlled Actual Emissions$ (lbs/year) n -Hexane 1.8 lb/MMSCF AP -42 276 ❑ No ❑✓ Check this box if multiple fuels were NOT fired during this reporting period and skip to Section 8. If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total non -criteria ooliutant (HAP) emissions table below: Secondary Fuel Type (#2 diesel, waste oil, etc.) CAS Number Chemical Name Overall Control Efficiency Uncontrolled Emission Factor (specify units) Emission Factor Source (AP -42, Mfg., etc.) Uncontrolled Actual Emissions (lbs/year) ( y ) Controlled Actual Emissions (lbs/year) 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 7/2018 COLORADO 5 I •i .--116 ti*d1ERY1SON1iH.1 Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit 4 and AIRS ID] If multiple fuels were fired during this reporting period, use the following table to report the TOTAL non -criteria pollutant (HAP) emissions from the source. Values listed below should be the sum of the reported emissions from the rximary and secondary fuels' emissions tables in this Section 7: CAS Number Chemical Name ctual Annual r Emissions}� -' 'SP=,5 Uncontrolled (tons/year) Controlled8 (tons/year) 8 Annual emissions 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 informatioontained herein and information submitted with this application is complete, true, and correct. Signature of Legally Authorized Person (not a vendor or consultant) Nick Holland Name (please print) //is/f 'Da e Director EHS&R Title Check the appropriate box if you want: ❑� 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 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 $191.13 to: 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-220 - Boiler APEN - Revision 7/2018 COLORADO 6 I AV �oe� H�hb£nv�ranw�uni Natural Gas Venting APEN - Form APCD-211 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 Natural Gas Venting only. Natural Gas Venting includes emissions from gas/liquid separators, well head casing, pneumatic pumps, blowdown events, among other events. If your emission unit does not fall into this category, there may be a more specific APEN for your source. 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.cotorado.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: 1 q wgQcg f AIRS ID Number: /AZl,/ Did [Leave blank unless APCD has already assigned a permit # and AIRS ID] Company equipment Identification: Pigging ; a ,1AA12 2 2Q' Apco [Provide Facility Equipment ID to identify how this equipment is referenced within your organization] Section 1 - Administrative Information Company Name': Cureton Front Range LLC Site Name: Hookside Gas Plant Site Location: SE, Sec3019, T9N, R60W Mailing Address: (Include Zip Code) 518 17th Street, Suite 650 Denver, CO 80202 E -Mail Address2: nick.holland@curetonmidstream.com Site Location County: Weld NAICS or SIC Code: 1321 Permit Contact: Nick Holland Phone Number: 303-324-5967 '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. 2 Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided. Form APCD-211 - Natural Gas Venting APEN - Rev 03/2017 3238 ,,i- KWn 2�. COLORADO Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2- Requested Action O NEW permit OR newly -reported emission source -OR - ❑ MODIFICATION to existing permit (check each box below that applies) O Change fuel or equipment 0 Change company name 0 Add point to existing permit O Change permit limit 0 Transfer of ownership3 ❑ Other (describe below) -OR- ❑ APEN submittal for update only (Please note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - El Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info £t Notes: 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: one 10" and one 16" Four pigging receivers, one 6", one 8", For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: / / TBD / / 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 weeks/year Will this equipment be operated in any NAAQS nonattainment area Is this equipment located at a stationary source that is considered a Major Source of (HAP) Emissions O Yes 0 No ❑ Yes 0 No Form APCD-211 -Natural Gas Venting APEN - Rev 03/2017 V. COLORADO 2 I Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Process Equipment Information ❑ Gas/Liquid Separator ❑ Well Head Casing ❑ Pneumatic Pump Make: Model: ❑ Compressor Rod Packing Make: Model: ❑ Blowdown Events # of Events/year: ❑r Other Description: Depressurization of receiver to remove pig Serial #: Capacity: Gal/min # of Pistons: Leak Rate: Scf/hr/pist Volume per event: MMscf/event If you are requesting uncontrolled VOC emissions greater than 100 tpy for a Gas/Liquid Separator you must use Natural Gas Venting as a process parameter. Are requested uncontrolled VOC emissions greater than 100 tpy? O Yes Natural Gas Venting Process Parameters4: Liquid Throughput Process Parameters4: ❑r No Maximum Vent Rate: 449 SCF/hr Vent Gas Heating Value: BTU/SCF Requested: 0.275 MMSCF/year Actual: MMSCF/year -OR- Requested: Bbl/yr Actual: Bbl/yr 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth Process Properties: Molecular Weight: VOC (mole %) VOC (Weight %) 25.03 Benzene (mole %) Benzene (Weight %) 0.0016 Toluene (mole %) Toluene (Weight %) 0.0130 Ethylbenzene (mole %) Ethylbenzene (Weight %) 0.0021 Xylene (mole %) Xylene (Weight %) 0.0032 n -Hexane (mole %) n -Hexane (Weight %) 0.2386 2,2,4-Trimethylpentane (mole %) 2,2,4-Trimethylpentane (Weight %) 0.0173 Additional Required Information: ❑✓ Attach a representative gas analysis (including BTEX ft n -Hexane, temperature, and pressure) Attach a representative pressurized extended liquids analysis (including BTEX it n -Hexane, temperature, and pressure) Form APCD-211 -Natural Gas Venting APEN - Rev 03/2017 3 I ACOLORADO v O Upward ❑ Horizontal Permit Number: AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 Operator Stack ID No Discharge Height Above Ground Level (Feet) Temp (F) Flow,, Rate (ACFM) Velocity (ft/sec) Pigging 5 ambient Indicate the direction, of the stack outlet: (check one) ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) El Circular Interior stack diameter (inches): ❑ Other (describe): ❑ Upward with obstructing raincap Section 6 - Control Device Information O VRU: Pollutants Controlled: Size: Make/Model: Requested Control Efficiency % VRU Downtime or Bypassed ❑ Combustion Device: Pollutants Controlled: Rating: Type: Requested Control Efficiency: Manufacturer Guaranteed Control Efficiency Minimum Temperature: MMBtu/hr Make/Model: Waste Gas Heat Content Constant Pilot Light: 0 Yes 0 No Pilot burner Rating Btu/scf MMBtu/hr O Other: Pollutants Controlled: Description: Control Efficiency Requested Form APCD-211 -Natural Gas Venting APEN - Rev 03/2017 COLORADO 4, #t?�fl�Y P:.vteMmgn� Permit Number: AIRS ID Number: / / [Leave blank unless APCD has already assigned a permit /! and AIRS ID] 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 O No If yes, please describe the control equipment AND state the overall control efficiency (% reduction): Pollutant Control Equipment Description Overall Requested Control Efficiency (% reduction in emissions) PM SOX NOX VOC CO HAPs Other: From what year is the following reported actual annual emissions data? 2019 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 Emission Factor Units Emission Factor Source (AP -42, Mfg. etc) Actual Annual Emissions: Requested Annual Permit Emission Limit(s)s , 4, Uncontrolled (Tons/year) Controlled6 (Tons/year) Uncontrolled (Tons/year) Controlled (Tons/year) PM SOX NOX VOC 0.0147 Ib/scf mass balance 2.03 CO Benzene Toluene Ethylbenzene Xylenes n -Hexane 2,2,4- Trimethylpentane Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-211 -Natural Gas Venting APEN - Rev 03/2017 COLORADO 5I 47 Permit Number: AIRS ID Number: / / [Leave blank unless APCD has already assigned a permit it and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. Signature of Legally Authorized Person (not a vendor or consultant) Nick Holland Name (please print) DatDat Director of EHS&R Title // 7 Check the appropriate box to request a copy of the: Draft permit prior to issuance 0 Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) 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 Make check payable to: Colorado Department of Public Health and Environment Telephone: (303) 692-3150 Form APCD-211 -Nature! Gas Venting APEN - Rev 03/2017 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.cotorado.gov/cdphe/apcd COLORADO 6I NWAb E;.vvamm�nt JAN 2 2 "t`'' 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: /9 u/e00g/ AIRS ID Number: fZ3 /A.®4I/ IJ(c [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name: Cureton Front Range LLC Site Name: Hookside Gas Plant Site Location: SE, Sec. 30, T9N, R60W Mailing Address: 518 17th Street, Suite 650 (include Zip Code) Denver, CO 80202 Permit Contact: Nick Holland E -Mail Address2: nick.holland@curetonmidstream.com Site Location Weld County: NAICS or SIC Code: 1321 Phone Number: 303-324-5967 1 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 392387 HAY COLORADO oep.Rmu.t at tt6„ttinu� ..b „ate Permit Number: AIRS ID Number: / / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2- Requested Action 0 NEW permit OR newly -reported emission source (check one below) -OR - ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change process or equipment 0 Change company name ❑ Add point to existing permit ❑ Change permit limit 0 Transfer of ownership3 ❑ Other (describe below) - OR • APEN submittal for update only (Blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - • APEN submittal for permit exempt/grandfathered source O Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Ft Notes: 3 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Information For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TBD El Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source hours/day days/week weeks/year Operation: Facility Type: ❑ Well Production Facility4 ❑ Natural Gas Compressor Station4 ✓❑ Natural Gas Processing Plant4 ❑ Other (describe): 4 When selecting the facility type, refer to definitions in Colorado Regulation No. 7, Section XVII. Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision 7/2017 COLORADO Z I a 'i uV:�ycrtmen�ottvuuc _ .'rA+1RbE�VHCt11M14{ Permit Number: AIRS ID Number: / / [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? TBD Will this equipment be operated in any NAAQS nonattainment area?5 0 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 Yes No located at this facility? ❑ ❑✓ Is this equipment subject to 40 CFR Part 60, Subpart KKK? 0 Yes 0 No Is this equipment subject to 40 CFR Part 60, Subpart OOOO? 0 Yes No Is this equipment subject to 40 CFR Part 60, Subpart OOOOa? El Yes 0 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? 0 Yes ❑✓ No Is this equipment subject to Colorado Regulation No. 7, Section XVII.B.3? 0 Yes ❑✓ No 5 See http://www.cotorado.eov/cdphe/state-implementation-plans-sips for which areas are designated as attainment/non- attainment. Section 5 - Stream Constituents ❑r 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. Stream VOC (wt %) Benzene (wt %) Toluene (wt %) Ethylbenzene (wt %) Xylene (wt %) n -Hexane (wt %) 2,2,4 Trimethylpentane (wt %) Gas g.G.- 0.0016 0.0130 0.0021 0.0032 0.2386 0.0173 Heavy Oil (or Heavy Liquid) 1 00 2 2 2 2 2 0 Light Oil (or Light Liquid) 100 2 2 2 2 2 0 Water/Oil <I% Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision 7/2017 31 AY COLORADO Ormmal,Nic Me0ThiFV*M.IM Permit Number: AIRS ID Number: / / [Leave blank unless APO) has already assigned a permit # and AIRS ID] Section 6 - Geographical Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 Attach a topographic site map showing location Section 7 - Leak Detection and Repair (LDAR) and Control Information Check the appropriate boxes to identify the LDAR program conducted at this site: 0 LDAR per 40 CFR Part 60, Subpart KKK 0 Monthly Monitoring - Control: 88% gas valve, 76% light liquid valve, 68% light liquid pump ❑ Quarterly Monitoring - Control: 70% gas valve, 61% light liquid valve, 45% light liquid pump 0 LDAR per 40 CFR Part 60, Subpart OOOO/OOOOa 0 Monthly Monitoring - Control: 96% gas valve, 95% light liquid valve, 88% light liquid pump, 81% connectors 0 LDAR per Colorado Regulation No. 7, Section XVII.F 0 Other6: 0 No LDAR Program 6 Attach other supplemental plan to APEN form if needed. Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision 7/2017 Ay COLORADO 4 I Permit Number: AIRS ID Number: / / [Leave blank unless APCD has already assigned a permit ti 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. ❑✓ Table 2-4 was used to estimate emissions'. ❑ Table 2-8 (< 10,000ppmv) was used to estimate emissions'. 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: Service Equipment Type Connectors Flanges Open -Ended Lines Pump Seals Valves Other9 Gas Count8 4799 2337 7 2,-'2).-4- 171 Emission Factor Units Heavy Oil (or Heavy Liquid) Count8 2136 1086 46 1099 51 Emission Factor Units Light Oil (or Light Liquid) Count8 2776 1526 9 49 1535 56 Emission Factor Units Water/Oil Count8 Emission Factor Units ' 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 COLD RADO mm�.m orwwc Permit Number: AIRS ID Number: / / [Leave blank unless APED has already assigned a permit #t and AIRS ID] Section 9 - Criteria and Non -Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. 2019 From what year is the following reported actual annual emissions data? Use the following table to report the criteria pollutant emissions and non -criteria pollutant (HAP) emissions from source: Use the data reported in Section 8 to calculate these emissions. Chemical Name CAS Number Actual Annual Emissions Requested Annual Permit Emission Limit(s) Uncontrolled (tons/year) Controlled10 (tons/year) Uncontrolled (tons/year) Controlledl1 (tons/year) VOC qI, II )C6, C Does the emissions source have any actual emissions of individual non -criteria pollutants (e.g. HAP- hazardous air pollutant) emissions equal to or greater than 250 ® Yes ❑ No lbs/year? f ves, use the following table to report the non -criteria pollutant (HAP) emissions from source: Chemical Name CAS Number Actual Annual Emissions Requested Annual Permit Emission Limit(s) Uncontrolled (lbs/year) Controlled9 (lbs/year) Uncontrolled (lbs/year) Controlled10 (lbs/year) Benzene 71432 240(.0 -1)i`6 Toluene 108883 P -17`b y 60, Ethylbenzene 100414 ?-'4.c) 97 .5°N Xylene 1330207 2 a l ',Al n -Hexane 110543 Ybb% 5OD- 2,2,4 Trimethvlpentane 540841 Other: 10 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. 11 Requested values will become permit limitations. Requested limit(s) should consider future process growth, component count variability, and gas composition variability. Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision 7/2017 COLORADO 61Th Permit Number: AIRS ID Number: / / [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 /) Dat Signature of Legally Authorized Person (not a vendor or consultant) Nick Holland Director of EHS&R Name (print) Title Check the appropriate box to request a copy of the: ❑✓ Draft permit prior to issuance ❑✓ 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-B 1 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 Ally COLORADO 7 I , Draw 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. Incomplete APENs will be rejected and will require re -submittal. Your APEN will be rejected if it is filled out incorrectly, is missing information, or lacks payment for the filing fee. The re -submittal will require payment for a new filing fee. There may be a more specific APEN for your source (e.g. boiler, mining operations, engines, etc.). A list of all available APEN forms can be found 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: W EV'UJO ( Pcr LeSrl AIRS ID Number: 123 /A020/ of 7 [Leave blank unless APCD has already assigned a permit if and AIRS ID] Section 1 - Administrative Information Company Name: Site Name: Cureton Front Range LLC Hookside Gas Plant Site Location: SE Sec. 30, T9N, R60W Mailing Address: 518 17th Street, Suite 1405 (Include Zip Code) Portable Source Home Base: Denver, CO 80202 Site Location WeIA ld County: NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick.holland@curetonmidstream.com 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 the APCD via e-mail to the address provided. 399236 Form APCD-200 - General APEN - Revision 3/2019 COLORADO 1 I ns�puEr n.r + Permit Number: AIRS ID Number: 123 /A020/ [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 O PORTABLE source -OR- ❑ MODIFICATION to existing permit (check each box below that applies) o Change fuel or equipment 0 Change company name3 0 Add point to existing permit ❑ Change permit limit 0 Transfer of ownership' 0 Other (describe below) - OR - O APEN submittal for update only (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 Et Notes: HAP reportable only 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Methanol Tank Manufacturer: TBD Model No.: TBD Company equipment Identification No. (optional): For existing sources, operation began on: TK-7 Serial No.: TBD For new 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: Form APCD-200 - General APEN - Revision 3/2019 days/week weeks/year Jun -Aug: Sep -Nov: COLORADO 2 c w ,rax,, of Ptt c Permit Number: AIRS ID Number: 123 /A020/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Processing/Manufacturing Information Et Material Use O Check box if this information is not applicable to source or process From what year is the actual annual amount? 2019 Description Design Process Rate (Specify Units) Actual Annual Amount (Specify Units) Requested Annual Permit Limits (Specify Units) Material Consumption: Finished Product(s): Methanol NA 8872.4 bbl/yr 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 ❑ 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. Operator Stack ID No. Discharge Height Above Ground Level (Feet) Temp. ('F) Flow Rate (ACFM) Velocity (ft/sec) TK-7 25 Amb. <0.01 <0.01 Indicate the direction of the'stack outlet: (check one) ❑✓ Upward O Horizontal O Downward O Other (describe): Indicate the stack opening and size: (check one) O Upward with obstructing raincap ❑✓ Circular Interior stack diameter (inches): -2 ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): Form APCD-200 - General APEN - Revision 3/2019 COLORADO 3 I Permit Number: AIRS ID Number: 1 23 / A020 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Combustion Equipment a 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 Limits (Specify Units) From what year is the actual annua fuel use data? Indicate the type 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) o Coal Heating value: BTU/lb Ash content: Sulfur content: ❑ Other (describe): Heating value (give units): 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 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? ❑ Yes 0 No If yes, describe the control equipment AND state the overall control efficiency (% reduction): Pollutant Control Equipment Description Overall Collection Efficiency Overall Control Efficiency (% reduction in emissions) TSP (PM) PM10 PM2.5 SOX NOx CO VOC Other: COLORADO Form APCD-200 - General APEN - Revision 3/2019 Permit Number: AIRS ID Number: 123 / A020 I [Leave blank unless APCD has already assigned a permit # and AIRS ID] From what year is the following reported actual annual emissions data? 2019 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.) Actual AnnualEmissions Requested Annual Permit Emission Limit(s)5 Uncontrolled (tons/year) Controlled? (tons/year) Uncontrolled (tons/year) Controlled (tons/year) TSP (PM) PM10 PM2.5 SOX NO), CO VOC Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 7 Annual emissions 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) equal to or greater than 250 lbs/year? ✓❑ Yes ❑ No following table to report the non -criteria pollutant (HAP) emissions from source: CAS Number Chemical Name Overall Control Efficiency Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg., etc.) Uncontrolled Actual Emissions (lbs/year) Controlled Actual Emissions? (lbs/year) 67561 Methanol 0% 0.1124 lb/bbl EPA Tanks 997 997 7 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-200 - General APEN - Revision 3/2019 COLORADO 5 I � �,al Pubtic Permit Number: AIRS ID Number: 123 / A020 / [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. Nicholas Holland Digitally signed by Nicholas Holland Date: 2019.05.07 21:31:42 -06'00' 5/7/2019 Signature of Legally Authorized Person (not a vendor or consultant) Date Nick Holland Director EHS&R Name (print) Title Check the appropriate box to request a copy of the: E✓ Draft permit prior to issuance �✓ 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 $191.13 to: 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.Rov/cdphe/apcd Form APCD-2OO - General APEN - Revision 3/2019 6 AI /j COLORADO Hydrocarbon Liquid Loading APEN Form APCD-208 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 hydrocarbon liquid loading only. If your emission unit does not fall into this category, there may be a more specific APEN for your source (e.g. amine sweetening unit, glycol dehydration unit, condensate storage tanks, 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. 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: ( l W 5008 I AIRS ID Number: 123 / A020 I O/g [Leave blank unless APCD has already assigned a permit A and AIRS ID] Section 1 - Administrative Information Company Name': Cureton Front Range LLC Site Name: Hookside Site Location: SE Sec. 30, T9N, R60W Mailing Address: (Anctude Zip Code) 518 17th Street, Suite 1405 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick.holland@curetonmidstream.com 1 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 the APCD via e-mail to the address provided. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 399237 QVT,COLoRAoa Permit Number: AIRS ID Number: 1 23 / A020 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action p NEW permit OR newly -reported emission source ❑✓ Request coverage under construction permit 0 Request coverage under General Permit GP07 If General Permit coverage is requested, the General Permit registration fee of $312.50 must be submitted along with the APEN filing fee. -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment 0 Change company name3 ❑ Change permit limit ❑ Transfer of ownership4 0 Other (describe below) OR - ▪ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - El Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info £t Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Pressurized loadout of NGL Company equipment Identification No. (optional): LOAD4 For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TBD Will this equipment be operated in any NAAQS nonattainment area? Yes No • GI Is this equipment located at a stationary source that is considered a Major Source of (HAP) emissions? Yes No • GI Does this source load gasoline into transport vehicles? Yes No • p Is this source located at an oil and gas exploration and production site? Yes No • Fl If yes: Does this source load less than 10,000 gallons of crude oil per day on an annual average? Yes No • • Does this source splash fill less than 6750 bbl of condensate per year? Yes No ■ • Does this source submerge fill less than 16308 bbl of condensate per year? Yes No • ■ Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 A rr COLORADO 2 11,artr.em PRE, COLORADO Permit Number: AIRS ID Number: 123 / A020 I [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Process Equipment Information Product Loaded: 0 Condensate 0 Crude Oil ❑✓ Other: NGL L If this APEN is being filed for vapors displaced from cargo carrier, complete the following: Requested Volume Loaded5: bbl/year This product is loaded from tanks at this facility into: (e.g. "rail tank cars" or "tank trucks") Actual Volume Loaded: bbl/year If site specific emission factor is used to calculate emissions, complete the following: Saturation Factor: Average temperature of bulk liquid loading: °F True Vapor Pressure: Psia @ 60 °F Molecular weight of displaced vapors: lb/lb-mol If this APEN is being filed for vapors displaced from pressurized loading lines, complete the following: Requested Volume Loaded5: 730,000 bbl/year Actual Volume Loaded: bbl/year Product Density: 29.35 lb/ft3 Load Line Volume: 0.0736 ft3/truckload Vapor Recovery Line Volume: 0.0436 ft3/truckload 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COLORADO 3 I Ifeiilhb �noliaNwM Permit Number: AIRS ID Number: 123 / A020 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 Operator p Stack ID No. Discharge Height Above Ground Level (feet) Temp. (?F) Flow Rate (ACFM) Velocity (ft/sec) LOAD4 5 amb. variable variable Indicate the direction of the stack outlet: (check one) ❑ Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) O Circular Interior stack diameter (inches): ❑ Other (describe): O Upward with obstructing raincap Section 6 - Control Device Information Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. O Loading occurs using a vapor balance system: Requested Control Efficiency: ❑ Combustion Device: Used for control of: Rating: Type: MMBtu/hr h r Make/Model: Requested Control Efficiency: % Manufacturer Guaranteed Control Efficiency: Minimum Temperature: °F Waste Gas Heat Content: Constant Pilot Light: O Yes O No Pilot Burner Rating: Btu/scf MMBtu/hr O Other: Pollutants Controlled: Description: Requested Control Efficiency: Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COLORADO 4 I AT !.:o« Permit Number: AIRS ID Number: 123 / A020 I [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Pollutant Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) PM SOX NO. CO VOC HAPs Other: ❑ Using State Emission Factors (Required for GP07) VOC Benzene n -Hexane ❑ Condensate 0.236 Lbs/BBL 0.00041 Lbs/BBL 0.0036 Lbs/BBL O Crude 0.104 Lbs/BBL 0.00018 Lbs/BBL 0.0016 Lbs/BBL From what year is the following reported actual annual emissions data? 2019 Criteria Pollutant Emissions Inventory Pollutant Emission Factor Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (tons/year) Controlled Emissions6 (tons/year) Uncontrolled Emissions (tons/year) Controlled Emissions (tons/year) PM SOx NO. CO VOC 0.009 lb/bbl Mass Balance 3.32 3.32 Non -Criteria Reportable Pollutant Emissions Inventory Chemical Name Chemical Abstract Service (CAS) Number Emission Factor Actual Annual Emissions Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (pounds/year) Controlled Emissions 6 (pounds/year) Benzene 71432 Toluene 108883 - Ethylbenzene 100414 Xylene 1330207 n -Hexane 110543 2,2,4- Trimethylpentane 540841 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COEOR AOO 5 H.. . _ H.4.0 .7„7,`P,„„„„,I Permit Number: AIRS ID Number: 123 / A020 I [Leave blank unless APCD has already assigned a permit ft and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. If this is a registration for coverage under General Permit GP07, I further certify that this source is and will be operated in full compliance with each condition of General Permit GP07. Nicholas Holland Digitally signed by Nicholas Holland 5/7/2019 Date: 2019.05.07 21:28:01 -06'00' Signature of Legally Authorized Person (not a vendor or consultant) Date Nick Holland Director EHS&R Name (print) Title Check the appropriate box to request a copy of the: ❑✓ Draft permit prior to issuance ❑✓ 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 $191.13 and the General Permit registration fee of $312.50, if applicable, to: 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd COLORADO Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 Hydrocarbon Liquid Loading APEN Form APCD-208 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 hydrocarbon liquid loading only. If your emission unit does not fall into this category, there may be a more specific APEN for your source (e.g. amine sweetening unit, glycol dehydration unit, condensate storage tanks, 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. 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: 19wEop'1 _(IEIVa L MAY 1 3 2019 n,,C D AIRS ID Number: 123 / A020 / £ 1 1 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Cureton Front Range LLC Site Name: Hookside Site Location: SE Sec. 30, T9N, R60W Mailing Address: (include Zip Code) 518 17th Street, Suite 1405 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick.holland@curetonmidstream.com 1 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 the APCD via e-mail to the address provided. COLORADO Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 Permit Number: AIRS ID Number: 123 / A020 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action O NEW permit OR newly -reported emission source ❑✓ Request coverage under construction permit 0 Request coverage under General Permit GP07 If General Permit coverage is requested, the General Permit registration fee of $312.50 must be submitted along with the APEN filing fee. -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment 0 Change company name3 ❑ Change permit limit ❑ Transfer of ownership4 0 Other (describe below) OR- ❑ APEN submittal for update only (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) Additional Info Et Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Loadout of stabilized condensate Company equipment Identification No. (optional): LOAD3 For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TBD Will this equipment be operated in any NAAQS nonattainment area? Yes No • A Is this equipment located at a stationary source that is considered a Major Source of (HAP) emissions? Yes No • GI Does this source load gasoline into transport vehicles? Yes No • ig Is this source located at an oil and gas exploration and production site? Yes No • GI If yes: Does this source load less than 10,000 gallons of crude oil per day on an annual average? Yes No • • Does this source splash fill less than 6750 bbl of condensate per year? Yes No • • Does this source submerge fill less than 16308 bbl of condensate per year? Yes No • • 2 I AV kewtl5l+' �'�u��aPieruM COLORADO Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 Permit Number: AIRS ID Number: 123 / A020 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Process Equipment Information Product Loaded: 0 Condensate O Crude Oil ❑� Other: mixed liquids If this APEN is being filed for vapors displaced from cargo carrier, complete the following: Requested Volume Loaded5: 730,000 bbl/year Actual Volume Loaded: This product is loaded from tanks at this facility into: tank trucks (e.g. "rail tank cars" or "tank trucks") bbl/year If site specific emission factor is used to calculate emissions, complete the following: Saturation Factor: Average temperature of bulk liquid loading: °F True Vapor Pressure: Psia @ 60 °F Molecular weight of displaced vapors: lb/lb-mot If this APEN is being filed for vapors displaced from pressurized loading lines, complete the following: Requested Volume Loaded5: bbl/year Actual Volume Loaded: bbl/year Product Density: lb/ft3 Load Line Volume: ft3/truckload Vapor Recovery Line Volume: ft3/truckload 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Aviv COLORADO Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 Permit Number: AIRS ID Number: 123 / A020/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 Operator Stack ID No. Discharge Height Above Ground Level (feet) Temp. en Flow Rate (ACFM) Velocity (ft/sec)`' Combustor 12 1000 variable variable Indicate the direction of the stack outlet: (check one) O Upward ❑ Horizontal ❑ Downward o Other (describe): Indicate the stack opening and size: (check one) 0 Circular O Other (describe): 0 Upward with obstructing raincap Interior stack diameter (inches): 48 Section 6 - Control Device Information ❑ Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. Loading occurs using a vapor balance system: Requested Control Efficiency: 95 % O Combustion Device: Used for control of: VOC and HAPs Rating: Type: Enclosed Combustor MMBtu/hr Make/Model: TBD Requested Control Efficiency: 95 % Manufacturer Guaranteed Control Efficiency: 98+ Minimum Temperature: NA °F Waste Gas Heat Content: 4059 Btu/scf Constant Pilot Light: 0 Yes 0 No Pilot Burner Rating: 0.2 MMBtu/hr ❑ Other: Pollutants Controlled: Description: Requested Control Efficiency: Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COLORADO 4 I , o«h� Permit Number: AIRS ID Number: 123 I A020 I [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Pollutant Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) PM SOX NO. CO VOC Vapor Balance/Combustor 95% HAPs Vapor Balance/Combustor 95% Other: 0 Using State Emission Factors (Required for GP07) VOC Benzene n -Hexane El Condensate 0.236 Lbs/BBL 0.00041 Lbs/BBL 0.0036 Lbs/BBL ❑ Crude 0.104 Lbs/BBL 0.00018 Lbs/BBL 0.0016 Lbs/BBL From what year is the following reported actual annual emissions data? 2019 Criteria Pollutant Emissions Inventory Pollutant Emission Factor Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (tons/year) Controlled Emissions& (tons/year) Uncontrolled Emissions (tons/year) Controlled Emissions (tons/year) PM SOX NO. CO VOC 0.236 lb/bbl State Default 86.14 4.31 Non -Criteria Reportable Pollutant Emissions Inventory Chemical Name Chemical Abstract Service (CAS) Number Emission Factor Actual Annual Emissions Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (pounds/year) Controlled Emissions6 (pounds/year) Benzene 71432 0.00041 lb/bbl State Default 299 15 Toluene 108883 0.0036 lb/bbl State Default 2628 131 Ethylbenzene 100414 Xylene 1330207 n -Hexane 110543 2,2,4- Trimethylpentane 540841 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COLORD 5 I -M AO � ' HPPnyb �ryulauP�..ienl Permit Number: AIRS ID Number: 123 / A020 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. If this is a registration for coverage under General Permit GP07, I further certify that this source is and will be operated in full compliance with each condition of General Permit GP07. Nicholas Holland Digitally signed by Nicholas Holland Date: 2019.05.07 21:26:40 -06'00' 5/7/2019 Signature of Legally Authorized Person (not a vendor or consultant) Date Nick Holland Director EHS&R Name (print) Title Check the appropriate box to request a copy of the: 0 Draft permit prior to issuance 0 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 $191.13 and the General Permit registration fee of $312.50, if applicable, to: 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: / /www. colorado. gov /cdphe / apcd •COLORADO Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 \ 3 Lrv,,,'' Hydrocarbon Liquid Loading APEN Form APCD-208 Air Pollutant Emission Notice (APEN) and Application for Construction Permit AR 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 hydrocarbon liquid loading only. If your emission unit does not fall into this category, there may be a more specific APEN for your source (e.g. amine sweetening unit, glycol dehydration unit, condensate storage tanks, 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. 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: 16/ VVE- �� gl AIRS ID Number: 123 / A020 / Q 2,93 ,[leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name: Site Name: Cureton Front Range LLC Hookside Site Location: SE Sec. 30, T9N, R60W Mailing Address: (Include Zip code) 518 17th Street, Suite 1405 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick.holland@curetonmidstream.com 1 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 the APCD via e-mail to the address provided. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 399233 A COLORADO te„A indxic 1 H ,naFr.;,ann, Permit Number: AIRS ID Number: 1 23 / A020 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ✓❑ NEW permit OR newly -reported emission source El Request coverage under construction permit ❑ Request coverage under General Permit GP07 If General Permit coverage is requested, the General Permit registration fee of $312.50 must be submitted along with the APEN filing fee. -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment ❑ Change company name3 ❑ Change permit limit ❑ Transfer of ownership' ❑ Other (describe below) -OR- ❑ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - E] Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Et Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Loadout of mixed liquids Company equipment Identification No. (optional): LOAD2 For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TBD Will this equipment be operated in any NAAQS nonattainment area? Yes No • IN Is this equipment located at a stationary source that is considered a Major Source of (HAP) emissions? Yes No • p Does this source load gasoline into transport vehicles? Yes No ■ p Is this source located at an oil and gas exploration and production site? Yes No ■ ig If yes: Does this source load less than 10,000 gallons of crude oil per day on an annual average?: Yes No • ■ Does this source splash fill less than 6750 bbl of condensate per year? Yes No • ■ Does this source submerge fill less than 16308 bbl of condensate per year? Yes No ■ • Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 712018 A COLORADO 2Wi �xarecpartmen, ot fh,bec, Permit Number: AIRS ID Number: 123 / A020 I [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Process Equipment Information Product Loaded: 0 Condensate 0 Crude Oil p Other: mixed liquids If this APEN is being filed for vapors displaced from cargo carrier, complete the following: Requested Volume Loaded5: 78,840 bbl/year Actual Volume Loaded: This product is loaded from tanks at this facility into: tank trucks (e.g. "rail tank cars" or "tank trucks") bbl/year If site specific emission factor is used to calculate emissions, complete the following: Saturation Factor: Average temperature of bulk liquid loading: °F True Vapor Pressure: Psia @ 60 °F Molecular weight of displaced vapors: lb/lb-mol If this APEN is being filed for vapors displaced from pressurized loading lines, complete the following: Requested Volume Loaded5: bbl/year Actual Volume Loaded: bbl/year Product Density: lb/ft3 Load Line Volume: ft3/truckload Vapor Recovery Line Volume: ft3/truckload 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 3 IAy::.COLORADO ,R :COLORADO Permit Number: AIRS ID Number: 123 / A020 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 Operator p Stack ID No.F Discharge Height Above Ground evel feet) Temp. C) Flow Rate (ACFM) Velocity (ft/sec) Combustor 12 1000 variable variable Indicate the direction of the stack outlet: (check one) ❑✓ Upward [] Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) El Circular ❑ Other (describe): ❑ Upward with obstructing raincap Interior stack diameter (inches): 48 Section 6 - Control Device Information ❑ Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. El Loading occurs using a vapor balance system: Requested Control Efficiency: 95 % ❑ Combustion Device: Used for control of: VOC and HAPs Rating: MMBtu/hr Type: Enclosed Combustor Make/Model: TBD Requested Control Efficiency: 95 % Manufacturer Guaranteed Control Efficiency: 98+ Minimum Temperature: NA °F Waste Gas Heat Content: 4059 Btu/scf Constant Pilot Light: 0 Yes 0 No Pilot Burner Rating: 0.2 MMBtu/hr 0 Other: Pollutants Controlled: Description: Requested Control Efficiency: Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COLORADO 4 I e°,of ry.M % t.;.n ..n..t Permit Number: AIRS ID Number: 123 / A020 I [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the rol efficiency (% reduction): Pollutant Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) PM SOX NOx CO VOC Vapor Balance/Combustor 95% HAPs Vapor Balance/Combustor 95% Other: ✓❑ Using State Emission Factors (Required for GP07) VOC Benzene n -Hexane 0 Condensate 0.236 Lbs/BBL 0.00041 Lbs/BBL 0.0036 Lbs/BBL 0 Crude 0.104 Lbs/BBL 0.00018 Lbs/BBL 0.0016 Lbs/BBL From what year is the following reported actual annual emissions data? 201 9 Criteria Pollutant Emissions Inventory Pollutant Emission Factor Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (tons/year) Controlled Emissions6 (tons/year) Uncontrolled Emissions (tons/year) Controlled Emissions (tons/year) PM SOx NOx CO VOC 0.236 lb/bbl State Default 9.30 0.47 Non -Criteria Reportable Pollutant Emissions Inventory Chemical Name Chemical Abstract Service (CAS) Number Emission Factor Actual Annual Emissions Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (pounds/year) Controlled Emissions6 (pounds/year) Benzene 71432 Toluene 108883 0.0036 lb/bbl State Default 284 14 Ethylbenzene 100414 Xylene 1330207 n -Hexane 110543 2,2,4- Trimethylpentane 540841 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 5I 'COLORADO be-part-ma; iEppm a; , H w. Permit Number: AIRS ID Number: 123 / A020 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. If this is a registration for coverage under General Permit GP07, I further certify that this source is and will be operated in full compliance with each condition of General Permit GP07. Nicholas Holland Digitally signed by Nicholas Holland Date: 2019.05.07 21:25:45 -06'00' 5/7/2019 Signature of Legally Authorized Person (not a vendor or consultant) Date Nick Holland Director EHS&R Name (print) Title Check the appropriate box to request a copy of the: ❑✓ Draft permit prior to issuance 0 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 $191.13 and the General Permit registration fee of $312.50, if applicable, to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B 1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: / /www.colorado.gov/cdphe/apcd Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COLORADO 6 I Haeu:yE5rumgi Condensate Storage Tank(s) APEN Form APCD-205 Air Pollutant Emission Notice (APEN) and Application for Construction Permit AR 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 tanks that store condensate associated with oil and gas industry operations. If your emission source does not fall into this category, there may be a more specific APEN available for your source (e.g. crude oil storage tanks, produced water storage tanks, hydrocarbon liquid loading, 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 and associated addendum forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/pacific/cdphe/air-permits. 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: l9wE(Az t AIRS ID Number: 123 / A020 / 624 [Leave blank unless APCD has already assigned a permit ft and AIRS ID] Section 1 - Administrative Information Company Name: Site Name: Cureton Front Range LLC Hookside Gas Plant Site Location: SE Sec. 30, T9N, R60W Mailing Address: (Include Zip Code) 518 17th Street, Suite 1405 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick.holland@curetonmidstream.com 1 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 the APCD via e-mail to the address provided. 399239 Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 1 I AW COLOR ADO Smoot Permit Number: AIRS ID Number: 1 23 / A020 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action Q NEW permit OR newly -reported emission source ✓❑ Request coverage under traditional construction permit O Request coverage under a General Permit ❑ GP01 O GP08 If General Permit coverage is requested, the General Permit registration fee of $312.50 must be submitted along with the APEN filing fee. -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change in equipment O Change company name3 ❑ Change permit limit O Transfer of ownership's O Other (describe below) OR- ❑ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ APEN submittal for permit exempt/grandfathered source ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Ft Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Company equipment Identification No. (optional): For existing sources, operation began on: 2 - 400 bbl mixed liquid tanks TK8-9 For new or reconstructed sources, the projected start-up date is: Normal Hours of Source Operation: 24 Storage tank(s) located at: hours/day 7 days/week 52 weeks/year O Exploration a Production (EEtP) site 0 Midstream or Downstream (non EftP) site Will this equipment be operated in any NAAQS nonattainment area? Yes No • 12 Are Flash Emissions anticipated from these storage tanks? Yes No p • Is the actual annual average hydrocarbon liquid throughput ≥ 500 bbl/day? Yes No U 12 If "yes", identify the stock tank gas -to -oil ratio: m3/liter Are these storage tanks subject to Colorado Oil and Gas Conservation Commission (COGCC) 805 series rules? If so, submit Form APCD-105. Yes No IN Fl Are you requesting ≥ 6 ton/yr VOC emissions (per storage tank), or are uncontrolled actual emissions ≥ 6 ton/yr (per storage tank)? Yes No D ■ Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 COLORADO 2j �� ron�n�aom Permit Number: AIRS ID Number: 123 I A020 i [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Storage Tank(s) Information Actual Annual Amount (bbl /year) Condensate Throughput: From what year is the actual annual amount? 2019 Average API gravity of sales oil: 73.3 degrees ❑ Internal floating roof Tank design: 0 Fixed roof Requested Annual Permit Limits (bbl/year) 78,840 RVP of sales oil: --12 ❑ External floating roof Storage Tank ID # of Liquid Manifold Storage Vessels in Storage Tank Total Volume of Storage Tank (bbl) Installation Date of Most Recent Storage Vessel in Storage Tank (month/year) Date of First Production (month/year) TK-8-9 2 800 Wells Serviced by this Storage Tank or Tank Battery6 (E&P Sites Only) API Number Name of Well Newly Reported Well - - IN _ ■ - ■ - - • - - • 5 Requested values will become permit limitations. Requested limit(s) should consider future growth. 6 The EEtP Storage Tank APEN Addendum (Form APCD-212) should be completed and, attached when additional space is needed to report all wells that are serviced by the equipment reported on this APEN form. Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 Operator Stack ID No. Discharge Height Above Ground Level (feet) Temp. (°F) Flow Rate (ACFM) Velocity (ft/sec) Combustor 12 1000 Variable Variable Indicate the direction of the stack outlet: (check one) O Upward O Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) O Circular ❑ Square/rectangle ❑ Other (describe): O Upward with obstructing raincap Interior stack diameter (inches): 48 Interior stack width (inches): Interior stack depth (inches): Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 3 coLoRAoo ee. He.*.* Prix, HebuI? Pi Permit Number: AIRS ID Number: 123 / A020 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Control Device Information O Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. Vapor ❑ Recovery Unit (VRU): Pollutants Controlled: Size: Requested Control Efficiency: Make/Model: VRU Downtime or Bypassed (emissions vented): % ❑ Combustion Device: Pollutants Controlled: VOC and HAPs Rating: MMBtu/hr Type: Enclosed Combustor Make/Model: TB D Requested Control Efficiency: 95 % Manufacturer Guaranteed Control Efficiency: 98+ Minimum Temperature: NA Waste Gas Heat Content: 1906 Btu/scf Constant Pilot Light: ✓❑ Yes ❑ No Pilot Burner Rating: 0.2 MMBtu/hr O Closed Loop System Description of the closed loop system: O Other: Pollutants Controlled: Description: Control Efficiency Requested: Section 7 - Gas/Liquids Separation Technology Information (E£itP Sites Only) What is the pressure of the final separator vessel prior to discharge to the storage tank(s)? psig Describe the separation process between the well and the storage tanks: Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 4 .Y COLORADO bcwty,-xn rant Permit Number: AIRS ID Number: 123 /A020/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form7. If multiple emission control methods were identified in Section 6, the following table can be used to state the Pollutant Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) VOC Combustor 95% NOx CO HAPs Combustor 95% Other: From what year is the following reported actual annual emissions data? 2019 Criteria Pollutant Emissions Inventory Pollutant Emission Factor Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units Source (AP -42, Mfg. etc) ) Uncontrolled Emissions (Tons/year) Controlled Emissions8 (Tons/year). Uncontrolled Emissions (Tons/year) Controlled Emissions (Tons/year) VOC 13.7 lb/bbl State default 540.05 27.00 NOx CO O.lioc ►t,/bbl 51-c,eolJ• & . '4 6. Non -Criteria Reportable Pollutant Emissions Inventory Chemical Name Chemical Abstract Service (CAS) Number Emission Factor Actual Annual Emissions Uncontrolled Basis Units Source (AP -42, Mfg. etc) Uncontrolled Emissions (Pounds/year) Controlled Emissions8 (Pounds/year) Benzene 71432 0.024 lb/bbl State Default 1892 95 Toluene 108883 Ethylbenzene 100414 Xylene 1330207 n -Hexane 110543 0.21 lb/bbl State Default 16556 828 2,2,4- Trimethylpentane 540841 5 Requested values will become permit limitations. Requested limit(s) should consider future growth. 7 Attach condensate liquid laboratory analysis, stack test results, and associated emissions calculations if you are requesting site specific emissions factors according to the guidance in PS Memo 14-03. $ Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 AT ADO 51 o«�� Permit Number: AIRS ID Number: 123 /A020 I [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. If this is a registration for coverage under General Permit GP01 or GP08, I further certify that this source is and will be operated in full compliance with each condition of the applicable General Permit. Nicholas Holland Digitally signed by Nicholas Holland Date: 2019.05.07 21:34:08 -06'00' 05/07/2019 Signature of Legally Authorized Person (not a vendor or consultant) Date Nick Holland Director EHS&R Name (print) Title Check the appropriate box to request a copy of the: Q✓ Draft permit prior to issuance 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 $191.13 and the General Permit registration fee of $312.50, if applicable, to: 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 COLOR ADO ce-H =w t. Put 6 �y,Mty� uhpt•, „n, Condensate Storage Tank(s) APEN Form APCD-205 Air Pollutant Emission Notice (APEN) and Application for Construction Permit AU 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 tanks that store condensate associated with oil and gas industry operations. If your emission source does not fall into this category, there may be a more specific APEN available for your source (e.g. crude oil storage tanks, produced water storage tanks, hydrocarbon liquid loading, 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 and associated addendum forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.Qov/pacific/cdphe/air-permits. 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: IcWEP081 AIRS ID Number: 123 / A020 / 022 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Cureton Front Range LLC Site Name: Hookside Gas Plant Site Location: SE Sec. 30, T9N, R60W Mailing Address: (include Zip code) 518 17th Street, Suite 1405 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Nick Holland Phone Number: 303-324-5967 E -Mail Address2: nick,holland@curetonmidstream.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 the APCD via e-mail to the address provided. 399240 Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 COLORADO HnDepah.�o Permit Number: AIRS ID Number: 123 /A020/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑✓ NEW permit OR newly -reported emission source ❑✓ Request coverage under traditional construction permit O Request coverage under a General Permit O GP01 O GP08 If General Permit coverage is requested, the General Permit registration fee of $312.50 must be submitted along with the APEN filing fee. -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change in equipment O Change company name3 ❑ Change permit limit O Transfer of ownership4 O Other (describe below) -OR- ❑ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ APEN submittal for permit exempt/grandfathered source ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info E: Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: 2 - 1000 bbl stabilized condensate tanks Company equipment Identification No. (optional): TK1 0-11 For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: Normal Hours of Source Operation: 24 hours/day 7 days/week 52 weeks/year Storage tank(s) located at: O Exploration Et Production (EftP) site El Midstream or Downstream (non E&P) site Will this equipment be operated in any NAAQS nonattainment area? Yes No ■ O Are Flash Emissions anticipated from these storage tanks? Yes No • El Is the actual annual average hydrocarbon liquid throughput ≥ 500 bbl/day? Yes No • O If "yes", identify the stock tank gas -to -oil ratio: m3/liter Are these storage tanks subject to Colorado Oil and Gas Conservation Commission (COGCC) 805 series rules? If so, `submit Form APCD-105. Yes No • O Are you requesting ≥ 6 ton/yr VOC emissions (per storage tank), or are uncontrolled actual emissions ≥ 6 ton/yr (per storage tank)? Yes No • Form APCD-2O5 - Condensate Storage Tank(s) APEN - Revision 7/2018 :COLORADO 2 IhillDeparcserit Puta. Ho** b F..totgnrni Permit Number: AIRS ID Number: 1 23 1 A020 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Storage Tank(s) Information Actual Annual Amount (bbl/year) Condensate Throughput: Requested Annual Permit Limits (bbl/year) 730,000 From what year is the actual annual amount? 2019 Average API gravity of sales oil: 73.3 degrees O Internal floating roof Tank design: ✓❑ Fixed roof RVP of sales oil: ~9.4 ❑ External floating roof Storage Tank ID # of Liquid Manifold Storage Vessels in Storage Tank Total Volume of Storage Tank (bbl) Installation Date of Most Recent Storage Vessel in Storage Tank (month/year) Date of First Production (month/year) TK-10-11 2 2000 Wells Serviced by this Storage Tank or Tank Battery6 (E&P Sites Only) API Number Name of Well Newly Reported Well ■ ■ - - ■ - - ■ ■ 5 Requested values will become permit limitations. Requested limit(s) should consider future growth. 6 The EEtP Storage Tank APEN Addendum (Form APCD-212) should be completed and attached when additional space is needed to report all wells that are serviced by the equipment reported on this APEN form. Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.714669/-104.131155 Operator Stack ID No. Discharge Height Above Ground Level (feet) Temp. (°F) Flow Rate (ACFM) Velocity (ft/sec) Combustor 12 1000 Variable Variable Indicate the direction of the stack outlet: (check one) ❑� Upward O Downward O Horizontal O Other (describe): Indicate the stack opening and size: (check one) ID Circular ❑ Square/rectangle ❑ Other (describe): O Upward with obstructing raincap Interior stack diameter (inches): 48 Interior stack width (inches): Interior stack depth (inches): Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 3 I AV of COLORADO Nflnh(. �nuk?n MM Permit Number: AIRS ID Number: 1 23 1A020 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Control Device Information ❑ Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. Vapor ❑ Recovery Unit (VRU): Pollutants Controlled: Size: Make/Model: Requested Control Efficiency: % VRU Downtime or Bypassed (emissions vented): % ❑ Combustion Device: Pollutants Controlled: VOC and HAPs Rating: MMBtu/hr p Type: Enclosed Combustor Make/Model: TB D Requested Control Efficiency: 95 Manufacturer Guaranteed Control Efficiency: 98+ Minimum Temperature: NA Waste Gas Heat Content: Constant Pilot Light: ✓❑ Yes O No Pilot Burner Rating: 4059 0.2 Btu/scf MMBtu/hr ❑ Closed Loop System Description of the closed loop system: O Other: Pollutants Controlled: Description: Control Efficiency Requested: % Section 7 - Gas/Liquids Separation Technology Information (Eat) Sites Only) What is the pressure of the final separator vessel prior to discharge to the storage tank(s)? psig Describe the separation process between the welt and the storage tanks: Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 COLORADO 4 I ' H40ui+. b �nukMrt�nN� Permit Number: AIRS ID Number: 123 1A020/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Pollutant Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) VOC Combustor 95% NOx CO HAPs Combustor 95% Other: From what year is the following reported actual annual emissions data? 201 9 Criteria Pollutant Emissions Inventory Pollutant Emission Factor Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units Source (AP -42, Mfg. etc) Uncontrolled Emissions (Tons/ ear y ) Controlled Emissions8 (Tons/year) Uncontrolled Emissions (Tons/year) Controlled Emissions (Tons/year) VOC 0.259 lb/bbl E&P Tanks 94.66 4.73 NOx CO Non -Criteria Reportable Pollutant Emissions Inventory Chemical Name Chemical Abstract Service CAS (CAS) Number Emission Factor Actual Annual Emissions Uncontrolled Basis Units Source (AP -42, Mfg. etc) Uncontrolled Emissions (Pounds/year) Controlled Emissions8 (Pounds/year) Benzene 71432 0.0040 lb/bbl E&P Tanks 2944 147 Toluene 108883 0.0017 lb/bbl E&P Tanks 1264 63 Ethylbenzene 100414 Xylene 1330207 n -Hexane 110543 2,2,4- Trimethylpentane 540841 5 Requested values will become permit limitations. Requested limit(s) should consider future growth. 7 Attach condensate liquid laboratory analysis, stack test results, and associated emissions calculations if you are requesting site specific emissions factors according to the guidance in PS Memo 14-03. 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD 205 - Condensate Storage Tank(s) APEN - Revision 7/2018 COLORADO 5 I T!�,o« H,,ltn55nvftgs, ,qt Permit Number: AIRS ID Number: 123 /A020/ [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. If this is a registration for coverage under General Permit GP01 or GP08, I further certify that this source is and will be operated in full compliance with each condition of the applicable General Permit. Nicholas Holland Digitally signed by Nicholas Holland Date: 2019.05.07 21:35:55 -06'00' 05/07/2019 Signature of Legally Authorized Person (not a vendor or consultant) Date Nick Holland Director EHS&R Name (print) Title Check the appropriate box to request a copy of the: ❑� Draft permit prior to issuance ❑� 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 $191.13 and the General Permit registration fee of $312.50, if applicable, to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B 1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: //www.cotorado.gov/cdphe/apcd Form APCD-205 - Condensate Storage Tanks) APEN - Revision 7/2018 COLORADO 6 I �a.�,� Hello