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Home My WebLink About20161159 A GDPHE COLORADO Co 'If Department of Public Health&Environment Dedicated to protecting and improving the health and environment of the people of Colorado Weld County - Clerk to the Board1150 0 St RECEIVED PO Box 758 RECEIVED Greeley, CO 80632 MAR 2 8 2016 March 24, 2016 WELD COUNTY COMMISSIONERS Dear Sir or Madam: On March 30, 2016, the Air Pollution Control Division will begin a 30-day public notice period for Sterling Energy Investments LLC - Centennial 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 Clara Gonzales Public Notice Coordinator Stationary Sources Program Air Pollution Control Division Enclosure ---PLoouL'Roubui ecTa.:;?1,0;4-3/(29 2016-1159 Wq/IIP4300 Cherry Creek Drive S., Denver, CO 80246-1530 P 303-692-2000 www.colorado.gov/cdphe John W. Hickenlooper, Governor Larry Wolk,MD,MSPH, Executive Director and Chief Medical Officer , ib s, CDPHE Air Pollution Control Division CO s' Notice of a Proposed Project or Activity Warranting Public r„ Comment Website Title: Sterling Energy Investments LLC - Centennial Gas Plant - Weld County Notice Period Begins: March 30, 2016 Notice is hereby given that an application for a proposed project or activity has been submitted to the Colorado Air Pollution Control Division for the following source of air pollution: Applicant: Sterling Energy Investments LLC Facility: Centennial Gas Plant Natural gas processing plant SESW S25 T9N R61W Weld County The proposed project or activity is as follows: Natural gas processing plant modifying emissions from four (4) existing reciprocating internal combustion engines, adding a plant flare to control vented gas during upsets and maintenance and replacing a TEG glycol dehydrator. The Division has determined that this permitting action is subject to public comment per Colorado Regulation No. 3, Part B, Section III.C due to the following reason(s): a the source is requesting a federally enforceable limit on the potential to emit in order to avoid other requirements The Division has made a preliminary determination of approval of the application. A copy of the application, the Division's analysis, and a draft of Construction Permit 12WE2117 have been filed with the Weld County Clerk's office. A copy of the draft permit and the Division's analysis are available on the Division's website at https://www.colorado.gov/pacific/cdphe/air-permit-public-notices The Division hereby solicits submission of public comment from any interested person concerning the ability of the proposed project or activity to comply with the applicable standards and regulations of the Commission. The Division will receive and consider written public comments for thirty calendar days after the date of this Notice. Any such comment must be submitted in writing to the following addressee: Stephanie Spector Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South, APCD-SS-B1 Denver, Colorado 80246-1530 cdphe.commentsapcd@state.co.us COLOR 4D0 STATE OF COLORADO /pF COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT y� a AIR POLLUTION CONTROL DIVISION TELEPHONE: (303) 692-3150 *c__`,876 CONSTRUCTION PERMIT PERMIT NO: 1 2WE21 1 7 Issuance 3 DATE ISSUED: ISSUED TO: Sterling Energy Investments LLC THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS: Natural gas processing facility, known as the Centennial Gas Plant, located in SESW S25 T9N R61 W, in Weld County, Colorado. THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING: Facility AIRS Description Equipment ID Point One (1)Waukesha, Model L7044GS1, Serial Number To Be Determined, natural gas-fired, turbo-charged, 4SRB reciprocating internal combustion engine, site rated at 1680 C001 001 horsepower at 1200 RPM. This engine shall be equipped with a non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. One (1)Waukesha, Model L7044GS1, Serial Number To Be Determined, natural gas-fired, turbo-charged, 4SRB reciprocating internal combustion engine, site rated at 1680 C002 002 horsepower at 1200 RPM. This engine shall be equipped with a non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. One (1)Waukesha, Model L7042GS1, Serial Number To Be Determined, natural gas-fired, turbo-charged, 4SRB reciprocating internal combustion engine, site rated at 1480 G001 003 horsepower at 1200 RPM. This engine shall be equipped with a non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for power production for up to 9260 hours per year shared with point 004 (G002). AIRS ID: 123/9966 Page 1 of 28 NGEngine Version 2012-1 IColl .o D rime o -ublic Health and Environment Air Pollution Control Division Facility AIRS Description Equipment ID Point One (1)Waukesha, Model L7042GS1, Serial Number To Be Determined, natural gas-fired, turbo-charged, 4SRB reciprocating internal combustion engine, site rated at 1480 G002 004 horsepower at 1200 RPM. This engine shall be equipped with a non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for power production for up to 9260 hours per year shared with point 003 (G001). Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 28.0 MMSCF per day (custom built serial number:TBD). This emissions unit is equipped with one (1) electric amine AMINE001 009 recirculation pump, make, model, and serial #, TBD, with a design capacity of 80 gallons per minute.. This system includes a natural gas/amine contactor, a flash tank, and a natural gas fired amine regeneration reboiler. All emissions from the still vent are routed to the thermal oxidizer. FUG001 010 Equipment leaks (fugitive VOCs)from a Natural Gas Processing Plant. TO001 011 Thermal Oxidizer as a control for waste streams of Amine unit and Dehydration unit. One (1)Waukesha, Model L7044GSI, Serial Number To Be Determined, natural gas-fired, turbo-charged, 4SRB reciprocating internal combustion engine, site rated at 1680 R003 013 horsepower at 1200 RPM. This engine shall be equipped with a non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for residue compression. One (1)Waukesha, Model L7044GS1, Serial Number To Be Determined, natural gas-fired, turbo-charged, 4SRB reciprocating internal combustion engine, site rated at 1680 C003 014 horsepower at 1200 RPM. This engine shall be equipped with a non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. One (1)Waukesha, Model L7044GS1, Serial Number To Be Determined, natural gas-fired, turbo-charged, 4SRB reciprocating internal combustion engine, site rated at 1680 C004 015 horsepower at 1200 RPM. This engine shall be equipped with a non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. AIRS ID: 123/9966 Page 2 of 28 Col, o Dlofftme o ublic Health and Environment I. . . Air Pollution Control Division Facility AIRS Description Equipment ID Point Plant flare controls vented gas during plant upsets and FLARE001 017 maintenance. Flare has a minimum combustion efficiency of 95%. The flare is not enclosed. One (1) Triethylene glycol (TEG) natural gas dehydration unit (J.W. Williams, model 375 MBtu/28 MMscfd, serial number: TBD) with a design capacity of 28 MMscf per day. This emissions unit is equipped with two (2) Rotor-Tech, model GS1104-E7.5.0TEFC, electric-glycol pumps (one is a DEHY002 019 backup pump) with a design capacity of 5.0 gallons per minute each. This unit is equipped with a flash tank, reboiler and still vent. Stripping gas is injected into the reboiler. Emissions from the still vent are routed to a thermal oxidizer. Emissions from the flash tank are routed to the facility inlet stream in a closed loop system. These engines may be replaced with another engine in accordance with the temporary engine replacement provision or with an engine of the same make and model specified for each point in accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as Attachment A. 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 THOSE GENERAL TERMS AND CONDITIONS INCLUDED IN THIS DOCUMENT AND THE FOLLOWING SPECIFIC TERMS AND CONDITIONS: REQUIREMENTS TO SELF-CERTIFY FOR FINAL AUTHORIZATION 1. YOU MUST notify the Air Pollution Control Division (the Division) no later than fifteen days after commencement of operation, by submitting a Notice of Startup form to the Division. The Notice of Startup form may be downloaded online at www.cdphe.state.co.us/ap/downloadforms.html. Failure to notify the Division of startup of the permitted source is a violation of Air Quality Control Commission (AQCC) Regulation No. 3, Part B, Section III.G.1 and can result in the revocation of the permit. 2. Within one hundred and eighty days (180) after commencement of operation, 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 to demonstrate compliance within 180 days may result in revocation of the permit. (Reference: Regulation No. 3, Part B, III.G.2). 3. This permit shall expire if the owner or operator of the source for which this permit was issued: (i) does not commence construction/modification or operation of this source within 18 months after either, the date of issuance of this construction permit or the date on which such construction or activity was scheduled to commence as set forth in the permit application associated with this permit; (ii) discontinues construction for a period of eighteen months or more; (iii) does not complete construction within a reasonable time of the estimated completion date. The Division may grant extensions of the deadline per Regulation No. 3, Part B, III.F.4.b. (Reference: Regulation No. 3, Part B, III.F.4.) AIRS ID: 123/9966 Page 3 of 28 I lk Er cot, . .o D !me o -ublic Health and Environment Air Pollution Control Division 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. (Reference: Regulation No. 3, Part B, Section III.E.) 5. The following information shall be provided to the Division within fifteen (15) days after commencement of operation. • manufacture date • construction date • order date • date of relocation into Colorado • manufacturer • model number • serial number This information shall be included with the Notice of Startup submitted for the equipment. (Reference: Regulation No. 3, Part B, III.E.) 6. 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 7. Emissions of air pollutants shall not exceed the following limitations (as calculated in the Division's preliminary analysis). (Reference: Regulation No. 3, Part B, Section II.A.4) Monthly Limits: Facility AIRS Pounds per Month Equipment ID Point NO VOC CO Emission Type X C001 001 827 358 827 Point C002 002 827 1105 827 Point G001/G002 003/004 782 1020 782 Point AMINE001 009 --- 177 --- Point FUG001 010 --- 7577 --- Fugitive TO001 011 807 --- 1431 Point R003 013 827 358 827 Point C003 014 827 1105 827 Point C004 015 827 358 827 Point FLARE001 017 255 2531 1291 Point DEHY002 019 --- 476 --- Point (Note: Monthly limits are based on a 31-day month.) The owner or operator shall calculate monthly emissions based on the calendar month. Facility-wide emissions of each individual hazardous air pollutant shall be less than 1,359 lb/month. AIRS ID: 123/9966 Page 4 of 28 Col 'do D_ the " o Public Health and Environment Air Pollution Control Division Facility-wide emissions of total hazardous air pollutants shall be less than 3,398 lb/month. Annual Limits: Facility AIRS Tons per Year Emission Type Equipment ID Point NO. VOC CO C001 001 4.9 2.1 4.9 Point C002 002 4.9 6.5 4.9 Point G001/G002 003/004 4.6 6.0 4.6 Point AMINE001 009 --- 1.0 --- Point FUG001 010 --- 44.6 --- Fugitive TO001 011 4.8 --- 8.4 Point R003 013 4.9 2.1 4.9 Point C003 014 4.9 6.5 4.9 Point C004 015 4.9 2.1 4.9 Point FLARE001 017 1.5 14.9 7.6 Point DEHY002 019 --- 2.8 --- Point See "Notes to Permit Holder"for information on emission factors and methods used to calculate limits. Facility-wide emissions of each individual hazardous air pollutant shall be less than 8.0 tpy. Facility-wide emissions of total hazardous air pollutants shall be less than 20.0 tpy. 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 shall be determined by recording the facility's annual criteria pollutant emissions, (including all HAPs above the de-minimis reporting level) from each emission unit, on a rolling twelve (12) month total. By the end of each month a new twelve-month total shall be calculated based on the previous twelve months' data. The permit holder shall calculate emissions each month and keep a compliance record on site or at a local field office with site responsibility, for Division review. This rolling twelve-month total shall apply to all permitted emission units, requiring an APEN, at this facility. 8. Point 010: The operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent extended 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 request. 9. The owner or operator shall track emissions from all insignificant activities at the facility on an annual basis to demonstrate compliance with the facility emission limitations as AIRS ID: 123/9966 Page 5 of 28 iCol +o D rime o •ublic Health and Environment Air Pollution Control Division seen below. An inventory of each insignificant activity and associated emission calculations shall be made available to the Division for inspection upon request. For the purposes of this condition, insignificant activities shall be defined as any activity or equipment, which emits any amount but does not require an Air Pollutant Emission Notice (APEN). Total emissions from the facility, including permitted emissions and insignificant activities, shall be less than: • 100 tons per year of any criteria pollutant 10. The emission points in the table below shall be operated and maintained with the control equipment as listed in order to reduce emissions to less than or equal to the limits established in this permit (Reference: Regulation No.3, Part B, Section III.E.) Facility AIRS Pollutants Equipment Point Control Device Controlled ID C001 001 NSCR catalyst and air/fuel ratio controller NOx, CO, VOC C002 002 NSCR catalyst and air/fuel ratio controller NOx, CO G001 003 NSCR catalyst and air/fuel ratio controller NOx, CO G002 004 NSCR catalyst and air/fuel ratio controller NOx, CO AMINE001 009 Thermal Oxidizer VOC, HAPs R003 013 NSCR catalyst and air/fuel ratio controller NOx, CO, VOC C003 014 NSCR catalyst and air/fuel ratio controller NOx, CO C004 015 NSCR catalyst and air/fuel ratio controller NOx, CO, VOC FLARE001 017 Process flare for blowdown events from planned VOC, HAPs maintenance and emergencies Flash tank: routed to facility inlet stream DEHY002 019 VOC, HAPs Still vent: thermal oxidizer 11. Point 019: Compliance with the emission limits in this permit shall be demonstrated by running the Promax simulation model on a monthly basis using the most recent wet gas analysis and recorded operational values (including gas throughput, lean glycol recirculation rate, and other operational values specified in the O&M Plan). Recorded operational values, except for gas throughput, shall be averaged on a monthly basis for input into Promax and be provided to the Division upon request. 12. Point 019: 100% of emissions that result from the flash tank associated with this dehydrator shall be recycled to the facility inlet stream. PROCESS LIMITATIONS AND RECORDS 13. This source shall be limited to the following maximum processing rates as listed below. Monthly records of the actual processing rate shall be maintained by the owner or AIRS ID: 123/9966 Page 6 of 28 max. „ Col o DIqaeme o Public Health and Environment Air Pollution Control Division operator and made available to the Division for inspection upon request. (Reference: Regulation 3, Part B, II.A.4) Process/Consumption Limits Facility Annual Monthly Limit Equipment AIRS Point Process Parameter Limit (31 days) ID C001 001 Consumption of natural gas as a 98.25 8.35 fuel MMscf/yr MMscf/month C002 002 Consumption of natural gas as a 98.25 8.35 fuel MMscf/yr MMscf/month G001/G002 003/004 Consumption of natural gas as a 92.53 7.86 fuel MMscf/yr MMscf/month AMINE001 009 Throughput of natural gas 10,220 868 MMscf/yr MMscf/month TO001 011 Consumption of waste gas and 332.9 28.3 supplemental fuel MMscf/yr MMscf/month R003 013 Consumption of natural gas as a 98.25 8.35 fuel MMscf/yr MMscf/month C003 014 Consumption of natural gas as a 98.25 8.35 fuel MMscf/yr MMscf/month C004 015 Consumption of natural gas as a 98.25 8.35 fuel MMscf/yr MMscf/month FLARE001 017 Natural gas flaring 27.5 2.3 MMSCF/yr MMSCF/month DEHY002 019 Throughput of natural gas 10,220 868 MMscf/yr MMscf/month The owner or operator shall calculate 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. 14. Point 009: This unit shall be limited to the maximum lean amine circulation rate of 80 gallons per minute. The amine recirculation rate shall be recorded weekly in a log maintained on site and made available to the Division for inspection upon request. (Reference: Regulation No. 3, Part B, 15. Points 009, 011 and 019: The owner or operator shall install, maintain and operate inline flow meters on the waste gas feed to the thermal oxidizer and supplemental/make- up fuel feed to the thermal oxidizer. The flow meters shall be calibrated at a minimum frequency of at least once per every twelve months. 16. Point 019: This unit shall be limited to the maximum lean glycol circulation rate of 5.0 gallons per minute. The lean glycol recirculation rate shall be recorded weekly in a log maintained on site and made available to the Division for inspection upon request. (Reference: Regulation No. 3, Part B, II.A.4) AIRS ID: 123/9966 Page 7 of 28 ICols' +o D i me o -ublic Health and Environment I Air Pollution Control Division STATE AND FEDERAL REGULATORY REQUIREMENTS 17. The permit number and AIRS ID point number(e.g. 123/4567/890) shall be marked on the subject equipment for ease of identification. (Reference: Regulation Number 3, Part B, III.E.) (State only enforceable) 18. 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. Emission control devices subject to Regulation 7, Sections XII.C.1.d or XVII.B.1.c shall have no visible emissions. (Reference: Regulation No. 1, Section II.A.1. &4.) 19. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable) 20. Points 001-004, 013-015: This equipment is subject to the control requirements for natural gas-fired reciprocating internal combustion engines under Regulation No. 7, Section XVII.E (State only enforceable). The owner or operator of any natural gas-fired reciprocating internal combustion engine that is either constructed or relocated to the state of Colorado from another state after the date listed in the table below shall operate and maintain each engine according to the manufacturer's written instructions or procedures to the extent practicable and consistent with technological limitations and good engineering and maintenance practices over the entire life of the engine so that it achieves the emission standards required in the table below: Maximum Engine Construction or Emission Standard in g/hp-hr HP Relocation Date NOx CO VOC <100HP Any N/A N/A N/A ≥100HP and January 1, 2008 2.0 4.0 1.0 <500HP January 1, 2011 1.0 2.0 0.7 ≥500HP July 1, 2007 2.0 4.0 1.0 July 1, 2010 1.0 2.0 0.7 Note: Per Regulation No. 7, Section XVII.B.4, internal combustion engines that are subject to an emission standard or an emissions control requirement in a federal maximum achievable control technology ("MACT") standard under 40 CFR Part 63, a Best Available Control Technology ("BACT") limit, or a New Source Performance Standard under 40 CFR Part 60 are not subject to this Section XVII. 21. Points 009 and 019: The operating temperature of the regenerative thermal oxidizer used to control emissions from this dehydration unit and amine unit shall be greater than 1400°F, or the temperature established during the most recent stack test of the equipment that was approved by the Division, at all times that any dehydration unit or amine unit emissions are routed to the thermal oxidizer in order to meet the emission limits in this permit. 22. Point 009: The permit holder shall measure and record the following amine unit operating parameters for each amine unit. Records of these operating parameters shall AIRS ID: 123/9966 Page 8 of 28 Col o D me o Public Health and Environment Air Pollution Control Division be made available to the Division for inspection upon request. (Colorado Regulation No. 3, Part A, II): a. The operating temperature of the regenerative thermal oxidizer shall be recorded daily. b. The lean amine strength shall be measured and recorded on a weekly basis. The lean amine strength is defined as the combined weight percent of MDEA, DEA and piperazine in the lean amine stream. c. Fuel use by the regenerative thermal oxidizer shall be measured or calculated and recorded on a monthly basis. 23. Point 009: This amine unit is subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: • §60.5365—Applicability and Designation of Affected Facilities o §60.5365(g)(3) - Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) are required to comply with recordkeeping and reporting requirements specified in §60.5423(c) but are not required to comply with §§60.5405 through 60.5407 and §§60.5410(g) and 60.5415(g). • §60.5423— Record keeping and reporting Requirements o §60.5423(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 24. Point 009: The operator shall sample the inlet gas to the plant, on an annual basis, to determine the concentration of hydrogen sulfide (H2S) and total sulfur in the gas stream. The sample results shall be monitored to demonstrate the amine unit qualifies for the exemption contained in §60.5365 listed above. The sample results shall also be monitored to demonstrate that the total sulfurs concentration, including H2S, in the gas stream is equal to 0 ppm. 25. Point 010: The fugitive emissions addressed by AIRS ID 010 are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: • §60.5365 Applicability - The group of all equipment, except compressors, within a process unit for which you commence construction, modification or reconstruction after August 23, 2011 is an affected facility per§60.5365(f). • §60.5400 Standards - The group of all equipment, except compressors, within a process unit must comply with the requirements of§60.5400 and §60.5401. • §60.5410 - Owner or operator must demonstrate initial compliance with the standards using the requirements in §60.5410(f). AIRS ID: 123/9966 Page 9 of 28 ICol A.o D !me o 'ublic Health and Environment I Air Pollution Control Division • § 60.5415 - Owner or operator must demonstrate continuous compliance with the standards using the requirements in §60.5415(f). • § 60.5421 - Owner or operator must comply with the recordkeeping requirements of §60.5421(b). • § 60.5422 - Owner or operator must comply with the reporting requirements of paragraphs (b) and (c) of this section in addition to the requirements of§ 60.487a(a), (b), (c)(2)(i)through (iv), and (c)(2)(vii)through (viii). 26. Point 010: The reciprocating compressors grouped with the fugitive emissions addressed by AIRS ID 010 are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: • §60.5385(a) — Owner or operator must replace the reciprocating compressor rod packing according to either paragraph §60.5385(a)(1) or(2). (i) §60.5385(a)(1) - Before the compressor has operated for 26,000 hours. The number of hours of operation must be continuously monitored beginning upon initial startup of your reciprocating compressor affected facility, or October 15, 2012, or the date of the most recent reciprocating compressor rod packing replacement, whichever is later. (ii) §60.5385(a)(2) - Prior to 36 months from the date of the most recent rod packing replacement, or 36 months from the date of startup for a new reciprocating compressor for which the rod packing has not yet been replaced. • §60.5410 — Owner or operator must demonstrate initial compliance with the standards as detailed in §60.5410(c). • §60.5415 —Owner or operator must demonstrate continuous compliance with the standards as detailed in §60.5415(c). • §60.5420 - Owner or operator must comply with the notification, reporting, and recordkeeping requirements as specified in §60.5420(a), §60.5420(b)(1), §60.5420(b)(4), and §60.5420(c)(3). 27. Point 019: The thermal oxidizer covered by this permit is subject to Regulation No. 7, Section XVII.B 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, 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. The operator shall comply with all applicable requirements of Section XVII. 28. Point 019: This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XVII.D (State only enforceable). Beginning May 1, 2008, uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas-condensate-glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by an average of at least 90 percent through the use of air pollution control equipment. AIRS ID: 123/9966 Page 10 of 28 Colrlo D me o ublic Health and Environment Air Pollution Control Division This source shall comply with all applicable general provisions of Regulation 7, Section XVII. 29. Point 019: This source is subject to the requirements of 40 CFR, Part 63, Subpart HH - National Emission Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities including, but not limited to, the following: • §63.764 - General Standards o §63.764 (e)(1) -The owner or operator of an area source 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). ■ §63.764 (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. • §63.772 - Test Methods, Compliance Procedures and Compliance Demonstration o §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. • §63.772(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-GLYCaIc 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 • §63.772(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. AIRS ID: 123/9966 Page 11 of 28 `I CoI f o D me o •ublic Health and Environment ' Air Pollution Control Division • §63.774 - Recordkeeping Requirements o §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. o §63.774 (d)(1)(ii) - The actual average benzene emissions (in terms of benzene emissions per year) as determined in accordance with §63.772(b)(2). OPERATING & MAINTENANCE REQUIREMENTS 30. Points 001-004, 009, 013-015, 017, 019: Upon startup of these points, the owner or operator shall follow the most recent operating and maintenance (O&M) plan and record keeping format approved by the Division, in order to demonstrate compliance on an ongoing basis with the requirements of this permit. Revisions to your O&M plan are subject to Division approval prior to implementation. (Reference: Regulation No. 3, Part B, Section III.G.7.) 31. Point 009: The inlet gas temperature and inlet gas pressure shall be measured and recorded monthly. COMPLIANCE TESTING AND SAMPLING Initial Testing Requirements 32. Points 001-004, 013-015: A source initial compliance test shall be conducted on emissions points to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emission limits 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 (Reference: Regulation No. 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods. Carbon Monoxide using EPA approved methods. Volatile Organic Compounds using EPA approved methods Formaldehyde using EPA approved methods 33. Points 009, 011 and 019: A source initial compliance test shall be conducted on Points 009, 011, and 019 to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with in this permit. The operator shall also demonstrate the thermal oxidizer achieves a minimum destruction efficiency of 99.0% for VOC. The operator shall measure and record, using EPA approved methods, VOC mass emission rates from the thermal oxidizer inlet and outlet to determine the destruction efficiency of the thermal oxidizer(ProMax/Amine Calc/GlyCalc models shall not be used to determine the flow rate or composition of the waste gas sent to the thermal oxidizer for the purposes of this test). The natural gas throughput to the dehy unit, natural gas throughput to the amine unit, lean glycol circulation rate, lean amine circulation rate, MDEA/DEA/piperazine concentration, and sulfur content of sour gas entering the amine AIRS ID: 123/9966 Page 12 of 28 Col o D .me o Public Health and Environment Air Pollution Control Division unit shall be monitored and recorded during this test. The flow rate of supplemental fuel fired in the thermal oxidizer shall be monitored and recorded during the test, and the Btu content of such gases shall be determined using the appropriate ASTM Methods or equivalent, if approved in advance by the Division. The operator shall also measure and record combustion temperature during the initial compliance test to establish the minimum combustion temperature. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Volatile Organic Compounds using EPA approved methods. Hazardous Air Pollutants using EPA approved methods. Sulfur Dioxide using EPA approved methods Oxides of Nitrogen using EPA approved methods Carbon Monoxide using EPA approved methods 34. Points 009, 011 and 019: Within 60 calendar days following the completion of the compliance test required by Condition 33, the owner or operator shall update and re- submit the O&M Plan for this unit to include the minimum combustion chamber temperature established during the compliance test. The O&M Plan shall be updated to require daily combustion chamber temperature monitoring 35. Point 009: The owner or operator shall complete the initial sour gas analysis testing required by this permit and submit the results to the Division as part of the self- certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section III.E.) 36. Point 010: Within one hundred and eighty days (180) after commencement of operation, 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. 37. Point 010: Within one hundred and eighty days (180) after commencement of operation, the owner or operator shall complete the initial extended gas analysis of gas samples and extended natural gas liquids analysis of liquids that are representative of volatile organic compound (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas and liquids analyses 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 and liquids analyses and emission calculations to the Division as part of the self-certification process to ensure compliance with emissions limits. 38. Point 017: The owner or operator shall demonstrate compliance with opacity standards using EPA Method 9 to measure opacity from the flare. (Reference: Regulation No. 1, Section II.A.5). AIRS ID: 123/9966 Page 13 of 28 Col A.o D, erne _ o -ublic Health and Environment I Air Pollution Control Division 39. Point 019: The owner or operator shall demonstrate compliance with opacity standards, using EPA Method 22 to determine the presence or absence of visible emissions from the outlet of the thermal oxidizer(Point 011). "Visible Emissions" means observations of smoke for any period or periods of duration greater than or equal to one (1) minute in any fifteen (15) minute period during normal operation. (Reference: Regulation No. 7, Section XVII.A.II) Periodic Testing Requirements 40. Point 010: On an annual basis, the owner or operator shall complete an extended gas analysis of gas samples and an extended natural gas liquids analysis of liquids that are representative of volatile organic compounds (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas analysis and liquids analyses shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. 41. Points 001-004, 013-015: This engine is subject to the periodic testing requirements as specified in the operating and maintenance (O&M) plan as approved by the Division. Revisions to your O&M plan are subject to Division approval. Replacements of this unit completed as Alternative Operating Scenarios may be subject to additional testing requirements as specified in Attachment A 42. Point 009: The operator shall sample the inlet gas to the plant or the inlet gas to the amine unit on an annual basis to determine the concentration of hydrogen sulfide (H2S) in the gas stream. The sample results shall be monitored to demonstrate that this amine unit qualifies for the exemption from the Standards of Performance for Onshore Natural Gas Processing: SO2 Emissions (§60.5423(c)) and to demonstrate compliance with the sulfurs concentration limit in Condition 24. 43. Point 019: The owner or operator shall complete an extended wet gas analysis prior to the inlet of the TEG dehydrator on an annual basis. Results of the wet gas analysis shall be used to calculate emissions of criteria pollutants and hazardous air pollutants per this permit and be provided to the Division upon request. 44. Point 019: The owner or operator shall demonstrate compliance with opacity standards, using EPA Method 22 to determine the presence or absence of visible emissions from the outlet of the thermal oxidizer(Point 011) on a weekly basis. "Visible Emissions" means observations of smoke for any period or periods of duration greater than or equal to one (1) minute in any fifteen (15) minute period during normal operation. (Reference: Regulation No. 7, Section XVII.A.II) ADDITIONAL REQUIREMENTS 45. All previous versions of this permit are cancelled upon issuance of this permit. 46. This permit replaces the following permits and/or points, which are cancelled upon startup of the points in this permit. The owner or operator shall submit a cancellation notice for the following equipment with the Notice of Startup for the corresponding new equipment in this permit. Existing Existing Permit No. Emission Point New Emission Point AIRS ID: 123/9966 Page 14 of 28 7-1 Col o D aftme o Public Health and Environment Air Pollution Control Division 41111,— Air 12W E2117 123/9966/008 123/9966/019 47. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation No. 3, Part A, II.C) a. 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 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. b. Whenever there is a change in the owner or operator of any facility, process, or activity; or c. Whenever new control equipment is installed, or whenever a different type of control equipment replaces an existing type of control equipment; or d. Whenever a permit limitation must be modified; or e. No later than 30 days before the existing APEN expires. f. 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. 48. Federal regulatory program requirements (i.e. PSD, NANSR or Title V Operating Permit) shall apply to this source at any such time that this source becomes major solely by virtue of a relaxation in any permit condition. Any relaxation that increases the potential to emit above the applicable Federal program threshold will require a full review of the source as though construction had not yet commenced on the source. The source shall not exceed the Federal program threshold until a permit is granted. (Regulation No. 3 Part D). 49. MACT Subpart HH - National Emission Standards for Hazardous Air Pollutants From Oil and Natural Gas Production Facilities major stationary source requirements shall apply to this stationary source at any such time that this stationary source becomes major solely by virtue of a relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of Subpart HH. (Reference: Regulation No. 8, Part E) 50. MACT Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines requirements shall apply to this AIRS ID: 123/9966 Page 15 of 28 Col .o D - me o "ublic Health and Environment I Air Pollution Control Division source at any such time that this source becomes major solely by virtue of a relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of that Subpart on the date as stated in the rule as published in the Federal Register. (Reference: Regulation No. 8, Part E) GENERAL TERMS AND CONDITIONS: 51. This permit and any attachments must be retained and made available for inspection upon request. The permit may be reissued to a new owner by the APCD as provided in AQCC Regulation No. 3, Part B, Section II.B upon a request for transfer of ownership and the submittal of a revised APEN and the required fee. 52. If this permit specifically states that final authorization has been granted, then the remainder of this condition is not applicable. Otherwise, the issuance of this construction permit does not provide "final" authority for this activity or operation of this source. Final authorization of the permit must be secured from the APCD in writing in accordance with the provisions of 25-7-114.5(12)(a) C.R.S. and AQCC Regulation No. 3, Part B, Section III.G. Final authorization cannot be granted until the operation or activity commences and has been verified by the APCD as conforming in all respects with the conditions of the permit. Once self-certification of all points has been reviewed and approved by the Division, it will provide written documentation of such final authorization. Details for obtaining final authorization to operate are located in the Requirements to Self- Certify for Final Authorization section of this permit. 53. 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 operator's agents. It is valid only for the equipment and operations or activity specifically identified on the permit. 54. 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. 55. 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 or owner or operator of a source may request a hearing before the AQCC for review of the Division's action. 56. 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. 57. 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, AIRS ID: 123/9966 Page 16 of 28 411 Col o D • me o ublic Health and Environment Air Pollution Control Division civil or criminal enforcement actions under Sections 25-7-115 (enforcement), -121 (injunctions), -122 (civil penalties), -122.1 (criminal penalties), C.R.S. By: Stephanie Spector, PE Permit Engineer Permit History Issuance Date Description Issuance 3 This Issuance Points 002, 003, 004 and 014: Modification to VOC emission limits. Addition of Point 017. Removing Point 008 and replacing it with Point 019. Removal of Points 005, 006, 007 and 012. Issuance 2 August 29, Modification to increase plant throughput, add 2014 points 013-015. Combine hours of use for points 003 and 004 to share wear and tear. Synthetic minor modification Issuance 1 June 11, 2013 Issued to Sterling Energy Investments LLC. New Synthetic Minor Gas Plant. AIRS ID: 123/9966 Page 17 of 28 col,A,+o D me o 'ublic Health and Environment Air Pollution Control Division Notes to Permit Holder at the time of this permit issuance: 1) The permit holder is required to pay fees for the processing time for this permit. An invoice for these fees will be issued after the permit is issued. The permit holder shall pay the invoice within 30 days of receipt of the invoice. Failure to pay the invoice will result in revocation of this permit (Reference: Regulation No. 3, Part A, Section VI.B.) 2) The production or raw material processing limits and emission limits contained in this permit are based on the consumption rates requested in the permit application. These limits may be revised upon request of the 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: http://www.cdphe.state.co.us/regulations/airregs/100102aacccommonprovisionsreq.pdf. 4) The following emissions of non-criteria reportable air pollutants are estimated based upon the process limits as indicated in this permit. This information is listed to inform the operator of the Division's analysis of the specific compounds emitted if the source(s) operate at the permitted limitations. Uncontrolled Are the Controlled AIRS Pollutant CAS# Emission emissions Emission Rate Point Rate reportable? (Ib/yr) (Ib/yr) Formaldehyde 50000 2336 Yes 2336 Acetaldehyde 75070 318 Yes 318 001 Acrolein 107028 300 Yes 300 Methanol 67561 349 Yes 349 Formaldehyde 50000 2336 Yes 2336 Acetaldehyde 75070 318 Yes 318 002 Acrolein 107028 300 Yes 300 Methanol 67561 349 Yes 349 Formaldehyde 50000 2200 Yes 2200 Acetaldehyde 75070 300 Yes 300 003/004 Acrolein 107028 282 Yes 282 Methanol 67561 329 Yes 329 Benzene 71432 7082 Yes 71 009 Toluene 108883 1008 Yes 10 n-Hexane 110543 1394 Yes 14 010 n-Hexane 110543 441 Yes 441 013 Formaldehyde 50000 2336 Yes 2336 AIRS ID: 123/9966 Page 18 of 28 r ., Col o D t arte o ublic Health and Environment 21 Air Pollution Control Division Acetaldehyde 75070 318 Yes 318 Acrolein 107028 300 Yes 300 Methanol 67561 349 Yes 349 Formaldehyde 50000 2336 Yes 2336 Acetaldehyde 75070 318 Yes 318 014 Acrolein 107028 300 Yes 300 Methanol 67561 349 Yes 349 Formaldehyde 50000 2336 Yes 2336 Acetaldehyde 75070 318 Yes 318 015 Acrolein 107028 300 Yes 300 Methanol 67561 349 Yes 349 Benzene 71432 24664 Yes 243 Toluene 108883 22892 Yes 227 019 Ethylbenzene 100414 3694 Yes 37 Xylenes 1330207 10098 Yes 101 n-Hexane 110543 12879 Yes 107 5) The emission levels contained in this permit are based on the following emission factors: Points 001,002,013-015: Emission Factors - Emission Factors— Uncontrolled Controlled CAS Pollutant lb/MMBtu g/bhp-hr lb/MMBtu g/bhp-hr NOx 3.78 13.3 0.095 0.30 CO 3.18 11.2 0.095 0.30 Points 001, VOC 9.9E-2 0.35 3.6E-2 0.13 013, 015 Points 002, VOC 0.114 0.4 0.114 0.4 014 5000 Formaldehyde 2.05E-2 7.2E-2 2.05E-2 7.2E-2 75070 Acetaldehyde 2.7E-3 9.8E-3 2.7E-3 9.8E-3 107028 Acrolein 0.00263 9.2E-3 0.00263 9.2E-3 71432 Benzene 0.00158 5.5E-3 0.00158 5.5E-3 106990 1,3-Butadiene 0.000663 0.002 0.000663 0.002 Emission factors are based on a Brake-Specific Fuel Consumption Factor of 7744 Btu/hp-hr, a site-rated horsepower value of 1680, and a fuel heat value of 1160 Btu/scf. Emission Factor Sources: CAS Pollutant Uncontrolled EFSource Controlled EF Source NOx Manufacturer Manufacturer CO Manufacturer Manufacturer VOC Manufacturer Manufacturer 5000 Formaldehyde AP-42; Table 3.2-3 (7/2000); Natural Gas No Control 75070 Acetaldehyde AP-42; Table 3.2-3 (7/2000); Natural Gas No Control AIRS ID: 123/9966 Page 19 of 28 t 4 Col, .o D •me o 'ublic Health and Environment Air Pollution Control Division CAS Pollutant Uncontrolled EFSource Controlled EF Source 107028 Acrolein AP-42; Table 3.2-3 (7/2000); Natural Gas No Control 71432 Benzene AP-42; Table 3.2-3 (7/2000); Natural Gas No Control Point 003,004: Emission Factors- Emission Factors— Uncontrolled Controlled CAS Pollutant lb/MMBtu g/bhp-hr lb/MMBtu g/bhp-hr NOx 3.659 13.0 0.084 0.30 CO 2.533 9.0 0.084 0.30 VOC 0.114 0.4 0.114 0.4 5000 Formaldehyde 2.05E-2 7.2E-2 2.05E-2 7.2E-2 75070 Acetaldehyde 2.7E-3 9.9E-3 2.7E-3 9.9E-3 107028 Acrolein 0.00263 9.3E-3 0.00263 9.3E-3 71432 Benzene 0.00158 5.6E-3 0.00158 5.6E-3 106990 1,3-Butadiene 0.000663 0.002 0.000663 0.002 Emission factors are based on a Brake-Specific Fuel Consumption Factor of 7832 Btu/hp-hr, a site-rated horsepower value of 1480, and a fuel heat value of 1160 Btu/scf. Emission Factor Sources: CAS Pollutant Uncontrolled EFSource Controlled EF Source NOx Manufacturer Manufacturer CO Manufacturer Manufacturer VOC Manufacturer Manufacturer 5000 Formaldehyde AP-42; Table 3.2-3 (7/2000); Natural Gas No Control 75070 Acetaldehyde AP-42; Table 3.2-3 (7/2000); Natural Gas No Control 107028 Acrolein AP-42; Table 3.2-3 (7/2000); Natural Gas No Control 71432 Benzene AP-42; Table 3.2-3 (7/2000); Natural Gas No Control Emission Factor Sources: CAS Pollutant Uncontrolled EFSource Controlled EF Source NOx Manufacturer Manufacturer CO Manufacturer Manufacturer VOC Manufacturer Manufacturer 5000 Formaldehyde AP-42; Table 3.2-3 (7/2000); Natural Gas No Control 75070 Acetaldehyde AP-42; Table 3.2-3 (7/2000); Natural Gas No Control 107028 Acrolein AP-42; Table 3.2-3 (7/2000); Natural Gas No Control 71432 Benzene AP-42; Table 3.2-3 (7/2000); Natural Gas No Control Point 009: The emission levels contained in this permit are based on the following emission factors: Emission Factors Emission Factors CAS# Pollutant Uncontrolled Controlled Source Ib/MMscf Natural lb/MMscf Natural Gas Throughput Gas Throughput VOC 29.97 0.29 VMGSim v7.0 71432 Benzene 1.02 0.01 VMGSim v7.0 108883 Toluene 0.14 0.0014 VMGSim v7.0 110543 n-Hexane 0.20 0.002 VMGSim v7.0 AIRS ID: 123/9966 Page 20 of 28 Col o D mer o Public Health and Environment Air Pollution Control Division Note: The controlled emissions factors for point 009 are based on the thermal oxidizer control efficiency of 99%. Point 010: Component Gas Service Heavy Oil Light Oil Water/Oil Service Connectors 1472 0 1844 0 Flanges 568 0 791 0 Open-ended Lines 62 0 87 0 Pump Seals 0 0 0 0 Valves 627 0 785 0 Other* 80 0 87 0 VOC Content(wt%) 33.8161903 100 100 100 Benzene Content(wt%) 8.73E-2 0 8.73E-2 0 Toluene Content(wt%) 4.08E-2 0 4.08E-2 0 Ethylbenzene (wt %) 3.05E-3 0 3.05E-3 0 Xylenes Content(wt%) 7.40E-3 0 7.40E-3 0 n-hexane Content(wt %) 0.495 0 0.495 0 *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 1.1E-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 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 analysis. Point 011: The emission levels contained in this permit are based on the following emission factors: CAS # Pollutant Pilot and make up fuel Source Emission Factor NOx 100 Ib/mmscf AP-42 Ch.1.4 CO 84 lb/mmscf AP-42 Ch.1.4 Waste Gas CAS# Pollutant Emission Factor Source NOx 0.068 lb/mmbtu AP-42 Ch.13.5 AIRS ID: 123/9966 Page 21 of 28 ikCole+o D ;rime o -ublic Health and Environment Air Pollution Control Division CAS# Pollutant Waste Gas Source Emission Factor CO 0.37 lb/mmbtu AP-42 Ch.13.5 The total emissions are based on the sum of the combustion emissions from the burner including supplemental fuel plus waste gas. Point 017: The emission levels contained in this permit are based on the following emission factors: CAS# Pollutant Pilot and make up fuel Source Emission Factor NOx 100 lb/mmscf AP-42 Ch.1.4 CO 84 lb/mmscf AP-42 Ch.1.4 CAS# Pollutant Waste Gas Source Emission Factor NOx 0.068 lb/mmbtu AP-42 Ch.13.5 CO 0.37 lb/mmbtu AP-42 Ch.13.5 Point 019: Uncontrolled Controlled CAS# Pollutant Emission Factors Emission Factors Source Ib/mmscf Ib/mmscf VOC 67.7104 0.5479 Promax 71432 Benzene 2.4133 0.0238 Promax 108883 Toluene 2.2399 0.0222 Promax 100414 Ethylbenzene 0.3614 0.0036 Promax 1330207 Xylene 0.9881 0.0099 Promax 110543 n-Hexane 1.2602 0.0105 Promax 6) In accordance with C.R.S. 25-7-114.1, each Air Pollutant Emission Notice (APEN) associated with this permit is valid for a term of five years from the date it was received by the Division. A revised APEN shall be submitted no later than 30 days before the five-year term expires. Please refer to the most recent annual fee invoice to determine the APEN expiration date for each emissions point associated with this permit. For any questions regarding a specific expiration date call the Division at (303)-692-3150. 7) Points 001-004: This engine is subject to 40 CFR, Part 60, Subpart JJJJ—Standards of Performance for Stationary Spark Ignition Internal Combustion Engines (See January 18, 2008 Federal Register posting — effective March 18, 2008). 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: http://www.epa.gov/ttn/atw/area/fr18ia08.pdf 8) Points 001-004: This engine is subject to 40 CFR, Part 63, Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines. (See January 18, 2008 Federal Register posting - effective March 18, 2008). The January 18, 2008 amendments to include requirements for area sources and engines < 500 hp located at major sources have not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 8. A copy of the complete subpart is available on the EPA website at: http://www.epa.ciov/ttn/atw/area/fr18ja08.pdf Additional information regarding area source standards can be found on the EPA website at: http://www.epa.gov/ttn/atw/area/arearules.html AIRS ID: 123/9966 Page 22 of 28 Col o D mer o Public Health and Environment Air Pollution Control Division 9) This facility is classified as follows: Applicable Status Requirement Operating Permit Synthetic Minor Source of: NOx, CO, VOC, benzene, toluene and total HAPs PSD Synthetic Minor Source of: NOx, CO, VOC MACT ZZZZ Area Source Requirements: Applicable 10) 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 63.1440-63.6175 Subpart QQQ—Subpart YYYY MACT 63.6580-63.8830 Subpart ZZZZ—Subpart MMMMM MACT 63.8980-End Subpart NNNNN—Subpart XXXXXX 11) An Oil and Gas Industry Construction Permit Self-Certification Form is included with this permit packet. Please use this form to complete the self-certification requirements as specified in the permit conditions. Further guidance on self-certification can be found on our website at: http://www.cdphe.state.co.us/ap/oilqaspermitting.html AIRS ID: 123/9966 Page 23 of 28 .'' Col a +o D !me o 'ublic Health and Environment 6 Air Pollution Control Division ATTACHMENT A: ALTERNATIVE OPERATING SCENARIOS RECIPROCATING INTERNAL COMBUSTION ENGINES October 12, 2012 2.Alternative Operating Scenarios The following Alternative Operating Scenario (AOS) for the temporary and permanent replacement of natural gas fired reciprocating internal combustion engines has been reviewed in accordance with the requirements of Regulation No. 3., Part A, Section IV.A, Operational Flexibility-Alternative Operating Scenarios, Regulation No. 3, Part B, Construction Permits, and Regulation No. 3, Part D, Major Stationary Source New Source Review and Prevention of Significant Deterioration, and it has been found to meet all applicable substantive and procedural requirements. This permit incorporates and shall be considered a Construction Permit for any engine replacement performed in accordance with this AOS, and the owner or operator shall be allowed to perform such engine replacement without applying for a revision to this permit or obtaining a new Construction Permit. 2.1 Engine Replacement The following AOS is incorporated into this permit in order to deal with a compressor engine breakdown or periodic routine maintenance and repair of an existing onsite engine that requires the use of either a temporary or permanent replacement engine. "Temporary" is defined as in the same service for 90 operating days or less in any 12 month period. "Permanent" is defined as in the same service for more than 90 operating days in any 12 month period. The 90 days is the total number of days that the engine is in operation. If the engine operates only part of a day, that day shall count as a single day towards the 90 day total. The compliance demonstrations and any periodic monitoring required by this AOS are in addition to any compliance demonstrations or periodic monitoring required by this permit. All replacement engines are subject to all federally applicable and state-only requirements set forth in this permit(including monitoring and record keeping). The results of all tests and the associated calculations required by this AOS shall be submitted to the Division within 30 calendar days of the test or within 60 days of the test if such testing is required to demonstrate compliance with NSPS or MACT requirements. Results of all tests shall be kept on site for five (5)years and made available to the Division upon request. The owner or operator shall maintain a log on-site and contemporaneously record the start and stop date of any engine replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number of the engine(s) that are replaced during the term of this permit, and the manufacturer, model number, horsepower, and serial number of the replacement engine. In addition to the log, the owner or operator shall maintain a copy of all Applicability Reports required under section 2.1.2 and make them available to the Division upon request. 2.1.1 The owner or operator may temporarily replace an existing compressor engine that is subject to the emission limits set forth in this permit with an engine that is of the same manufacturer, model, and horsepower or a different manufacturer, model, or horsepower as the existing engine without modifying this permit, so long as the temporary replacement engine complies with all permit limitations and other requirements applicable to the existing engine. Measurement of emissions from the temporary replacement engine shall be made as set forth in section 2.2. AIRS ID: 123/9966 Page 24 of 28 Col o D1iI10 Public Health and Environment Air Pollution Control Division 2.1.2 The owner or operator may permanently replace the existing compressor engine with another engine with the same manufacturer, model, and horsepower engines without modifying this permit so long as the permanent replacement engine complies with all permit limitations and other requirements applicable to the existing engine as well as any new applicable requirements for the replacement engine. Measurement of emissions from the permanent replacement engine and compliance with the applicable emission limitations shall be made as set forth in section 2.2. An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model and serial number and horsepower of the permanent replacement engine shall be filed with the Division for the permanent replacement engine within 14 calendar days of commencing operation of the replacement engine. The APEN shall be accompanied by the appropriate APEN filing fee, a cover letter explaining that the owner or operator is exercising an alternative operating scenario and is installing a permanent replacement engine, and a copy of the relevant Applicability Reports for the replacement engine. Example Applicability Reports can be found at http://www.cdphe.state.co.us/ap/oilgaspermitting.html. This submittal shall be accompanied by a certification from the Responsible Official indicating that"based on the information and belief formed after reasonable inquiry, the statements and information included in the submittal are true, accurate and complete". This AOS cannot be used for permanent engine replacement of a grandfathered or permit exempt engine or an engine that is not subject to emission limits. The owner or operator shall agree to pay fees based on the normal permit processing rate for review of information submitted to the Division in regard to any permanent engine replacement. 2.2 Portable Analyzer Testing Note: In some cases there may be conflicting and/or duplicative testing requirements due to overlapping Applicable Requirements. In those instances, please contact the Division Field Services Unit to discuss streamlining the testing requirements. Note that the testing required by this Condition may be used to satisfy the periodic testing requirements specified by the permit for the relevant time period (i.e. if the permit requires quarterly portable analyzer testing, this test conducted under the AOS will serve as the quarterly test and an additional portable analyzer test is not required for another three months). The owner or operator may conduct a reference method test, in lieu of the portable analyzer test required by this Condition, if approved in advance by the Division. The owner or operator shall measure nitrogen oxide (NOX) and carbon monoxide (CO) emissions in the exhaust from the replacement engine using a portable flue gas analyzer within seven (7) calendar days of commencing operation of the replacement engine. All portable analyzer testing required by this permit shall be conducted using the Division's Portable Analyzer Monitoring Protocol (ver March 2006 or newer) as found on the Division's web site at: http://www.Colorado.qov/cs/Satellite/CDPH E-AP/CBO N/1251596520270. Results of the portable analyzer tests shall be used to monitor the compliance status of this unit. For comparison with an annual (tons/year) or short term (lbs/unit of time) emission limit, the results of the tests shall be converted to a lb/hr basis and multiplied by the allowable operating hours in the month or year(whichever applies) in order to monitor compliance. If a source is not limited in its hours of operation the test results will be multiplied by the maximum number of hours in the month or year(8760), whichever applies. AIRS ID: 123/9966 Page 25 of 28 �. Cole:.+o D •me o 'ublic Health and Environment 6 Air Pollution Control Division For comparison with a short-term limit that is either input based (lb/mmBtu), output based (g/hp-hr) or concentration based (ppmvd @ 15% O2) that the existing unit is currently subject to or the replacement engine will be subject to, the results of the test shall be converted to the appropriate units as described in the above-mentioned Portable Analyzer Monitoring Protocol document. If the portable analyzer results indicate compliance with both the NOX and CO emission limitations, in the absence of credible evidence to the contrary, the source may certify that the engine is in compliance with both the NOX and CO emission limitations for the relevant time period. Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if the portable analyzer results fail to demonstrate compliance with either the NOX or CO emission limitations, the engine will be considered to be out of compliance from the date of the portable analyzer test until a portable analyzer test indicates compliance with both the NOX and CO emission limitations or until the engine is taken offline. 2.3 Applicable Regulations for Permanent Engine Replacements 2.3.1 Reasonably Available Control Technology (RACT): Reg 3, Part B § II.D.2 All permanent replacement engines that are located in an area that is classified as attainment/maintenance or nonattainment must apply Reasonably Available Control Technology (RACT) for the pollutants for which the area is attainment/maintenance or nonattainment. Note that both VOC and NOX are precursors for ozone. RACT shall be applied for any level of emissions of the pollutant for which the area is in attainment/maintenance or nonattainment, except as follows: In the Denver Metropolitan PM10 attainment/maintenance area, RACT applies to PM10 at any level of emissions and to NOX and SO2, as precursors to PM10, if the potential to emit of NOX or SO2 exceeds 40 tons/yr. For purposes of this AOS, the following shall be considered RACT for natural gas fired reciprocating internal combustion engines: VOC: The emission limitations in NSPS JJJJ CO: The emission limitations in NSPS JJJJ NOX: The emission limitations in NSPS JJJJ SO2: Use of natural gas as fuel PM10: Use of natural gas as fuel As defined in 40 CFR Part 60 Subparts GG (§60.331) and 40 CFR Part 72 (§ 72.2), natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. 2.3.2 Control Requirements and Emissidn Standards: Regulation No. 7, Sections XVI. and XVII.E (State- Only conditions). Control Requirements: Section XVI Any permanent replacement engine located within the boundaries of an ozone nonattainment area is subject to the applicable control requirements specified in Regulation No. 7, section XVI, as specified below: Rich burn engines with a manufacturer's design rate greater than 500 hp shall use a non- selective catalyst and air fuel controller to reduce emission. Lean burn engines with a manufacturer's design rate greater than 500 hp shall use an oxidation catalyst to reduce emissions. AIRS ID: 123/9966 Page 26 of 28 Col o D • me o ublic Health and Environment Air Pollution Control Division The above emission control equipment shall be appropriately sized for the engine and shall be operated and maintained according to manufacturer specifications. The source shall submit copies of the relevant Applicability Reports required under Condition 2.1.2. Emission Standards: Section XVII.E—State-only requirements Any permanent engine that is either constructed or relocated to the state of Colorado from another state, after the date listed in the table below shall operate and maintain each engine according to the manufacturer's written instructions or procedures to the extent practicable and consistent with technological limitations and good engineering and maintenance practices over the entire life of the engine so that it achieves the emission standards required in the table below: Construction or Emission Standards in G/hp-hr Max Engine HP Relocation Date NOX CO VOC January 1, 2008 2.0 4.0 1.0 100<Hp<500 January 1, 2011 1.0 2.0 0.7 July 1, 2007 2.0 4.0 1.0 500<Hp July 1, 2010 1.0 2.0 0.7 The source shall submit copies of the relevant Applicability Reports required under Condition 2.1.2. 2.3.3 NSPS for stationary spark ignition internal combustion engines: 40 CFR Part 60, Subpart JJJJ A permanent replacement engine that is manufactured on or after 7/1/09 for emergency engines greater than 25 hp, 7/1/2008 for engines less than 500 hp, 7/1/2007 for engines greater than or equal to 500 hp except for lean burn engines greater than or equal to 500 hp and less than 1,350 hp, and 1/1/2008 for lean burn engines greater than or equal to 500 hp and less than 1,350 hp are subject to the requirements of 40 CFR Part 60, Subpart JJJJ. An analysis of applicable monitoring, recordkeeping, and reporting requirements for the permanent engine replacement shall be included in the Applicability Reports required under Condition 2.1.2. Any testing required by the NSPS is in addition to that required by this AOS. Note that the initial test required by NSPS Subpart JJJJ can serve as the testing required by this AOS under Condition 2.2, if approved in advance by the Division, provided that such test is conducted within the time frame specified in Condition 2.2. Note that under the provisions of Regulation No. 6. Part B, section I.B. that Relocation of a source from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of Regulation No. 6 (i.e., the date that the source is first relocated to Colorado becomes equivalent to the manufacture date for purposes of determining the applicability of NSPS JJJJ requirements). However, as of October 1, 2011 the Division has not yet adopted NSPS JJJJ. Until such time as it does, any engine subject to NSPS will be subject only under Federal law. Once the Division adopts NSPS JJJJ, there will be an additional step added to the determination of the NSPS. Under the provisions of Regulation No. 6, Part B, § 1.8 (which is referenced in Part A), any engine relocated from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of NSPS JJJJ. 2.3.4 Reciprocating internal combustion engine (RICE) MACT: 40 CFR Part 63, Subpart ZZZZ A permanent replacement engine located at either an area or major source is subject to the requirements in 40 CFR Part 63, Subpart ZZZZ. An analysis of the applicable monitoring, recordkeeping, and reporting AIRS ID: 123/9966 Page 27 of 28 Col +o D� •„ me '_ o -ublic Health and Environment Air Pollution Control Division requirements for the permanent engine replacement shall be included in the Applicability Reports required under Condition 2.1.2. Any testing required by the MACT is in addition to that required by this AOS. Note that the initial test required by the MALT can serve as the testing required by this AOS under Condition 2.2, if approved in advance by the Division, provided that such test is conducted within the time frame specified in Condition 2.2. 2.4 Additional Sources The replacement of an existing engine with a new engine is viewed by the Division as the installation of a new emissions unit, not "routine replacement" of an existing unit. The AOS is therefore essentially an advanced construction permit review. The AOS cannot be used for additional new emission points for any site; an engine that is being installed as an entirely new emission point and not as part of an AOS- approved replacement of an existing onsite engine has to go through the appropriate Construction/Operating permitting process prior to installation. AIRS ID: 123/9966 Page 28 of 28 Summary of Preliminary Analysis - NG RICE Company Name Sterling Energy Investments LLC Permit No. 12WE2117 Facility Name Centennial Gas Plant AIRS 123/9966/002 Facility Location SESW S25 T9N R61W Review Date 12/10/2015 Facility Equipment ID C002 Permit Engineer Stephanie Spector Requested Action Request MOD-change permit limit Issuance No. 3 Emission Point Description One(1)Waukesha, Model L7044GS1, Serial Number C-13998/1, natural gas-fired,turbo-charged,4SRB reciprocating internal combustion engine, site rated at 1680 horsepower. This engine shall be equipped with a non-selective catalytic reduction (NSCR)system and air-fuel ratio control.This emission unit is used for primary and/or peaking power. Natural Gas Consumption Hours of Operation Requested (mmscf/yr) 98.25 PTE Calculated at(hpy) 8760 Requested(mmscf/m) 8.34 Permit limits calculated at(hpy) 8760 Fuel Heat Value(btu/scf) 1160 BSCF (Btu/hp-hr) 7744 Emission Factor Sources Uncontrolled Controlled NOx Manufacturer Manufacturer VOC Manufacturer Manufacturer CO Manufacturer Manufacturer Formaldehyde AP-42 AP-42 SOX AP-42;Table 3.2-3(7/2000);Natural Gas No Control TSP AP-42;Table 3.2-3(7/2000);Natural Gas No Control PM10 AP-42;Table 3.2-3(7/2000);Natural Gas No Control PM2.5 AP-42;Table 3.2-3(7/2000);Natural Gas No Control Other Pollutants AP-42 AP-42 Point Summary of Criteria Emissions(tpy) Uncontrolled Controlled Proposed Control Requested Requested PTE Efficiency NOx 215.8 4.3 215.8 98.0% VOC 6.5 6.5 6.5 0.0% CO 181.7 4.9 181.7 97.3% SOx 0.0 0.0 0.0 0.0% TSP 1.1 1.1 1.1 0.0% PM10 1.1 1.1 1.1 0.0% PM2.5 1.1 1.1 1.1 0.0% Total HAPs* 0.0 0.0 1.8 0.0% *Uncontrolled requested and controlled requested totals include HAPs only if the uncontrolled actual values are above de minim us thresholds. PTE includes all HAPs calculated, even those below de minim us. Point Summary of Hazardous Air Pollutants 'Ib/yr) Uncontrolled Controlled Proposed Control HAP Name Requested Requested PTE Efficiency Formaldehyde 2336 2336 2336 0.0% Methanol 349 349 349 0.0% Acetaldehyde 318 318 318 0.0% Acrolein 300 300 300 0.0% Benzene * * 180 0.0% 1,3-Butadiene * 76 0.0% Toluene * * 64 0.0% *Uncontrolled requested and controlled requested values are shown only for pollutants where REQUESTED UNCONTROLLED is greater than de minimus Permitting Requirements Ambient Air Impacts q Source is not required to model based on Division Guidelines Public Comment Public Commentrequired because of other points on facility-wide permit MACT ZZZZ Missing or invalid entry information over 500 HP located at a(n)Area Source Reg 7 XVII.E Standards NOx: NA CO: NA VOC: NA (g/hp-hr) Reg 7 XVI.B(Ozone NAA No requirements)applies? MACT ZZZZ(area source) Is this engine subject to MACT ZZZZ area Yes source requirements? Is this engine subject to NSPS JJJJ? TBD NSPS JJJJ Note:JJJJ requriements are not currently included as permit conditions because the reg has not been adopted into Reg 6. Comments/Notes 0 Summary of Preliminary Analysis - NG RICE Company Name Sterling Energy Investments LLC Permit No. 12WE2117 Facility Name Centennial Gas Plant AIRS 123/9966/003 Facility Location SESW S25 T9N R61W Review Date 12/10/2015 Facility Equipment ID G001 Permit Engineer Stephanie Spector Requested Action Request MOD-change permit limit Issuance No. 3 Emission Point Description One (1)Waukesha, Model L7042GS1, Serial Number 403170, natural gas-fired,turbo-charged,4SRB reciprocating internal combustion engine, site rated at 1480 horsepower. This engine shall be equipped with a non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. Natural Gas Consumption Hours of Operation Requested (mmscf/yr) 87.53 PTE Calculated at(hpy) 8760 Requested(mmscf/m) 7.43 Permit limits calculated at(hpy) 8760 Fuel Heat Value(btu/scf) 1160 BSCF (Btu/hp-hr) 7832 Emission Factor Sources Uncontrolled Controlled NOX Manufacturer Manufacturer VOC Manufacturer Manufacturer CO Manufacturer Manufacturer Formaldehyde AP-42 AP-42 SOX AP-42;Table 3.2-3(7/2000); Natural Gas No Control TSP AP-42;Table 3.2-3(7/2000), Natural Gas No Control PM10 AP-42;Table 3.2-3(7/2000); Natural Gas No Control PM2.5 AP-42;Table 3.2-3(7/2000); Natural Gas No Control Other Pollutants AP-42 AP-42 Point Summary of Criteria Emissions(tpy) Uncontrolled Controlled Proposed Control Requested Requested PTE Efficiency NOx 185.8 4.3 185.8 97.7% VOC 5.7 5.7 5.7 0.0% CO 128.6 4.3 128.6 96.7% SOx 0.0 0.0 0.0 0.0% TSP 1.0 1.0 1.0 0.0% PM10 1.0 1.0 1.0 0.0% PM2.5 1.0 1.0 1.0 0.0% Total HAPs" 0.0 0.0 1.6 0.0% *Uncontrolled requested and controlled requested totals include HAPs only if the uncontrolled actual values are above de minimus thresholds. PTE includes all HAPs calculated, even those below de minim us. Point Summary of Hazardous Air Pollutants (lb/yr) Uncontrolled Controlled Proposed Control HAP Name Requested Requested PTE Efficiency Formaldehyde 2082 2082 2082 0.0% Methanol 311 311 311 0.0% Acetaldehyde 283 283 283 0.0% Acrolein 267 267 267 0.0% Benzene * * 160 0.0% 1,3-Butadiene * * 67 0.0% Toluene 57 0.0% *Uncontrolled requested and controlled requested values are shown only for pollutants where REQUESTED UNCONTROLLED is greater than de minimus Permitting Requirements Ambient Air Impacts Source is not required to model based on Division Guidelines Public Comment Public Commentrequired because of other points on facility-wide permit MACT ZZZZ Missing or invalid entry information over 500 HP located at a(n)Area Source Reg 7 XVII.E Standards NOx: NA CO: NA VOC: NA (g/hp-hr) Reg 7 XVI.B(Ozone NAA No requirements)applies? MACT ZZZZ(area source) Is this engine subject to MACT ZZZZ area Yes source requirements? Is this engine subject to NSPS JJJJ? TBD NSPS JJJJ Note:JJJJ requriements are not currently included as permit conditions because the reg has not been adopted into Reg 6. Comments/Notes 0 Summary of Preliminary Analysis - NG RICE Company Name Sterling Energy Investments LLC Permit No. 12WE2117 Facility Name Centennial Gas Plant AIRS 123/9966/004 Facility Location SESW S25 T9N R61W Review Date 12/10/2015 Facility Equipment ID G002 Permit Engineer Stephanie Spector Requested Action Request MOD-change permit limit Issuance No. 3 Emission Point Description One(1)Waukesha, Model L7042GSl, Serial Number 403170, natural gas-fired, turbo-charged,4SRB reciprocating internal combustion engine, site rated at 1480 horsepower. This engine shall be equipped with a non-selective catalytic reduction (NSCR)system and air-fuel ratio control.This emission unit is used for natural gas compression. Natural Gas Consumption Hours of Operation Requested (mmscf/yr) 5.00 PTE Calculated at(hpy) 500 Requested(mmscf/m) 0.42 Permit limits calculated at(hpy) 500 Fuel Heat Value(btu/scf) 1160 BSCF (Btu/hp-hr) 7832 Emission Factor Sources Uncontrolled Controlled NOx Manufacturer Manufacturer VOC Manufacturer Manufacturer CO • Manufacturer Manufacturer Formaldehyde AP-42 AP-42 SOX AP-42;Table 3.2-3(7/2000);Natural Gas No Control TSP AP-42;Table 3.2-3(7/2000);Natural Gas No Control PM10 AP-42;Table 3.2-3(7/2000);Natural Gas No Control PM2.5 AP-42;Table 3.2-3(7/2000);Natural Gas No Control Other Pollutants AP-42 AP-42 Point Summary of Criteria Emissions(tpy) Uncontrolled Controlled Proposed Control Requested Requested PTE Efficiency NOx 10.6 0.2 10.6 97.7% VOC 0.3 0.3 0.3 0.0% CO 7.3 0.2 7.3 96.7% SOx 0.0 0.0 0.0 0.0% TSP 0.1 0.1 0.1 0.0% PM10 0.1 0.1 0.1 0.0% PM2.5 0.1 0.1 0.1 0.0% Total HAPs* 0.0 0.0 0.1 0.0% `Uncontrolled requested and controlled requested totals include HAPs only if the uncontrolled actual values are above de minimus thresholds. PTE includes all HAPs calculated, even those below de minim us. Point Summary of Hazardous Air Pollutants (Ib/yr) Uncontrolled Controlled Proposed Control HAP Name Requested Requested PTE Efficiency Formaldehyde * * 119 0.0% Methanol * * 18 0.0% Acetaldehyde * * 16 0.0% Acrolein * * 15 0.0% Benzene * * 9 0.0% 1,3-Butadiene * * 4 0.0% Toluene * * 3 0.0% *Uncontrolled requested and controlled requested values are shown only for pollutants where REQUESTED UNCONTROLLED is greater than de minimus Permitting Requirements Ambient Air Impacts Source is not required to model based on Division Guidelines Public Comment Public Commentrequired because of other points on facility-wide permit MACT Z777 Missing or invalid entry information over 500 HP located at a(n)Area Source Reg 7 XVII.E Standards NOx: NA CO: NA VOC: NA (g/hp-hr) Reg 7 XVI.B(Ozone NAA No requirements)applies? MACT ZZZZ(area source) Is this engine subject to MACT ZZZZ area Yes source requirements? Is this engine subject to NSPS JJJJ? TBD NSPS JJJJ Note:JJJJ requriements are not currently included as permit conditions because the reg has not been adopted into Reg 6. Comments/Notes 0 Summary of Preliminary Analysis - NG RICE Company Name Sterling Energy Investments LLC Permit No. 12WE2117 Facility Name Centennial Gas Plant AIRS 123/9966/014 Facility Location SESW S25 T9N R61W Review Date 12/10/2015 Facility Equipment ID C003 Permit Engineer Stephanie Spector Requested Action Request MOD-change permit limit Issuance No. 3 Emission Point Description One(1)Waukesha, Model L7044GS1, Serial Number C-13795, natural gas-fired,turbo-charged,4SRB reciprocating internal combustion engine, site rated at 1680 horsepower. This engine shall be equipped with a non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. Natural Gas Consumption Hours of Operation Requested (mmscf/yr) 98.25 PTE Calculated at(hpy) 8760 Requested(mmscf/m) 8.34 Permit limits calculated at(hpy) 8760 Fuel Heat Value(btu/scf) 1160 BSCF (Btu/hp-hr) 7744 Emission Factor Sources Uncontrolled Controlled NOx Manufacturer Manufacturer VOC Manufacturer Manufacturer CO Manufacturer Manufacturer Formaldehyde AP-42 AP-42 SOX AP-42;Table 3.2-3(7/2000); Natural Gas No Control TSP AP-42;Table 3.2-3(7/2000); Natural Gas No Control PM10 AP-42;Table 3.2-3(7/2000); Natural Gas No Control PM2.5 AP-42;Table 3.2-3(7/2000); Natural Gas No Control Other Pollutants AP-42 AP-42 Point Summary of Criteria Emissions(tpy) Uncontrolled Controlled Proposed Control Requested Requested PTE Efficiency NOx 215.8 4.9 215.8 97.7% VOC 6.5 6.5 6.5 0.0% CO 181.7 4.9 181.7 97.3% SOx 0.0 0.0 0.0 0.0% TSP 1.1 1.1 1.1 0.0% PM10 1.1 1.1 1.1 0.0% PM2.5 1.1 1.1 1.1 0.0% Total HAPs* 0.0 0.0 1.8 0.0% *Uncontrolled requested and controlled requested totals include HAPs only if the uncontrolled actual values are above de minimus thresholds. PTE includes all HAPs calculated, even those below de minimus. Point Summary of Hazardous Air Pollutants'Ib/yr) Uncontrolled Controlled Proposed Control HAP Name Requested Requested PTE Efficiency Formaldehyde 2336 2336 2336 0.0% Methanol 349 349 349 0.0% Acetaldehyde 318 318 318 0.0% Acrolein 300 300 300 0.0% Benzene * * 180 0.0% 1,3-Butadiene * * 76 0.0% Toluene * * 64 0.0% *Uncontrolled requested and controlled requested values are shown only for pollutants where REQUESTED UNCONTROLLED is greater than de minimus Permitting Requirements Ambient Air Impacts Source is not required to model based on Division Guidelines Public Comment Public Commentrequired because of other points on facility-wide permit MACT ZZZZ Missing or invalid entry information over 500 HP located at a(n)Area Source Reg 7 XVII.E Standards NOx: NA CO: NA VOC: NA (g/hp-hr) Reg 7 XVI.B(Ozone NAA No requirements)applies? MACT ZZZZ(area source) Is this engine subject to MACT Z777 area Yes source requirements? Is this engine subject to NSPS JJJJ? TBD NSPS JJJJ Note: JJJJ requriements are not currently included as permit conditions because the reg has not been adopted into Reg 6. Comments/Notes 0 Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Health and Environment Air Pollution Control Division Division Information Engineer: Stephanie Spector,PE Attainment Status Control Engineer: Chris Laplante( PM10 Attainment Review Date: 01/19/2016 PM2.5 Attainment Application Date: 08/05/2015 SOx Attainment NOx Attainment VOC Attainment Facility Information CO Attainment Permit No. 12WE2117 County# 123 Weld AIRs Facility# 9966 Point# 017 Facility Equipment ID Flare001 Company Name: Sterling Energy Investments LLC Source Name: Centennial Gas Plant Source Location: SESW S25 T9N R61W SIC: 1321 Elevation(feet)4941 New Permit Modificatio APEN (CP1) X n(Issuance Required/Permit 3) Exempt Transfer of APEN Ownership Exempt/Permit Exempt Notes Equipment Description This source vents natural gas from: a well head separator Emissions from this source are: routed to an open-flame flare Natural gas venting from a well head separator.Emissions from this source are routed to an open- flame flare. Emission Calculation Method EPA Emission Inventory Improvement Program Publication:Volume II,Chapter 10-Displacement Equation(10.4-3) Ex=Q*MW*Xx/C Ex=emissions of pollutant x Q=Volumetric flow rate/volume of gas processed MW=Molecular weight of gas=SG of gas*MW of air Xx=mass fraction of x in gas C=molar volume of ideal gas(379 scf/lb-mol)at 60F and 1 atm Throughput(O) 25.0 MMscf/yr* I 2853.9 scf/hr I 2.12 MMscf/mo MW 23.800 Ib/Ib-mol 0.001 MMscf/d `Total venting volume is 25 MMScf/yr. Operator is requesting a total throughput of this point of 27.5 mmscf/yr to include plant upsets,maintenance and truck loading vapors mole% MW Ibx/Ibmol mass fraction E lb/hr lb/yr tpy Helium 0.01 4.0026 0.000 0.000 Helium 0.0 26 0.01 CO2 2.86 44.01 1.259 0.053 CO2 9.5 83027 41.51 N2 1.03 28.013 0.289 0.012 N2 2.2 19033 9.52 methane 69.5175 16.041 11.151 0.469 methane 84.0 735574 367.79 ethane 11.9991 30.063 3.607 0.152 ethane 27.2 237948 118.97 propane 9.2601 44.092 4.0830 0.172 propane 30.7 269325 134.66 isobutane 0.8569 58.118 0.4980 0.021 isobutane 3.8 32850 16.43 n-butane 2.8311 58.118 1.6454 0.069 n-butane 12.4 108534 54.2( isopentane 0.474 72.114 0.3418 0.014 isopentane 2.6 22548 11.27 n-pentane 0.5937 72.114 0.4281 0.018 n-pentane 3.2 28241 14.12 cyclopentane 0.0444 70.13 0.0311 0.001 cyclopentane 0.2 2054 1.03 n-Hexane 0.1057 86.18 0.0911 0.004 n-Hexane 0.7 6009 3.00 cyclohexane 0.0000 84.16 0.0000 0.000 cyclohexane 0.0 0 0.00 Other hexanes 0.216 86.18 0.1861 0.008 Other hexanes 1.4 12279 6.14 heptanes 0.1049 100.21 0.1051 0.004 heptanes 0.8 6934 3.47 methylcyclohexane 0 98.19 0.0000 0.000 methylcyclohexane 0.0 0 0.00 224-TMP 0 114.23 0.0000 0.000 224-TMP 0.0 0 0.00 Benzene 0.0144 78.12 0.0112 0.000 Benzene 0.1 742 0.37 Toluene 0.008 92.15 0.0074 0.000 Toluene 0.1 486 0.24 Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Health and Environment Air Pollution Control Division Ethylbenzene 0.001 106.17 0.0011 0.000 Ethylbenzene 0.0 70 0.04 Xylenes 0.002 106.17 0.0021, 0.000 Xylenes 0.0 140 0.07 C8+Heavies 0.0462 134.559 0.0622 0.003 C8+Heavies 0.5 4101 2.05 VOC mass fraction: 0.3149 Total VOC Emissions(Uncontrolled) 247.2 23.800 annual limit assuming 95%control 12.4 Notes monthly limit assuming 95%control(lb/mo.) 2099.1 Mole%,MW,and mass fractions fromsite specific gas analysis collected March 18,2015 Emissions are based on 8760 hours of operation per year. I calculated the average MW of C8+based on the average MW on the analysis for the gas. Flaring Information for the purposes of determining a conservative flaring Equipment Description emission input,the calculations assume all truck loadout Flare to combust low-pressure separator gas during VRU downtime. vapors will be directed to the flare(in practice,truck Manufacturer TBD loadout vapors will be directed to a VRU and routed back Model TBD to the facility inlet). Serial Number TBD Gas Heating Value 1468 Btu/scf Uncontrolled loadout VOC emission: 51.7 TPY Throughput 40370 MMBtu/yr** **Throughput is based on the requested throughput of 27.5 MMscf/yr Total uncontrolled VOC emissions= 298.9 TPY Combustion emission factor source: AP-42:Chapter 13.5 Total controlled VOC emissions= 14.9 TPY 0.068 lb NOX/MMBtu 0.37 lb CO/MMBtu 1.37 tpy NOX 7.47 tpy CO Combustion emission factor source: AP-42:Chapter 1.4 100 lb NOX/MMscf 84 lb CO/MMscf 0.11 tpy NOX 0.09 tpy CO Emissions Summary 1.5 tpy NOX Uncontrolled/PTE 7.6 tpy CO 247.2 tpy VOC Controlled 12.4 tpy VOC Operator Operator Uncontrolled Emissions Scenario A Controlled Emissions Total(Ib/yr) (Ibtyr) Reportable? Total(Ib/yr) (Ib/yr) Benzene 742 740 Yes 37 37 Toluene 486 480 Yes 24 24 Ethylbenzene 70 60 No 4 3 Xylenes 140 140 No 7 7 n-hexane 6009 6000 Yes 300 300 224-TMP 0 0 No 0 0 Regulatory Applicability AQCC Regulation 1 This source is subject to the opacity requirements for flares in Section II.A.5:'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.' AQCC Regulation 2 Section I.A applies to all emission sources."No person,wherever located,shall cause or allow the emission of odorous air contaminants from any single source such as to result in detectable odors which are measured in excess of the following limits: For areas used predominantly for residential or commercial purposes it is a violation if odors are detected after the odorous air has been diluted with seven(7)or more volumes of odor free air." AQCC Regulation 3 An APEN is required for this source because uncontrolled VOC emissions Part A: exceed two tons per year in an attainment area. A permit is required for this source because uncontrolled VOC emissions from this facility exceed five tons per year in an attainment area. Part B: This source is not subject to Section III.D.2(Minor Source RACT)because it is not located in a nonattainment area. Is public comment Public Comment Required required? AQCC Regulation 7 Was the well newly constructed,hydraulically fractured,or recompleted on or after August 1,2014? Yes This separator is subject to Reg 7,Section XVII.G.and control requirements of Reg 7,XVII.B.2 Construction Permit Application Preliminary Analysis Summary Section 1 —Applicant Information Company Name: Sterling Energy Investments LLC Permit Number: 12WE2117 Centennial Gas Plant Source Location: SESE Section 25, 59N, R61W, Weld County (attainment) Equipment Description: TEG dehydrator AIRS ID: 123-9966-019 Date: March 8, 2016 Review Engineer: Stephanie Spector Control Engineer: Chris Laplante Section 2—Action Completed Grandfathered Modification APEN Required/Permit Exempt X CP3 Transfer of Ownership APEN Exempt/Permit Exempt Section 3—Applicant Completeness Review Was the correct APEN submitted for this source type? X Yes No Is the APEN signed with an original signature? X Yes No Was the APEN filled out completely? X Yes No Did the applicant submit all required paperwork? X Yes No Did the applicant provide ample information to determine emission rates? X Yes No If you answered"no" to any of the above, when did you mail an Information Request letter to the source? On what date was this application complete? January 19, 2016. I received revised calculations and APEN on 2/17/16. Section 4—Source Description AIRS Point Equipment Description One (1)Triethylene glycol (TEG) natural gas dehydration unit (J.W. Williams, model 375 MBtu/28 MMscfd, serial number: TBD)with a design capacity of 28 MMscf per day. This emissions unit is equipped with two (2) Rotor-Tech, model GS1104-E7.5.0TEFC, electric- 019 glycol pumps (one is a backup pump)with a design capacity of 5.0 gallons per minute each. This unit is equipped with a flash tank, reboiler and still vent. Stripping gas is injected into the reboiler. Emissions from the still vent are routed to a thermal oxidizer. Emissions from the flash tank are routed to the facility inlet stream in a closed loop system. Is this a portable source? Yes X No Is this location in a non-attainment area for any criteria Yes X No pollutant? If"yes", for what pollutant? PM,o CO Ozone Is this location in an attainment maintenance area for Yes X No any criteria pollutant? If"yes", for what pollutant? (Note: These pollutants are subject to minor source PM,o CO Ozone RACT per Regulation 3, Part B, Section III.D.2) Page 1 Is this source located in the 8-hour ozone non- attainment region?(Note: If"yes" the provisions of Yes X No Regulation 7, Sections XII and XVII.C may apply) Section 5—Emission Estimate Information AIRS Point Emission Factor Source 019 ProMax simulation model (Refer to Section 14 for calculations) Did the applicant provide actual process data for the emission inventory? X Yes No Basis for Potential to Emit(PTE) AIRS Point Process Consumption/Throughput/Production 019 10,220 MMSCF per year, 5.0 gallons per minute glycol circulation rate Basis for Actual Emissions Reported During this APEN Filing (Reported to Inventory) AIRS Point Process Consumption/Throughput/Production Data Year 019 10,220 MMSCF per year, 5.0 gallons per minute glycol circulation rate 2016 Basis for Permitted Emissions(Permit Limits) AIRS Point Process Consumption/Throughput/Production 019 10,220 MMSCF per year, 5.0 gallons per minute glycol circulation rate Does this source use a control device? X Yes No AIRS Point Process Control Device Description % Reduction Granted 019 01 Flash tank: Closed loop system (facility inlet stream) 100 019 01 Still vent: thermal oxidizer 99 Section 6—Emission Summary (tons per year) Point NO,, VOC CO Single HAP Total HAP PTE: 019 --- 346.0 --- 12.3 (Benzene) 37.1 Uncontrolled point 019 --- 346.0 --- 12.3 (Benzene) 37.1 source emission rate: Controlled point 019 --- 2.8 --- 0.12 (Benzene) 0.4 source emission rate: Section 7—Non-Criteria/ Hazardous Air Pollutants Uncontrolled Uncontrolled UncTotall Iled UncTotall Iled Are the Controlled Pollutant CAS# Emission Rate Emission Rate Emissions Emissions emissions Emission (lb/yr)-Flash Tank (lb/yr)-Still Vent (Ibtyr) (TPY) reportable? Rate(Ibtyr) Benzene 71432 413 24251 24664 12.3 Yes 243 Toluene 108883 219 22673 22892 11.4 Yes 227 Ethylbenzene 100414 25 3669 3694 1.8 Yes 37 Xylenes 1330207 48 10050 10098 5.0 Yes 101 n-Hexane 110543 2164 10715 12879 6.4 Yes 107 Note: Regulation 3, Part A, Section I1.B.3.b APEN emission reporting requirements for non-criteria air pollutants are based on potential emissions without credit for reductions achieved by control devices used by the operator. Page 2 Section 8—Testing Requirements Will testing be required to show compliance with any emission rate or regulatory Yes X No standard? If"yes", complete the information listed below AIRS Point Process Pollutant Regulatory Basis Test Method 019 01 VOC, Regulation No. 3, Part B., Section III.G.3 Stack Test HAPS 019 01 Visible Regulation No. 7, Section XVII.A.II Method 22 Emissions Section 9—Source Classification Is this a new previously un-permitted source? X Yes No What is this facility classification? True X Synthetic Major Minor Minor Classification relates to what programs? X Title V X PSD NA NSR X MACT Is this a modification to an existing permit? X Yes No If"yes"what kind of modification? Minor X Synthetic Major Minor Section 10—Public Comment Does this permit require public comment per CAQCC Regulation 3? X Yes No If"yes", for which pollutants?Why? VOC For Reg. 3, Part B, III.C.1.a (emissions increase > 25/50 tpy)? Yes X No For Reg. 3, Part B, III.C.1.c.iii (subject to MACT)? X Yes No For Reg. 3, Part B, III.C.1.d (synthetic minor emission limits)? X Yes No Section 11 —Modeling Is modeling required to demonstrate compliance with National Ambient Yes X No Air Quality Standards(NAAQS)? AIRS Point Section 12— Regulatory Review Regulation 1 - Particulate, Smoke, Carbon Monoxide and Sulfur Dioxide Section II.A.1 -Except as provided in paragraphs 2 through 6 below, no owner or operator of a source shall allow or cause the emission into the atmosphere of any air pollutant which 019 is in excess of 20% opacity. This standard is based on 24 consecutive opacity readings taken at 15-second intervals for six minutes. The approved reference test method for visible emissions measurement is EPA Method 9 (40 CFR, Part 60, Appendix A (July, 1992)) in all subsections of Section II. A and B of this regulation. Regulation 2—Odor Section I.A - No person, wherever located, shall cause or allow the emission of odorous air contaminants from any single source such as to result in detectable odors which are 019 measured in excess of the following limits: For areas used predominantly for residential or commercial purposes it is a violation if odors are detected after the odorous air has been diluted with seven (7)or more volumes of odor free air. Regulation 3-APENs, Construction Permits, Operating Permits, PSD Part A-APEN Requirements 019 Applicant is required to file an APEN since emissions exceed 2 tons per year VOC in an attainment area for ozone. Part B—Construction Permit Exemptions 019 Applicant is not required to obtain a permit since uncontrolled VOC emissions from this facility are greater than the 5.0 TPY threshold(Reg. 3, Part B, Section II.D.3.a) Regulation 6- New Source Performance Standards 019 None Page 3 Regulation 7—Volatile Organic Compounds Is this source subject to the control requirements of MACT HH? (Regulation 8-Hazardous Air Pollutants review). No Is this source subject to the exemptions under MACT HH (i.e. throughput exemption less 019 than 3 MMSCFD or benzene exemption of less than 1984 lb/yr)? Yes Even though this source is subject to some requirements of MACT HH, it is not subject to control requirements. Therefore, it can also be subject to Regulation 7 control requirements. Section XII.H: 019 Is this source located in the non-attainment area? No This source is not subject to this regulation. Section XVII.D(State only enforceable). 019 Applicant is required to reduce VOC emissions from this dehydrator by at least 90% since uncontrolled VOC emissions are greater than the 15.0 TPY threshold. gulatian 8—Hazardous Air Pollutants MACT HH: If facility is MAJOR source for HAP (summation of HAPS of dehydrators and fugitives greater than 25 TPY total or 10 TPY single HAP), then all glycol dehydrators at this facility are subject to MACT HH. If facility is an area source of HAP, only TEG dehydrators are subject to MACT HH. 1.Is facility a production field facility per 63.761 (Refer to Section 14 for definition)? No 2.If facility is NOT a production field facility (i.e. natural gas processing plant), then is it a 019 major source of HAPS when summing all HAP emissions from ALL HAP emitting units? No 3.Is this facility considered MAJOR for HAPS? No 4.Is this source subject to MACT HH?Yes 5.WHY? This facility is an area source of HAP and MACT HH area source requirements apply to this TEG dehydrator. However, since benzene emissions from each unit will be less 1984 Ib/yr, this source is only required to calculate and keep records demonstrating that benzene emissions stay below this level. Section 13—Aerometric Information Retrieval System Coding Information Point Process Process Throughput Emission Pollutant/ Fugitive Emission Control Description limit Factor CAS# (Y/N) Factor Source (%) 67.7104 VOC No Promax 99.2 Ibs/mmscf 2.4133 Benzene/ No Promax 97.6 Ibs/mmscf 71432 2.2399 Toluene/ 10,220 No Promax 96.8 01 Glycol MMSCF er Ibs/mmscf 108883 019 Dehydrator year P 0.3614 Ethylbenzene No Promax 94.4 Ibs/mmscf / 100414 0.9881 Xylenes/ No Promax 93.6 Ibs/mmscf 1330207 1.2602 n-Hexane/ No Promax 99.2 lbs/mmscf 110543 SCC 31000301 —Glycol dehydrators: reboiler still vent: Triethylene glycol Page 4 Section 14—Miscellaneous Application Notes AIRS Point 019 Glycol Dehydrator I emailed the consultant on 3/8/16 with some questions. He responded on 3/8/16 and his responses are in italics: 1. Could you please email me the information from Promax that includes the input. I want to verify what you entered into the model, not just want was generated from the model. I'll send over the input data in a few moments. I'm having a colleague pull that up now and it will take me a little bit to sort through all of the data. In order to get a more accurate representation of the inlet stream to the dehy system, we ran the simulation including the amine system. Do you want to see all of that data as well or just the inputs for the dehy model itself? 2. Also, did the NOx and CO emissions change with the revisions to the dehydrator? I am referring to the"Natural Gas Fuel Reboiler Emissions"calculation sheet in the original application. The NOx and CO emissions did not change with the revisions. For the initial calculations I used the max reboiler duty of 375 MBtu/hr. The modeled reboiler fuel consumption was 232 MBtu/hr for the initial app and increased to 278 MBtu/hr with the increased production. On the ProMax report flow diagram, there is a table on the bottom right of the diagram that shows the reboiler duty(Q Reboiler). 3. Also, shouldn't there be uncontrolled emissions coming from the flash tank? I understand they are in a closed loop system, but if there was no system,what would be the emissions coming from the flash tank? Is that also in the Promax model? I'll also include the flash tank outputs when I send the other data. In order to determine emissions,the operator used Promax simulation model. 100%of the emissions generated from the flash tank are routed back to the facility through the facility inlet stream. Only the still vent uncontrolled emissions will be routed to the thermal oxidizer with a destruction efficiency of 99%. I will require an initial test of the thermal oxidizer to confirm 99%control. Controlled emission factors are calculated only with the still vent emissions. Emissions from the thermal oxidizer(NOx and CO) are below APEN-reporting thresholds. The Promax model was based off of an extended gas analysis dated 3/18/15. The gas analysis was perfomed less than/greater than a year of submittal. An updated extended gas analysis will not be required because an extended gas analysis was performed within a year of this submittal and included with this package. Uncontrolled Emission factors Controlled Emission factors VOC =(346.0*2000)/(28"365) =67.7104 lb/mmscf VOC=(2.8*2000)/(28*365) =0.5479 lb/mmscf Benzene= (24664)/(28*365) =2.4133 lb/mmscf Benzene= (243)/(28*365)=0.0238 lb/mmscf Toluene= (22892)/(28'365)=2.2399 lb/mmscf Toluene= (227)/(28*365) =0.0222 lb/mmscf Ethylbenzene= (3694)/(28*365)=0.3614 lb/mmscf Ethylbenzene= (37)/(28*365) =0.0036 lb/mmscf Xylenes= (10098)/(28*365)=0.9881 lb/mmscf Xylenes= (101)/(28*365) =0.0099 lb/mmscf N-hexane= (12879)/(28*365) = 1.2602 lb/mmscf N-hexane= (107)/(28*365) =0.0105 lb/mmscf MACT HH includes requirements for both major and area sources of HAPs. The definition of major source for MACT HH (63.761)states: (3) For facilities that are production field facilities, only HAP emissions from glycol dehydration units and storage vessels with the potential for flash emissions shall be aggregated for a major source determination. For facilities that are not production field facilities, HAP emissions from all HAP emission units shall be aggregated for a major source determination. The following definitions from 63.761 are also needed to determine major source applicability: Production field facilities means those facilities located prior to the point of custody transfer Custody transfer means the transfer of hydrocarbon liquids or natural gas: after processing and/or treatment in the producing operations, or from storage vessels or automatic transfer facilities or other such equipment, including product loading racks, to pipelines or any other forms of transportation. For the purposes of this subpart, the point at which such liquids or natural gas enters a natural gas processing plant is a point of custody transfer. Natural gas processing plant(gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, or the fractionation of mixed NGL to natural gas products, or a combination of both. Based on the definitions above, this source qualifies as a natural gas processing plant. Does this dehydrator have a reboiler?Yes If Yes, what is the reboiler rated? 0.375 mmbtu/hr The source has a design rate less than 5 mmbtu/hr, therefore it is APEN-exempt(Regulation No. 3, Part A, ll.D.1.k), as well as exempt from construction permitting requirements(Regulation no. 3, Part B, II.D.1.a). Criteria pollutant emission levels for this unit are based on factors from AP-42, Chapter 1.4, Small Boilers< 100 MMBtu/hr(7/1998). Page 5 ti b Z . -O C G. . T y a) p c C o -1 V Q N GG 0 = o = Z o 0o n =! o y y W �I y o. I U N �.. 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