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Home My WebLink About20152728.tiff cDPHE ' COLORADO irN co Department of Public Health fr Environment Dedicated to protecting and improving the health and environment of the people of Colorado Weld County - Clerk to the Board 1150 0 St RECEIVED PO Box 758 Greeley, CO 80632 AUG 1 4 2015 August 11, 2015 WELD COUNTY COMMISSIONERS Dear Sir or Madam: On August 12, 2015, the Air Pollution Control Division will begin a 30-day public notice period for DCP Midstream - Mountain View Gas Plant. A copy of this public notice and the public comment packet are enclosed. Thank you for assisting the Division by posting a copy of this public comment packet in your office. Public copies of these documents are required by Colorado Air Quality Control Commission regulations. The packet must be available for public inspection for a period of thirty (30) days from the beginning of the public notice period. Please send any comment regarding this public notice to the address below. Colorado Dept. of Public Health Et Environment APCD-SS-B1 4300 Cherry Creek Drive South Denver, Colorado 80246-1530 Attention: Clara Gonzales Regards, Clara Gonzales Public Notice Coordinator Stationary Sources Program Air Pollution Control Division Enclosure S- 19 19-.2D/5- eC W; I L;)4L $'1� 2015-2728 4300 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 h+" A, CDPHE Air Pollution Control Division CC's . Notice of a Proposed Project or Activity Warranting Public Comment Website Title: DCP Midstream - Mountain View Gas Plant - Weld County Notice Period Begins: August 12, 2015 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: DCP Midstream, LP Facility: Mountain View Gas Plant Natural Gas Processing Plant SW, SEC 18, T4N, R64W Weld County The proposed project or activity is as follows: Applicant proposes construction of a new natural gas processing plant The Division has determined that this permitting action is subject to public comment per Colorado Regulation No. 3, Part B, Section III.C due to the following reason(s): • permitted emissions exceed public notice threshold values in Regulation No. 3, Part B, Section III.C.1.a (25 tpy in a non-attainment area and/or 50 tpy in an attainment area) • the source is requesting a federally enforceable limit on the potential to emit in order to avoid other requirements The Division has made a preliminary determination of approval of the application. A copy of the application, the Division's analysis, and a draft of Construction Permit 14WE1326 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: Christopher Kester Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South, APCD-SS-B1 Denver, Colorado 80246-1530 cdphe.commentsapcd@state.co.us eaa C xe OORRDO. 1 STATE OF COLORADO J.COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT T AIR POLLUTION CONTROL DIVISION *` TELEPHONE: (303) 692-3150 # 8 +*/876* CONSTRUCTION PERMIT PERMIT NO: 14YYE1326 Issuance 1 DATE ISSUED: ISSUED TO: DCP Midstream, LP THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS: Natural gas processing facility, known as the Mountain View Gas Plant, located in the SW Quarter of Section 18 of Township 4N, Range 64W THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING: Facility AIRS Description Equipment ID Point One (1) natural gas fired compression turbine (Make: Solar; Model: T70; SN: TBD) equipped with low NOX burners, site rated at 9,055 horsepower at 11,513 RPM. The turbine is TURB-1 001 design rated for a heat input of 72.73 MMBtu/hr at 60°F ambient temperature. The turbine will be equipped with a Waste Heat Recovery Unit (WHRU) System. This combustion turbine will be used to power a compressor. One (1) natural gas fired compression turbine (Make: Solar; Model: T70; SN: TBD) equipped with low NOX burners, site rated at 9,055 horsepower at 11,513 RPM. The turbine is TURB-2 002 design rated for a heat input of 72.73 MMBtu/hr at 60°F ambient temperature. The turbine will be equipped with a Waste Heat Recovery Unit (WHRU) System. This combustion turbine will be used to power a compressor. One (1) natural gas fired hot oil heater(Make: Optimized Process Furnaces, Inc.; Model: Custom (TBD); SN: TBD), HT-01 003 equipped with low NOXburners. The heater is design rated at a heat input of 44 MMBtu/hr. This heater is used to heat oil for several processes within the plant. One (1) natural gas fired regeneration heater (Make: Optimized Process Furnaces, Inc.; Model: Custom (TBD); HT-02 004 SN: TBD), equipped with low NOX burners. The heater is design rated at a heat input of 9.6 MMBtu/hr. This heater is used to provide regeneration heat. AIRS ID: 123/9D12 Page 1 of 40 NGEngine Version 2009-1 rlorado ,-pan �� 'alth and Environment 11 A P.'ution Control Division a Facility Equipment ID _ ' r r; • One (1) Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 230 MMscf/day (Make: TBD; Model: TBD; SN: TBD). This emissions unit is equipped with amine recirculation pumps with a total limited capacity of 945 gallons per minute of lean amine. This system includes a natural gas/amine contactor, reflux condenser, a flash tank, still vent, and an indirect fired hot oil (or waste heat from the AU-01 005 WHRU's) amine regeneration reboiler(point 003). The amine flash stream is routed to a closed loop system that utilizes a vapor recovery unit (maximum 5% annual downtime). Emissions during the downtime will be routed to a flare with 95% destruction efficiency. The acid gas stream from the still overheads is routed to a regenerative thermal oxidizer with a maximum of 3.6% annual downtime (Make: Anguil; Model: 150 RTO; SN: TBD) rated at 15,000 scf/min with a minimum destruction efficiency of 96%. One (1) Triethylene Glycol (TEG) dehydrator unit with a design capacity of 230 MMscfi/day (Make: TBD; Model: TBD; SN: TBD). This emissions unit is equipped with electric glycol pumps with a limited total combined capacity of 40 gallons per minute. This system includes a condenser, reboiler, still vent, and a flash tank. This system is permitted with 40 scfm of stripping gas. The flash gas is routed to a D-01 006 closed loop system that utilizes a vapor recovery unit (maximum 5% annual downtime). Emissions during the downtime will be routed to a flare with a minimum 95% destruction efficiency. The still vent emissions are routed to a condenser and then to an enclosed combustor with a minimum destruction efficiency of 95%. The primary enclosed combustor is equipped with a backup enclosed combustor. Four(4) 1,000 bbl stabilized condensate fixed-roof storage tanks. Emissions from the tanks are routed to an enclosed Tanks 007 combustor with a minimum destruction efficiency of 95%. The primary enclosed combustor is equipped with a backup enclosed combustor. Truck loading of stabilized condensate. Emissions from the loadout will be routed to an enclosed combustor with a LOAD 008 minimum destruction efficiency of 95%. The primary enclosed combustor is equipped with a backup enclosed combustor. FUG 011 Fugitive emission component leaks from this natural gas processing plant. Points 001 and 002 may be replaced with another like-kind turbine in accordance with the temporary turbine replacement provision or with another Solar Model Taurus 70 turbine in AIRS ID: 123/9D12 Page 2 of 40 alorado -part A - alth and Environment '' P. ution Control Division accordance with the irma Pnt -pl - - pr. :;sio .f he AI nate Operating Scenario (AOS), included in t . a ;c: 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 APCD no later than fifteen days after commencement of the permitted operation or activity by submitting a Notice of Startup (NOS) form to the APCD. The Notice of Startup (NOS) form may be downloaded online at www.cdphe.state.co.us/ap/downloadforms.html. Failure to notify the APCD of startup of the permitted source is a violation of AQCC Regulation No. 3, Part B, Section I II.G.1 and can result in the revocation of the permit. 2. Within one hundred and eighty days (180) after commencement of operation, compliance with the conditions contained on this permit shall be demonstrated to the Division. It is the permittee's responsibility to self-certify compliance with the conditions. Failure to demonstrate compliance within 180 days 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.) 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 manufacturer, model number and serial number of the subject equipment shall be provided to the Division within fifteen days (15) after commencement of operation. This information shall be included on the Notice of Startup (NOS) submitted for the equipment. (Reference: Regulation No. 3, Part B, III.E.) 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) AIRS ID: 123/9D12 Page 3 of 40 D.lorado -part . alth and Environment , iP. ution Control Division Monthly Limits' Facility Al_ Emission Equipment Point Type ID NOX VOC CO SO2 PM2.5 H2S TURB-1 001 2,552 114 2,991 184 357 -- Point TURB-2 002 2,552 114 2,991 184 357 -- Point AU-01 005 240 2,852 1,307 5,351 -- 225 Point D-01 006 259 4,337 1,415 -- -- -- Point Tanks 007 14 513 75 -- -- -- Point LOAD 008 21 785 114 -- -- -- Point FUG 011 -- 3,560 -- -- -- -- Fugitive ' Monthly limits are based on a 31-day month. Quarterly Limits2: Facility AIRS Pounds per Quarter Emission Equipment ID Point Type VOC CO SO2 PM2.5 H2S Type HT-01 003 2,309 342 5,244 37 311 --- Point HT-02 004 663 97 1,498 10 87 --- Point 2 Upon startup of the Facility,quarterly limits shall be established at the beginning of the calendar quarter. For the first twelve(12)months of operation,monthly emissions from the three calendar months of a quarter shall be summed to demonstrate compliance with the quarterly emission limits for AIRS Point 003 and 004 as well as annual limitations. After the first twelve(12)months of operation,the operator shall calculate monthly emissions to demonstrate compliance with the annual limits and to maintain the 12-month rolling total. Annual Limits: Facility AIRS Tons per Year Emission Equipment ID Point NOX VOC CO SO2 PM2.5 H2S Type TURB-1 001 15.0 0.7 17.6 1.1 2.1 --- Point TURB-2 002 15.0 0.7 17.6 1.1 2.1 --- Point HT-01 003 4.5 0.7 10.3 0.1 0.6 --- Point HT-02 004 1.3 0.2 3.0 0.1 0.2 --- Point AU-01 005 1.4 16.8 7.7 31.5 --- 1.4 Point D-01 006 1.5 25.5 8.3 --- --- --- Point AIRS ID: 123/9D12 Page 4 of 40 73lorado epart alth and Environment P ution Control Division Tanks 00 , .0 0- - Point • LOAD 008 0.1 4.6 0.7 --- --- Point FUG 011 --- 21.0 --- --- --- Fugitive See "Notes to Permit Holder #4 for information on emission factors and methods used to calculate limits. During the first twelve (12) months of operation, compliance with the monthly, quarterly and yearly emission limitations is required. After the first twelve (12) months of operation, compliance with only the yearly limitation is required. Compliance with the emission limits in this permit shall be determined by recording the facility's annual criteria pollutant emissions (including all HAPs above the de- minimis reporting level) from each emission unit, on a rolling (12) month total. By the end of each month, a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate monthly emissions and keep a compliance record on site or at a local field office with site responsibility, for Division review. This rolling twelve-month total shall apply to all emission units, requiring an APEN, at this facility. 8. 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 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 not exceed: • 100 tons per year of any criteria pollutant and/or • 10 tons per year of a single hazardous air pollutant (HAP) and/or • 25 tons per year of total hazardous air pollutants (HAP). 9. Point 005: Compliance with the emission limits in this permit shall be demonstrated by running the Promax model on a monthly basis using the most recent amine unit inlet extended sour gas analysis and recorded operational values (including plant inlet gas throughput, lean amine recirculation rate, lean amine strength, VRU downtime and other operational values specified in the O&M Plan). Recorded operational values, except for plant inlet gas throughput, shall be averaged on a monthly basis for input into Promax. 10. Point 005: Emissions from the amine flash tank are routed to a closed loop vapor recovery system back to the plant inlet equipped with a vapor recovery unit (VRU) (5% maximum allowable downtime). During the VRU downtime, emissions generated shall be routed to the flare. Emissions from the still overheads shall be collected and controlled by a regenerative thermal oxidizer (3.6% maximum allowable downtime) in AIRS ID: 123/9D12 Page 5 of 40 ,Iorado -part �' . . . alth� and Environment A. i P•''`ution Control Division order to reduc ; - si s vol. le o ani• ompoun ., H2S, and hazardous air pollutants to • li - i - ec ' e. • ting parameters of the regenerative thermal oxidizer are identified in the O&M plan for this unit. (Reference: Regulation No.3, Part B, Section III.E.) 11. Point 006: Compliance with the emission limits in this permit shall be demonstrated by running the GRI GlyCalc model version 4.0 or higher on a monthly basis using the most recent 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 GRI GlyCalc and be provided to the Division upon request. 12. Point 008: All loading operations shall occur in vapor balance service, such that all tanker truck vapors are routed to and controlled by the enclosed combustor. The vapor return hose shall be connected at all times during loading operations. (Reference: Regulation No. 3, Part B, Section III.E.) 13. Point 011: The operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent gas analyses, as required in the Compliance Testing and Sampling section of this permit. The operator shall maintain records of the results of component counts and sampling events used to calculate actual emissions and the dates that these counts and events were completed. These records shall be provided to the Division upon request. 14. 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 VRU (closed loop)and backup flare during VRU VOC, H2S, & downtime to control flash tank HAP AU-01 005 Regenerative Thermal Oxidizer to control Acid VOC, H2S, & Gas stream HAP VRU (closed loop)and backup flare during VRU VOC & HAP D-01 006 downtime to control flash tank Enclosed Combustor to control still vent VOC & HAP Tanks 007 Enclosed Combustor VOC & HAP LOAD 008 Enclosed Combustor VOC & HAP FUG 011 NSPS OOOO LDAR VOC & HAP PROCESS LIMITATIONS AND RECORDS 15. 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 AIRS ID: 123/9D12 Page 6 of 40 lorado Depart c alth and Environment P . ution Control Division applicant and de a , ila t he vise for 'spection. on request. (Reference: Regulation 3, I.A \ ., Process/Consumption Limits Facility AIRS Monthly Limits(31 Equipment Point Process Parameter Annual Limit days) ID TURB-1 001 Natural Gas Combusted 637.9 MMscf/yr 54.2 MMscf/month TURB-2 002 Natural Gas Combusted 637.9 MMscf/yr 54.2 MMscf/month AU-01 005 Natural Gas Processed 83,950 MMscf/yr 7,130 MMscf/month D-01 006 Natural Gas Processed 83,950 MMscf/yr 7,130 MMscf/month Tanks 007 Condensate Throughput 912,500 bbl/yr 77,500 bbl/month LOAD 008 Condensate Throughput 912,500 bbl/yr 77,500 bbl/month Facility AIRS Equipment Point Process Parameter Annual Limit Quarterly Limits3 ID HT-01 003 Natural Gas Combusted 245 MMscf/yr 62.4 MMscf/quarter HT-02 004 Natural Gas Combusted 70 MMscf/yr 17.8 MMscf/quarter 3 Upon startup of the Facility,quarterly limits shall be established at the beginning of the calendar quarter. During the first twelve (12) months of operation, compliance with the monthly, quarterly and yearly emission limitations shall be required. After the first twelve (12) months of operation, compliance with only the yearly limitation shall be required. Compliance with the yearly process 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, monitor, and record monthly natural gas combusted, natural gas vented, natural gas processed, condensate throughput, and produced water throughput and keep a compliance record on site or at a local field office with site responsibility, for Division review. 16. Point 005: This unit shall be limited to a maximum lean amine recirculation pump rate of 945 gallons per minute. The lean 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, II.A.4). 17. Point 006: This source shall be limited to a maximum lean glycol recirculation pump rate as calculated per 40 CFR, Part 63, Subpart HH, §63.764 (d)(2)(i). If the owner or operator requests an alternate circulation rate per §63.764(d)(2)(ii) or an exemption per §63.764(e), then the maximum recirculation rate shall not exceed 40 gallons per AIRS ID: 123/9D12 Page 7 of 40 jlorado ;-part . u alth and Environment A P. ution Control Division minute. The o :_ er or pe a,;to all ain n w -kly reco of the actual lean glycol recirculation r , ' a .bl: 4.vision � :z. spection upon request. 18. Points 005 & 006: The owner or operator shall monitor and record VRU downtime for each emission point. VRU downtime shall be defined as times when the flash gas from the amine unit and the dehydrator are routed to the flare rather than the VRU. The total hours of downtime and volume of gas processed during VRU downtime shall be recorded on a monthly basis. The operator shall demonstrate VRU downtime for each emission point does not exceed 1% of total operational hours and total volume of gas processed on a rolling 12 month total basis. 19. Point 008: Condensate loading to truck tanks shall be conducted by submerged fill. (Reference: Regulation 3, Part B, III.E) STATE AND FEDERAL REGULATORY REQUIREMENTS 20. The permit number and AIRS ID number shall be marked on the subject equipment for ease of identification. (Reference: Regulation Number 3, Part B, III.E.) (State only enforceable). 21. Visible emissions 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. (Reference: Regulation No. 1, Section II.A.1. &4.) 22. No owner or operator of a smokeless flare or other flare for the combustion of waste gases shall allow or cause emissions into the atmosphere of any air pollutant which is in excess of 30% opacity for a period or periods aggregating more than six minutes in any sixty consecutive minutes. (Reference: Regulation No. 1, Section I I.A.5.) 23. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable) 24. This source is located in an ozone non-attainment or attainment-maintenance area and subject to the Reasonably Available Control Technology (RACT) requirements of Regulation Number 3, Part B, III.D.2. The following requirements were determined to be RACT for this source. Facility AIRS Equipment Point Pollutant RACT ID TURB-1 001 NOx, VOC Natural gas as fuel, low NOx burners, good combustion practices TURB-2 002 NOx, VOC Natural gas as fuel, low NOx burners, good combustion practices HT-01 003 NOx, VOC Natural gas as fuel, low NOx burners, good combustion practices. HT-02 004 NOx, VOC Natural gas as fuel, low NOx burners, good combustion practices. AIRS ID: 123/9D12 Page 8 of 40 g lorado :'-part a `¢ alth and Environment P. ution Control Division APR , r'a •C ash '.nk RU to in t and downtime to flare AU-01 St . egene a Thermal Oxidizer Flash Tank: VRU to inlet and downtime to flare D-01 006 VOC, HAP Still Vent: Condenser and enclosed combustor TANKS 007 VOC, HAP Enclosed combustor LOAD 008 VOC, HAP Submerged fill, vapor balance service, enclosed combustor FUG 011 VOC LDAR per 40 C.F.R. Part 60, Subpart OOOO 25. Points 001, 002, 003, 005, 007, 011: These sources are subject to the requirements of Regulation No. 6, Part A, Subpart A, General Provisions, including, but not limited to, the following: a. At all times, including periods of start-up, shutdown, and malfunction, the facility and control equipment shall, to the extent practicable, be maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. Determination of whether or not acceptable operating and maintenance procedures are being used will be based on information available to the Division, which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. (Reference: Regulation No. 6, Part A. General Provisions from 40 CFR 60.11) b. No article, machine, equipment or process shall be used to conceal an emission which would otherwise constitute a violation of an applicable standard. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve compliance with an opacity standard or with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere. (§ 60.12) c. Written notification of construction and initial startup dates shall be submitted to the Division as required under§ 60.7. d. Records of startups, shutdowns, and malfunctions shall be maintained, as required under§ 60.7. e. Performance tests shall be conducted as required under§60.8. AIRS ID: 123/9D12 Page 9 of 40 .. 0'Iorado -part • r alth and Environment A A P•`ution Control Division Turbines 26. Points 001 and 002: The owner or operator shall not emit sulfur dioxide in excess of the following limitations. (Heat input rates shall be the manufacturer's guaranteed maximum heat input rates). (Regulation 1, Section VI.B) (1) Combustion Turbines with a heat input of less than 250 Million BTU per hour: 0.8 pounds of sulfur dioxide per million BTU of heat input (Regulation 1, Section VI.B.4.c) 27. Points 001 and 002: These units are subject to the New Source Performance Standards requirements of Regulation 6, Part B including, but not limited to, the following (Regulation 6, Part B, Section II): a. Standard for Particulate Matter — On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere of any particulate matter which is: (i) For fuel burning equipment generating greater than one million but less than 250 million Btu per hour heat input, the following equation will be used to determine the allowable particulate emission limitation: PE=0.5(Fl)-°26 Where: PE is the allowable particulate emission in pounds per million Btu heat input. Fl is the fuel input in million Btu per hour. (ii) Greater than 20 percent opacity. 28. Points 001 and 002: The combustion turbines are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart KKKK, Standards of Performance for Stationary Combustion Turbines including, but not limited to, the following: • §60.4320—Nitrogen Oxide Emissions Limits o (a) NOx emissions shall not exceed 25 ppm at 15% O2 or 1.2 lb/MW-hr; • §60.4330-Sulfur Dioxide Emissions Limits o (a)(1) SO2 emissions shall not exceed 0.9 lb/MW-hr gross output; or o (a)(2) Operator shall not burn any fuel that contains total potential sulfur emissions in excess of 0.060 lb SO2/MMBtu heat input. • §60.4333—General Requirements o (a) Operator must operate and maintain stationary combustion turbine, air pollution control equipment, and monitoring equipment in a manner AIRS ID: 123/9D12 Page 10 of 40 lorado -party , ,t alth and Environment Pallution Control Division consis m goy: a'r,eoll x on •.` trol practices vr minimizing emissions at IF all ti _ .v I pdline, 'Hs ins, 1 p, ;.4. $ •.9 and m h, nction. • §60.4340—NO, Monitoring o (a) If you are not using water or steam injection to control NOX emissions, you must perform annual performance tests in accordance with §60.4400 to demonstrate continuous compliance. If the NOX emission result from the performance test is less than or equal to 75 percent of the NOX emission limit for the turbine, you may reduce the frequency of subsequent performance tests to once every 2 years (no more than 26 calendar months following the previous performance test). If the results of any subsequent performance test exceed 75 percent of the NOX emission limit for the turbine, you must resume annual performance tests. • §60.4365 (or§§60.4360 and 60.4370)-SO2 Monitoring o The operator shall comply with §60.4365 or with both §§60.4360 and 60.4370 to demonstrate compliance with SO2 emissions limits. • §60.4375—Reporting o (b) For each affected unit that performs annual performance tests in accordance with §60.4340(a), you must submit a written report of the results of each performance test before the close of business on the 60th day following the completion of the performance test. • §§60.4400 and 60.4415— Performance Tests o Annual tests must be conducted in accordance with §60.4400(a) and (b). o Unless operator chooses to comply with §60.4365 for exemption of monitoring the total sulfur content of the fuel, then initial and subsequent performance tests for sulfur shall be conducted according to §60.4415. b. Standard for Sulfur Dioxide — On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere sulfur dioxide in excess of: (i) Sources with a heat input of less than 250 million Btu per hour: 0.8 lbs. SO2/million Btu. Heaters 29. Points 003 and 004: The owner or operator shall not emit sulfur dioxide in excess of the following limitations. (Heat input rates shall be the manufacturer's guaranteed maximum heat input rates). (Regulation 1, Section VI.B) (1) Limit emissions to not more than two (2) tons per day of sulfur dioxide (Regulation 1, Section VI.B.5.a) AIRS ID: 123/9D12 Page 11 of 40 lorado a3-part alth and Environment AA z: P. ution Control Division k�e 30. Points 003 an. 004: e u ar= -ubj. t to e ew S rce Performance Standards re, -�; `s �'` -g�_x�• _.:•, 'a y uding of limited to, the following (Regulation 6, Part B, Section II): c. Standard for Particulate Matter — On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere of any particulate matter which is: (i) For fuel burning equipment generating greater than one million but less than 250 million Btu per hour heat input, the following equation will be used to determine the allowable particulate emission limitation: PE=0.5(FI)-o.26 Where: PE is the allowable particulate emission in pounds per million Btu heat input. Fl is the fuel input in million Btu per hour. (ii) Greater than 20 percent opacity. 31. Point 003: This source is subject to the New Source Performance Standards requirements of Regulation No. 6, Part A Subpart Dc, Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units including, but not limited to, the following: a. The owner or operator of the facility shall record and maintain records of the amount of fuel combusted during each month (40 CFR Part 60.48c(g)). b. Monthly records of fuel combusted required under the previous condition shall be maintained by the owner or operator of the facility for a period of two years following the date of such record (40 CFR Part 60.48c(i)). Amine Sweetening Unit 32. Point 005: 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 AIRS ID: 123/9D12 Page 12 of 40 lorado part" -a alth and Environment P ution Control Division o §60.54 (c) - °o rti hat fac is empt fro the control requirements of th ar r _ 1 cili esign city less than 2 LT/D of H2S 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. TEG Dehydrator 33. Point 006: This unit is subject to the requirements in 40 CFR part 63 Subpart A "General Provisions", as adopted by reference in Colorado Regulation No. 8, Part E, Section I as specified in 40 CFR Part 63 Subpart HH § 63.764. These requirements include, but are not limited to the following: a. Prohibited activities and circumvention in § 63.4. b. Operation and maintenance requirements in § 63.6(e)(1). c. Notification requirements in § 63.9(j). d. Recordkeeping and reporting requirements in § 63.10(b), except as provided in § 63.774(b)(1). 34. Point 006: This source is subject to the TEG dehydrator area source 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: • §63.760—Applicability and designation of affected source o (f) The owner or operator of an affected major source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(1) and (f)(2) of this section. The owner or operator of an affected area source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(3) through (f)(6) of this section. • (4) The owner or operator of an affected area source, located in an Urban-1 county, as defined in §63.761, the construction or reconstruction of which commences on or after February 6, 1998, shall achieve compliance with the provisions of this subpart p p immediately upon initial startup or January 3, 2007, whichever date is later. • §63.764 - General Standards o (d)(2) Each owner or operator of an area source not located in a UA plus offset and UC boundary (as defined in §63.761) shall comply with the provisions specified in paragraphs (d)(2(i) through (iii) of this section. • (i) Determine the optimum glycol circulation rate using the following equation: AIRS ID: 123/9D12 Page 13 of 40 g . <.lorado -part • aith and Environment A ' P.''ution Control Division LAIL.0 _ IL , $ 21: . rim, Where: LoPT = Optimal circulation rate, gal/hr. F = Gas flowrate (MMSCF/D) I = Inlet water content(Ib/MMSCF) O = Outlet water content(Ib/MMSCF) 3.0 = The industry accepted rule of thumb for a TEG-to water ratio (gal TEG/IbH2O) 1.15 = Adjustment factor included for a margin of safety. • (ii) Operate the TEG dehydration unit such that the actual glycol circulation rate does not exceed the optimum glycol circulation rate determined in accordance with paragraph (d)(2)(i) of this section. If the TEG dehydration unit is unable to meet the sales gas specification for moisture content using the glycol circulation rate determined in accordance with paragraph (d)(2)(i), the owner or operator must calculate an alternate circulation rate using GRI—GLYCalcTM, Version 3.0 or higher. The owner or operator must document why the TEG dehydration unit must be operated using the alternate circulation rate and submit this documentation with the initial notification in accordance with §63.775(c)(7). • (iii) Maintain a record of the determination specified in paragraph (d)(2)(ii) in accordance with the requirements in §63.774(f) and submit the Initial Notification in accordance with the requirements in §63.775(c)(7). If operating conditions change and a modification to the optimum glycol circulation rate is required, the owner or operator shall prepare a new determination in accordance with paragraph (d)(2)(i) or (ii) of this section and submit the information specified under §63.775(c)(7)(ii) through (v). • §63.774 - Recordkeeping Requirements o (b) Except as specified in paragraphs (c), (d), and (f) of this section, each owner or operator of a facility subject to this subpart shall maintain the records specified in paragraphs (b)(1)through (11) of this section: • (1) The owner or operator of an affected source subject to the provisions of this subpart shall maintain files of all information (including all reports and notifications) required by this subpart. The files shall be retained for at least 5 years following the date of each occurrence, measurement, maintenance, corrective action, report or period. • (i)All applicable records shall be maintained in such a manner that they can be readily accessed. AIRS ID: 123/9D12 Page 14 of 40 :a "In brad o : epart `- alth and Environment 1-1 Vo P ution Control Division • , ii) e 'ost cen 2 nths of r bords shall be retained on ▪ Si s acs OM a eal location by computer or other means that provides access within 2 hours after a request. • (iii) The remaining 4 years of records may be retained offsite. • (iv) Records may be maintained in hard copy or computer- readable form including, but not limited to, on paper, microfilm, computer, floppy disk, magnetic tape, or microfiche. o (f) The owner or operator of an area source not located within a UA plus offset and UC boundary must keep a record of the calculation used to determine the optimum glycol circulation rate in accordance with §63.764(d)(2)(i) or§63.764(d)(2)(ii), as applicable. • §63.775— Reporting Requirements o (c) Except as provided in paragraph (c)(8), each owner or operator of an area source subject to this subpart shall submit the information listed in paragraph (c)(1) of this section. If the source is located within a UA plus offset and UC boundary, the owner or operator shall also submit the information listed in paragraphs (c)(2) through (6) of this section. If the source is not located within any UA plus offset and UC boundaries, the owner or operator shall also submit the information listed within paragraph (c)(7). ■ (1) The initial notifications required under §63.9(b)(2) not later than January 3, 2008. In addition to submitting your initial notification to the addressees specified under §63.9(a), you must also submit a copy of the initial notification to EPA's Office of Air Quality Planning and Standards. Send your notification via e-mail to CCG— ONG@EPA.GOV or via U.S. mail or other mail delivery service to U.S. EPA, Sector Policies and Programs Division/Coatings and Chemicals Group (E143—01), Attn: Oil and Gas Project Leader, Research Triangle Park, NC 27711. ■ (7) The information listed in paragraphs (c)(1)(i) through (v) of this section. This information shall be submitted with the initial notification. • (i) Documentation of the source's location relative to the nearest UA plus offset and UC boundaries. This information shall include the latitude and longitude of the affected source; whether the source is located in an urban cluster with 10,000 people or more; the distance in miles to the nearest urbanized area boundary if the source is not located in an urban cluster with 10,000 people or more; and the names of the nearest urban cluster with 10,000 people or more and nearest urbanized area. AIRS ID: 123/9D12 Page 15 of 40 0'Iorado ,-part ., ..alth and Environment AP. ution Control Division ii) S cul.,uon t optimu glycol circulation rate d "in - c•_ s 'th §6 •(d)(2)(i). • (iii) If applicable, documentation of the alternate glycol circulation rate calculated using GRI-GLYCalcTM, Version 3.0 or higher and documentation stating why the TEG dehydration unit must operate using the alternate glycol circulation rate. • (iv) The name of the manufacturer and the model number of the glycol circulation pump(s) in operation. • (v) Statement by a responsible official, with that official's name, title, and signature, certifying that the facility will always operate the glycol dehydration unit using the optimum circulation rate determined in accordance with §63.764(d)(2)(i) or§63.764(d)(2)(ii), as applicable. o (f) Notification of process change. Whenever a process change is made, or a change in any of the information submitted in the Notification of Compliance Status Report, the owner or operator shall submit a report within 180 days after the process change is made or as a part of the next Periodic Report as required under paragraph (e) of this section, whichever is sooner. The report shall include: • (1) A brief description of the process change; • (2)A description of any modification to standard procedures or quality assurance procedures • (3) Revisions to any of the information reported in the original Notification of Compliance Status Report under paragraph (d) of this section; and • (4) Information required by the Notification of Compliance Status Report under paragraph (d) of this section for changes involving the addition of processes or equipment. 35. Point 006: This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XII.H. Beginning May 1, 2005, 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 at least 90 percent through the use of air pollution control equipment. This source shall comply with all applicable general provisions of Regulation 7, Section XII 36. Point 006: This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XVII.D (State only enforceable). a. Beginning May 1, 2015, uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas-condensate-glycol AIRS ID: 123/9D12 Page 16 of 40 Iorado part alth and Environment P ' ution Control Division (GCG) pars (fl" h par or o las n ), if p sent, shall be reduced by an avethnc,. t I t twelv nth basis through the use of air pollution control equipment. If a combustion device is used, it shall have a design destruction efficiency of at least 98% for hydrocarbons. This source shall comply with all applicable general provisions of Regulation 7, Section XVII. Condensate Storage Tanks 37. Point 007: These storage tanks are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart Kb, Standards of Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels)for which Construction, Reconstruction, or Modification Commenced after July 23, 1984 including, but not limited to, the following: • 40 CFR, Part 60, Subpart A— General Provisions • §60.112b—Standard for volatile organic compounds (VOC) ▪ §60.112b(a) The owner or operator of each storage vessel either with a design capacity greater than or equal to 151 m3 containing a VOL that, as stored, has a maximum true vapor pressure equal to or greater than 5.2 kPa but less than 76.6 kPa or with a design capacity greater than or equal to 75 m3 but less than 151 m3 containing a VOL that, as stored, has a maximum true vapor pressure equal to or greater than 27.6 kPa but less than 76.6 kPa, shall equip each storage vessel with one of the following: • §60.112b(a)(3) A closed vent system and control device meeting the following specifications: • §60.112b(a)(3)(i) The closed vent system shall be designed to collect all VOC vapors and gases discharged from the storage vessel and operated with no detectable emissions as indicated by an instrument reading of less than 500 ppm above background and visual inspections, as determined in part 60, subpart VV, §60.485(b). • §60.112b(a)(3)(ii) The control device shall be designed and operated to reduce inlet VOC emissions by 95 percent or greater. If a flare is used as the control device, it shall meet the specifications described in the general control device requirements (§60.18) of the General Provisions. • §60.113b—Testing and procedures • The owner or operator of each storage vessel as specified in §60.112b(a) shall keep records and furnish reports as required by paragraphs (a), (b), or (c) of this section depending upon the control equipment installed to meet the requirements of §60.112b. The owner or operator shall keep copies of all reports and records required by this section, except for the record required by AIRS ID: 123/9D12 Page 17 of 40 ., =z lorado -part w alth and Environment P. ution Control Division A (c)(1) =st y- s. r e r= •rd squired b (c)(1) will be kept for the life of rol - '• • §60.113b(d) The owner or operator of each source that is equipped with a closed vent system and a flare to meet the requirements in §60.112b (a)(3) or (b)(2) shall meet the requirements as specified in the general control device requirements, §60.18 (e) and (f). • §60.115b— Reporting and recordkeeping requirements • §60.115b(d) After installing a closed vent system and flare to comply with §60.112b, the owner or operator shall meet the following requirements. • §60.115b(d)(1) A report containing the measurements required by §60.18(f) (1), (2), (3), (4), (5), and (6) shall be furnished to the Administrator as required by §60.8 of the General Provisions. This report shall be submitted within 6 months of the initial start-up date. • §60.115b(d)(2) Records shall be kept of all periods of operation during which the flare pilot flame is absent. • §60.115b(d)(3) Semiannual reports of all periods recorded under §60.115b(d)(2) in which the pilot flame was absent shall be furnished to the Administrator. • §60.116b— Monitoring of operations • §60.116b(a) The owner or operator shall keep copies of all records required by this section, except for the record required by paragraph (b) of this section, for at least 2 years. The record required by paragraph (b) of this section will be kept for the life of the source. • §60.116b(b) The owner or operator of each storage vessel as specified in §60.110b(a) shall keep readily accessible records showing the dimension of the storage vessel and an analysis showing the capacity of the storage vessel. In addition, the following requirements of Regulation No. 6, Part A, Subpart A, General Provisions, apply. a. At all times, including periods of start-up, shutdown, and malfunction, the facility and control equipment shall, to the extent practicable, be maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. Determination of whether or not acceptable operating and maintenance procedures are being used will be based on information available to the Division, which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. (Reference: Regulation No. 6, Part A. General Provisions from 40 CFR 60.11 AIRS ID: 123/9D12 Page 18 of 40 a° lorado part i ` alth and Environment g Pdaution Control Division 10, b. No article, achi , i ent pr ss all be u d to conceal an emission which w rw. o a of a licable standard. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve compliance with an opacity standard or with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere. (§ 60.12) c. Written notification of construction and initial startup dates shall be submitted to the Division as required under § 60.7. d. Records of startups, shutdowns, and malfunctions shall be maintained, as required under § 60.7. e. Written notification of opacity observation or monitor demonstrations shall be submitted to the Division as required under§ 60.7. f. Excess Emission and Monitoring System Performance Reports shall be submitted as required under § 60.7. g. Performance tests shall be conducted as required under§ 60.8. h. Compliance with opacity standards shall be demonstrated according to § 60.11. i. The flare shall be designed and operated, and records and reports shall be furnished, as required under § 60.18. 38. Point 007: This source is subject to Regulation No. 7, Section XII.C General Provisions (State only enforceable). All condensate collection, storage, processing and handling operations, regardless of size, shall be designed, operated and maintained so as to minimize leakage of volatile organic compounds to the atmosphere to the maximum extent practicable. The operator shall comply with all 39. Point 007: The storage tanks covered by this permit are subject to the emission control requirements in Regulation No. 7, Section XVII.C.1.b. The owner/operator must install and operate air pollution control equipment that achieves an average hydrocarbon control efficiency of 95%. If a combustion device is used, it must have a design destruction efficiency of at least 98% for hydrocarbons. The source shall follow the inspection requirements of Regulation No. 7, Section XVII.C.1.d. and maintain records of the inspections for a period of two years, made available to the Division upon request. This control must be achieved according to the following schedule: o If storage tank was constructed on/after May 1, 2014, within 90 days of the date that the storage tank commences operation; o If storage tank was constructed before May 1, 2014, by May 1, 2015. 40. Point 007: The storage tanks covered by this permit are subject to the venting requirements of Regulation No. 7, Section XVII.C.2. This storage tank shall be operated without venting hydrocarbon emissions from the thief hatch (or other access point to the tank) or pressure relief device during normal operation, unless venting is reasonably required for maintenance, gauging, or safety of personnel and equipment. AIRS ID: 123/9D12 Page 19 of 40 lorado -part . :`. aith and Environment alAk A P•``ution Control Division The owner/ope tor s' n'II e in re, •rds` , ace rdance h Regulation No. 7, Section XVII. 's -e ` - bl- 41ivisio ,s,-n request. The owner/operator will maintain records of all required inspections and monitoring for a period of two years. This point is not subject to the STEM requirements under this section. TEG Dehydrator and Tanks 41. Point 006 and 007: The enclosed combustor covered by this permit is subject to Regulation No. 7, Section XII.C General Provisions (State only enforceable). If a combustion device is used to control emissions of volatile organic compounds to comply with Section XII.D, it shall be enclosed, have no visible emissions, and be designed so that an observer can, by means of visual observation from the outside of the enclosed combustion device, or by other means approved by the Division, determine whether it is operating properly. The operator shall comply with all applicable requirements of Section XII. 42. Point 006 and 007: This source is subject to the recordkeeping, monitoring, reporting and emission control requirements of Regulation 7, Section XII. The operator shall comply with all applicable requirements of Section XII. 43. Point 006 and 007: The enclosed combustor 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. Condensate Truck Loadout 44. Point 008: The owner or operator shall follow loading procedures that minimize the leakage of VOCs to the atmosphere including, but not limited to (Reference: Regulation 3, Part B, III.D.2): a. Hoses, couplings, and valves shall be maintained to prevent dripping, leaking, or other liquid or vapor loss during loading and unloading. b. All compartment hatches at the facility (including thief hatches) shall be closed and latched at all times when loading operations are not active, except for periods of maintenance, gauging, or safety of personnel and equipment. c. The owner or operator shall inspect onsite loading equipment during loading operations to monitor compliance with above conditions. The inspections shall occur at least monthly. Each inspection shall be documented in a log available to the Division on request. AIRS ID: 123/9D12 Page 20 of 40 •tiiallorado •Q epart alth and Environment itn;iF. P ution Control Division : 45. Point 008: All ydro rb0 lipid le.din op-vtions, r- ardless of size, shall be designed, op d . t. - o •r imize age of volatile organic compounds to the atmosphere to the maximum extent practicable. Fugitive Emissions 46. Point 011: The compressors at this facility commenced construction, modification or reconstruction after August 23, 2011, 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). o §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. o §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). 47. Point 011: The fugitive component emissions from this point that commenced construction, modification or reconstruction after August 23, 2011, 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 which commenced 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). • §60.5415: Owner or operator must demonstrate continuous compliance with the standards using the requirements in §60.5415(f). AIRS ID: 123/9D12 Page 21 of 40 jj.: lorado ' -pad . , :. alth and Environment A P. ution Control Division • §60.5421: O er of sip:, :to + us Aom wi the rec.,,•keeping requirements of §60.5421(b) a.; �.. . • §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). 48. Point 011: This source is subject to Regulation No. 7, Section XII.G.1 (State only enforceable). To comply with Regulation No. 7, Section XII.G.1, the source shall follow the leak detection and repair (LDAR) program as provided at 40 C.F.R. Part 60, Subpart OOOO in lieu of following 40 C.F.R. Part 60, Subpart KKK. OPERATING & MAINTENANCE REQUIREMENTS 49. Points 005, 006, 007, and 008: Upon startup ofi the points covered by this permit, the applicant shall follow the 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.) COMPLIANCE TESTING AND SAMPLING Initial Testing Requirements 50. Points 001 and 002: The combustion turbines are subject to the initial testing requirements of 40 C.F.R. Part 60, Subpart KKKK, as referenced in this permit. 51. Point 003 and 004: Within one hundred and eighty days (180) after commencement of operation, a source initial compliance test shall be conducted on the heaters to measure the emission rates) for the pollutants listed below in order to demonstrate compliance with the emissions limits contained in this permit. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall b.e 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 quarterly or annual emission limitation shall have the results projected up to the quarterly 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. 52. Point 005: Within one hundred and eighty days (180) after commencement of operation, the operator shall complete the initial extended gas analyses of the inlet gas to the plant 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 Crude Oil and Natural Gas Production, Transmission and Distribution : SO2 Emissions (§60.5365(g)(3)). The operator shall submit the results to the Division as part of the AIRS ID: 123/9D12 Page 22 of 40 wwaLl lorado .epart� alth and Environment Poi ution Control Division self-certificatio proc t e re Qom nc r it emi ions limits. (Reference: Regulation N B, io r 53. Point 005: Within one hundred and eighty days (180) after commencement of operation, the owner or operator shall complete an initial extended sour gas analysis prior to the inlet of the amine unit. Results of the sour gas analysis shall be used to calculate emissions of criteria pollutants and hazardous air pollutants. 54. Point 005: Within one hundred and eighty days (180) after commencement of operation, a source initial compliance test shall be conducted on emissions point 005 to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits in this permit. The operator shall also demonstrate the regenerative thermal oxidizer achieves a minimum destruction and removal efficiency of 96% for VOC. The operator shall measure and record, using EPA approved methods, VOC mass emission rates at the regenerative thermal oxidizer inlet and outlet to determine the destruction and removal efficiency of the regenerative thermal oxidizer (process models shall not be used to determine the flow rate or composition of the waste gas (acid gas stream from the still vent) sent to the regenerative thermal oxidizer for the purposes of this test). The natural gas throughput, lean amine circulation rate, MDEA concentration, and sulfur content of sour gas entering the amine unit shall be monitored and recorded during this test. The operator shall also measure and record combustion zone temperature during the initial compliance test to establish the minimum combustion temperature. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Sulfur Dioxide using EPA approved methods Oxides of Nitrogen using EPA approved methods Volatile Organic Compounds using EPA approved methods Carbon Monoxide using EPA approved methods 55. Points 006, 007, and 008: The owner or operator shall demonstrate compliance with opacity standards, using EPA Method 22 to determine the presence or absence of visible emissions. "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.All) 56. Point 006: Within one hundred and eighty days (180) after commencement of operation, the owner or operator shall complete the initial annual extended wet gas analysis testing required by this permit and submit the results to the Division as part AIRS ID: 123/9D12 Page 23 of 40 'lorado -part "` alth and Environment II 3 " AP. ution Control Division A of the self-c self-cz oc -.s t e re omplian.₹ with emissions limits. (Reference: :, ' .- - e :a I z . 57. Points 006, 007, and 008: Within one hundred and eighty days (180) after commencement of operation, a source initial compliance test shall be conducted on emissions point 006, 007, and 008 to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emission limits in this permit. Total emissions during this compliance test from these emission points will be used to determine compliance with the sum of 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. 58. Point 011: Within one hundred and eighty days (180) after commencement of operation, the permittee shall complete the initial extended gas analysis of gas samples that are representative of volatile organic compound (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas analysis shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. The operator shall submit the results of the gas analysis and emission calculations to the Division as part of the self-certification process to ensure compliance with emissions limits. 59. Point 011: 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 "light liquid 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. Periodic Testing Requirements 60. Points 001 and 002: Replacements of these units completed as Alternative Operating Scenarios may be subject to additional testing requirements as specified in Attachment A. 61. Points 001 and 002: The combustion turbines are subject to the periodic testing requirements of 40 C.F.R. Part 60, Subpart KKKK, as referenced in this permit. 62. Points 001 and 002: The operator shall conduct, at a minimum, quarterly portable analyzer monitoring of each turbine exhaust outlet emissions of nitrogen oxides (NO)) and carbon monoxide (CO) to monitor compliance with the emissions limits. Results of all tests conducted shall be kept on site and made available to the Division upon request. 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 AIRS ID: 123/9D12 Page 24 of 40 lorado 0epartriL. ; alth and Environment P ' ution Control Division averaging time, y mt4ifipl g te, re is the allo ble number of operating hours for that ._ g tR ce: No. x rt B., Section III.G.3). 63. Point 005: On an annual basis, the owner or operator shall complete an extended sour gas analysis prior to the inlet of the amine unit on an annual basis. Results of the sour gas analysis shall be used to calculate emissions of criteria pollutants and hazardous air pollutants. 64. Point 005: The permit holder shall measure and record the lean amine strength on a weekly basis. The lean amine strength is defined as the combined weight percent of DEA, MDEA and piperazine in the lean amine stream. Measurements of lean amine strength do not have to be speciated. Records of the amine strength shall be made available to the Division for inspection upon request. (Colorado Regulation No. 3, Part A, II) 65. Point 005: The operator shall sample the inlet gas to the plant 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 each amine unit qualifies for the exemption from the Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution (§60.5365(g)(3)). 66. Points 006, 007, 008: On a weekly basis, the owner or operator shall demonstrate compliance with opacity standards, using EPA Method 22 to determine the presence or absence of visible emissions. "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.Al I) 67. Point 006: 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. 68. Point 011: On an annual basis, the permittee shall complete an extended gas analysis of gas samples that is representative volatile organic compounds (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas analysis shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. ADDITIONAL REQUIREMENTS 69. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation No. 3, Part A, II.C) a. Annually 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 AIRS ID: 123/9D12 Page 25 of 40 tlorado , -part ° • 6 . alth and Environment P• ution Control Division For volatil orga • me nd (VS a nitroge oxides sources (NOX) in ozone n c r= "e � -a - ing :n 10' _•s of VOC or NO, per year, a change in annual actual emissions of one (1) ton per year or more or five percent, whichever is greater, above the level reported on the last APEN; or For sources emitting 100 tons per year or more, a change in actual emissions of five percent or 50 tons per year or more, whichever is less, above the level reported on the last APEN submitted; or For any non-criteria reportable pollutant: If the emissions increase by 50% or five (5) tons per year, whichever is less, above the level reported on the last APEN submitted to the Division. 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. Points 001 and 002: Within 14 calendar days of commencing operation of a permanent replacement turbine 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 turbine, the appropriate APEN filing fee and a cover letter explaining that the permittee is exercising an alternative-operating scenario and is installing a permanent replacement turbine. 70. Points 001 and 002: MACT Subpart YYYY - National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines requirements shall apply to this source at any such time that this source becomes a major source of hazardous air pollutants (HAP) 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) 71. 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) GENERAL TERMS AND CONDITIONS: 72. 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 AIRS ID: 123/9D12 Page 26 of 40 et 9lorado epart ;r alth and Environment P ution Control Division in AQCC Reg ation o. rt , S ion .B upon.. request for transfer of ownership an mi ,e o,f d the r d fee. 73. 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. 74. This permit is issued in reliance upon the accuracy and completeness of information supplied by the applicant and is conditioned upon conduct of the activity, or construction, installation and operation of the source, in accordance with this information and with representations made by the applicant or applicant's agents. It is valid only for the equipment and operations or activity specifically identified on the permit. 75. 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. 76. Each and every condition of this permit is a material part hereof and is not severable. Any challenge to or appeal of a condition hereof shall constitute a rejection of the entire permit and upon such occurrence, this permit shall be deemed denied ab initio. This permit may be revoked at any time prior to self-certification and final authorization by the Air Pollution Control Division (APCD) on grounds set forth in the Colorado Air Quality Control Act and regulations of the Air Quality Control Commission (AQCC), including failure to meet any express term or condition of the permit. If the Division denies a permit, conditions imposed upon a permit are contested by the applicant, or the Division revokes a permit, the applicant or owner or operator of a source may request a hearing before the AQCC for review of the Division's action. 77. 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. 78. Violation of the terms of a permit or of the provisions of the Colorado Air Pollution Prevention and Control Act or the regulations of the AQCC may result in administrative, civil or criminal enforcement actions under Sections 25-7-115 (enforcement), -121 (injunctions), -122 (civil penalties), -122.1 (criminal penalties), C.R.S. AIRS ID: 123/9D12 Page 27 of 40 D.lorado E -part y : alth and Environment AP. ution Control Division By: 61014.4101zu_________ Christopher Kester Permit Engineer Permit History Issuance Date Description Issuance 1 This issuance Issued to DCP Midstream— Initial Issuance AIRS ID: 12319D12 Page 28 of 40 T_ = c p Ilorado depart alth and Environment w P ution Control Division Notes to Permit Holder atthtime thi •er iss nce: 1) The permit holder is required to pay fees for the processing time for this permit. An invoice for these fees will be issued after the permit is issued. The permit holder shall pay the invoice within 30 days of receipt of the invoice. Failure to pay the invoice will result in revocation of this permit (Reference: Regulation No. 3, Part A, Section VI.B.) 2) The production or raw material processing limits and emission limits contained in this permit are based on the consumption rates requested in the permit application. These limits may be revised upon request of the permittee providing there is no exceedance of any specific emission control regulation or any ambient air quality standard. A revised air pollution emission notice (APEN) and application form must be submitted with a request for a permit revision. 3) This source is subject to the Common Provisions Regulation Part II, Subpart E, Affirmative Defense Provision for Excess Emissions During Malfunctions. The permittee shall notify the Division of any malfunction condition which causes a violation of any emission limit or limits stated in this permit as soon as possible, but no later than noon of the next working day, followed by written notice to the Division addressing all of the criteria set forth in Part II.E.1. of the Common Provisions Regulation. See: http://www.cdphe.state.co.us/regulations/airregs/100102agcccommonprovisionsreg.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. Facility Uncontrolled Are the Controlled Equipment AIRS Pollutant CAS# Emission emissions Emission ID Point Rate reportable? Rate(Ib/yr) (lb/yr) Formaldehyde 50000 453 Yes 453 Acetaldehyde 75070 26 No 26 TURB-1 001 Acrolein 107028 5 No 5 Benzene 71432 8 No 8 Toluene 108883 83 No 83 Formaldehyde 50000 453 Yes 453 Acetaldehyde 75070 26 No 26 TURB-2 002 Acrolein 107028 5 No 5 Benzene 71432 8 No 8 Toluene 108883 83 No 83 HT-01 003 n-Hexane 110543 441 Yes 441 HT-02 004 n-Hexane 110543 126 No 126 Benzene 71432 145,320 Yes 11,715 Toluene 108883 68,308 Yes 5,562 AU-01 005 Ethylbenzene 100414 2,504 Yes 202 Xylenes 1330207 5,138 Yes 422 n-Hexane 110543 18,362 Yes 189 AIRS ID: 123/9D12 Page 29 of 40 0,lorado -part` ° •3 _ • alth and Environment P. ution Control Division B ;en 7 32 -0,560 Yes 6,822 Toluene I::83 '1,648 Yes 4,435 D-01 006 Ethylbenzene 100414 5,769 Yes 284 Xylenes 1330207 11,960 Yes 592 n-Hexane 110543 90,595 Yes 2,908 Benzene 71432 1,644 Yes 83 Toluene 108883 4,555 Yes 228 Tanks 007 Ethylbenzene 100414 339 Yes 17 Xylenes 1330207 3,443 Yes 173 n-Hexane 110543 8,843 Yes 442 Benzene 71432 2,520 Yes 126 Toluene 108883 6,965 Yes 348 Load 008 Ethylbenzene 100414 519 Yes 26 Xylenes 1330207 5,265 Yes 263 n-Hexane 110543 13,524 Yes 676 Benzene 71432 392 Yes 64 Toluene 108883 289 Yes 47 FUG 011 Ethylbenzene 100414 23 Yes 4 Xylenes 1330207 39 Yes 6 n-Hexane 110543 8,025 Yes 1,309 5) The emission levels contained in this permit are based on the following emission factors: Points 001 (TURB-01) and 002(TURB-02): Emission Factors -Uncontrolled CAS Pollutant Ib/MMBtu Source NOX 0.0472 Manufacturer CO 0.0553 Manufacturer VOC 0.0021 AP-42, Chapter 3.1-2a SO2 0.0034 AP-42, Chapter 3.1-2a PM2.5 0.0066 AP-42, Chapter 3.1-2a 50000 Formaldehyde 0.00071 AP-42, Chapter 3.1-3 Emission factors are based on a rated heat input of 72.73 MMBtu/hr, a HHV value of 999 Btu/scf and 8,760 hours of operation a year Point 003(HT-01): Emission Factors-Uncontrolled CAS Pollutant lb/MMscf Source Approved by Bailey NOX 37 Smith(CDPHE—APCD) 4/3/2013 CO 84 AP-42, Table 1.4-1 AIRS ID: 123/9D12 Page 30 of 40 c lorado @epartr alth and Environment � y P ution Control Division 1 Q issitn Fa " ors -UnYource trolled CAS PySutate M4:0 VOC 5.5 AP-42, Table 1.4-2 PM2.5 5.0 Manufacturer 110543 n-Hexane 1.8 AP-42, Table 1.4-3 Emission factors are based on a rated heat input of 44 MMBtu/hr, a higher heating value of 999 Btu/scf, and a limited use scenario of 245 MMscf/yr or the equivalent of 63.5% of operating capacity. ** Emission factors approved by APCD engineer on 4/3/2013 based on review of "not to exceed" emission factors for other similar heaters. Point 004(HT-02): Emission Factors - Uncontrolled CAS Pollutant lb/MMscf Source Approved by Bailey NOx 37 Smith(CDPHE—APCD) 4/3/2013 CO 84 AP-42, Table 1.4-1 VOC 5.5 AP-42, Table 1.4-2 PM2.5 5.0 Manufacturer 110543 n-Hexane 1.8 AP-42, Table 1.4-3 Emission factors are based on a rated heat input of 9.6 MMBtu/hr, a higher heating value of 999 Btu/scf, and a limited use scenario of 70 MMscf/yr or the equivalent of 83.2% of operating capacity. ** Emission factors approved by APCD engineer on 4/3/2013 based on review of "not to exceed" emission factors for other similar heaters. Point 005(AU-01): The emission levels contained in this permit are based on the Promax simulation model using the extended sour gas analysis submitted with the permit application. The emissions levels in this permit were buffered by multiplying the model results by a factor 1.2 (H2S values were not buffered because compositions were conservatively estimated before buffer was applied) Emission Factors Emission Factors CAS# Pollutant Uncontrolled Controlled Source lb/MMscf Natural Ib/MMscf Natural Gas Throughput Gas Throughput NOx 0.033 --- AP-42, Table 13.5-1 CO 0.183 --- AP-42, Table 13.5-1 Mass Balance using SOx 0.750 H2S composition from ProMax VOC 17.42 0.402 Promax H2S 0.431 0.033 Promax 110543 n-Hexane 0.219 0.0022 Promax 71432 Benzene 1.731 0.140 Promax 108883 Toluene 0.814 0.067 Promax 100414 Ethylbenzene 0.030 0.0024 Promax 1330207 Xylene 0.061 0.0050 Promax AIRS ID: 123/9D12 Page 31 of 40 0, �-part .' .a .. "` 'alth and Environment iA P. ution Control Division The controlled emissit .Is _s ._..e c _ w= iency a for the acid gas stream during RTO operation (3.6% annual downtime with no emission controls) and a 100% control efficiency for the flash tank stream during VRU operation (5% annual downtime with 95%control). NOx and CO emission factors from AP-42 were used to calculate emissions. Emission factors were back calculated to provide an emission factor with the same units as other pollutants for this point. Point 006(D-01): The VOC and HAP emission levels contained in this permit are based on information provided in the application and the GRI GlyCalc 4.0 model. Emission Factors Emission Factors CAS# Pollutant Uncontrolled Controlled Source lb/MMscf Natural lb/MMscf Natural Gas Throughput Gas Throughput NOx 0.036 --- AP-42, Table 13.5-1 CO 0.198 --- AP-42, Table 13.5-1 VOC 20.40 0.608 GlyCalc 4.0 110543 n-Hexane 1.08 0.035 GlyCalc 4.0 71432 Benzene 1.67 0.082 GlyCalc 4.0 108883 Toluene 1.08 0.053 GlyCalc 4.0 100414 Ethylbenzene 0.069 0.0033 GlyCalc 4.0 1330207 Xylene 0.142 0.0071 GlyCalc 4.0 The controlled emissions factors are based on the control efficiency of 95% for the Regenerator Still Vent Stream routed to an enclosed combustor (back up enclosed combustor used during downtime) and 100% control efficiency for the flash tank stream during VRU operation (5% annual downtime with 95% control). NOx and CO emission factors from AP-42 were used to calculate emissions. Emission factors were back calculated to provide an emission factor with the same units as other pollutants for this point. Point 007(Tanks): Emission Emission CAS Pollutant Factors Factors Source Uncontrolled Controlled NOx 0.068 --- AP-42, Table 13.5-1 lb/MMBtu CO 0.37 --- AP-42, Table 13.5-1 lb/MMBtu 0.132 0.006600 VOC lb/bbl lb/bbl EPA Tank 4.09d 71432 Benzene 0.00180 0.000090 EPA Tank 4.09d lb/bbl lb/bbl 108883 Toluene 0.00499 0.000250 EPA Tank 4.09d lb/bbl lb/bbl 100414 Ethylbenzene 0.00037 0.000019 EPA Tank 4.09d lb/bbl lb/bbl 1330207 Xylenes 0.00377 0.000188 EPA Tank 4.09d lb/bbl lb/bbl 110543 n-Hexane 0.010 0.00050 EPA Tank 4.09d lb/bbl lb/bbl AIRS ID: 123/9D12 Page 32 of 40 lorado epart i` alth and Environment P• ution Control Division Emissions for NOx and S wer..- al lat- usir the •mb - e• gas H of 3397 btu/scf(calculated 444, as an interpolated va oikjAz ;49.„,r s• • e flare • s). Volume of gas to be combusted was calculated using the ideal gas law with the emission mass flow rate calculated by EPA Tank 4.09d. The controlled emissions factors for point 007 are based on the enclosed combustor control efficiency of 95%. Emission factors are based on the condensate tank battery as a combined unit, not per tank. Point 008 (Load): Emission Emission CAS Pollutant Factors Factors Source Uncontrolled Controlled NOx 0.068 ___ AP-42, Table 13.5-1 lb/MMBtu CO 0'37 --- AP-42, Table 13.5-1 lb/MMBtu VOC 0.2022 lb/bbl 0.01011 lb/bbl AP-42 Chapter 5.2 Equation 1 71432 Benzene AP-42 Chapter 5.2 Equation 1 0.0027 lb/bbl 0.00014 lb/bbl with mass fraction 108883 Toluene AP-42 Chapter 5.2 Equation 1 0.0074 lb/bbl 0.00037 lb/bbl with mass fraction 100414 Ethylbenzene AP-42 Chapter 5.2 Equation 1 0.0006 lb/bbl 0.00003 lb/bbl with mass fraction 1330207 Xylenes AP-42 Chapter 5.2 Equation 1 0.0056 lb/bbl 0.00028 lb/bbl with mass fraction AP-42 Chapter 5.2 Equation 1 110543 n-Hexane 0.0145 lb/bbl 0.00073 lb/bbl p q with mass fraction Emissions for NOx and CO were calculated using the combusted gas HHV of 3397 btu/scf (calculated as an interpolated value based on the molecular weight of the flared gas). Volume of gas to be combusted was calculated using the ideal gas law with the emission mass flow rate calculated with AP-42 Chapter 5.2 Equation 1. The uncontrolled VOC emission factor was calculated using AP-42, Chapter 5.2, Equation 1 (version 1/95) using the following values: L = 12.46*S*P*M/T S = 0.6 (Submerged loading: dedicated normal service) P (true vapor pressure) = 5.0032 psia M (vapor molecular weight) = 66 Ib/Ib-mol T (temperature of liquid loaded) = 512.45 °R The uncontrolled non-criteria reportable air pollutant (NCRP) emission factors were calculated by multiplying the mass fraction of each NCRP in the vapors by the VOC emission factor. Controlled emission factors are based on an enclosed combustor efficiency of 95%. AIRS ID: 123/9D12 Page 33 of 40 •Iorado -part . alth and Environment �' P• ution Control Division Point 011 (FUG): • Equipment Typ ' e s C.° Li•r. uid Light Liquid Control% Connectors 15258 30 2524 30 Flanges 1031 30 494 30 Open-Ended Lines 0 75 0 75 Pump Seals 0 88 36 88 Valves 3652 95 1224 95 Other 61 75 14 75 VOC Content(wt%) 26.92% --- 100% Benzene(wt%) 0.06% --- 0.06% --- Toluene(wt%) 0.04% --- 0.04% --- Ethylbenzene (wt%) 0.003% --- 0.003% --- Xylenes(wt%) 0.01% --- 0.01% --- n-hexane(wt%) 1.21% --- 1.21% --- *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 Light Oil Connectors 2.0E-04 2.1E-04 Flanges 3.9E-04 1.1E-04 Open-ended Lines 2.0E-03 1.4E-03 Pump Seals 2.4E-03 1.3E-02 Valves 4.5E-03 2.5E-03 Other 8.8E-03 7.5E-03 Source: EPA-453/R95-017 Compliance with emissions limits in this permit will be demonstrated by using the TOC emission factors listed in the table above with representative component counts, multiplied by the VOC content from the most recent gas analysis. 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) This facility is classified as follows: Applicable Status Requirement Operating Permit Synthetic Minor Source of VOC and HAP PSD Synthetic Minor Source of VOC NANSR Synthetic Minor Source of VOC AIRS ID: 123/9D12 Page 34 of 40 . lorado epart F= �P e alth and Environment Pollution Control Division 8) Full text of the Title 40' rote n1ironntE ctroderal Regulations can be foundatthewebsiteli • ,, , http://ecfr.gpoaccess.gov/ Part 60: Standards of Performance for New Stationary Sources NSPS 60.1-End Subpart A—Subpart OOOO 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 9) A self certification form and guidance on how to self-certify compliance as required by this permit may be obtained online at: http://www.colorado.gov/pacific/cdphe/air-permit-self-certification AIRS ID: 123/9D12 Page 35 of 40 DCP Midstream, LP Colorado Department of Public Health and Environment Permit No. 14WE1326 Air Pollution Control Division Issuance 1 ATTACHMENT A: ALTERNATIVE OPERATING SCENARIOS TURBINES WITHOUT CONTINUOUS EMISSIONS MONITORING 1. Routine Turbine Component Replacements The following physical or operational changes to the turbines in this permit are not considered a modification for purposes of NSPS GG, major stationary source NSR/PSD, or Regulation No. 3, Part B. Note that the component replacement provisions apply ONLY to those turbines subject to NSPS GG. Neither pre-GG turbines nor post GG turbines (i.e. KKKK turbines) can use those provisions. 1) Replacement of stator blades, turbine nozzles, turbine buckets, fuel nozzles, combustion chambers, seals, and shaft packings, provided that they are of the same design as the original. 2) Changes in the type or grade of fuel used, if the original gas turbine installation, fuel nozzles, etc. were designed for its use. 3)An increase in the hours of operation (unless limited by a permit condition) 4)Variations in operating loads within the engine design specification. 5)Any physical change constituting routine maintenance, repair, or replacement. Turbines undergoing any of the above changes are subject to all federally applicable and state only requirements set forth in this permit (including monitoring and record keeping). If replacement of any of the components listed in (1) or (5) above results in a change in serial number for the turbine, a letter explaining the action as well as a revised APEN and appropriate filing fee shall be submitted to the Division within 30 days of the replacement. Note that the repair or replacement of components must be of genuinely the same design. Except in accordance with the Alternate Operating Scenario set forth below, the Division does not consider that this allows for the entire replacement (or reconstruction) of an existing turbine with an identical new one or one similar in design or function. Rather, the Division considers the repair or replacements to encompass the repair or replacement of components at a turbine with the same (or functionally similar) components. 2. Alternative Operating Scenarios The following Alternative Operating Scenario (AOS) for the temporary and permanent replacement of combustion turbines and turbine components 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 turbine or turbine component replacement performed in accordance with this AOS, and the owner or operator shall be allowed to perform such turbine or turbine component replacement without applying for a revision to this permit or obtaining a new Construction Permit. AIRS ID: 123/9D12/001,002 Page 36 of 40 DCP Midstream, LP Colorado Department of Public Health and Environment Permit No. 14WE1326 Air Pollution Control Division Issuance 1 2.1 Turbine Replacement The following AOS is incorporated into this permit in order to deal with a turbine breakdown or periodic routine maintenance and repair of an existing onsite turbine that requires the use of a temporary replacement turbine. "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 turbine is in operation. If the turbine 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. Any permanent turbine replacement under this AOS shall result in the replacement turbine being considered a new affected facility for purposes of NSPS and shall be subject to all applicable requirements of that Subpart including, but not limited to, any required Performance Testing. All replacement turbines 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 the NSPS 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 turbine replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number of the turbine (s) that are replaced during the term of this permit, and the manufacturer, model number, horsepower, and serial number of the replacement turbine. 2.1.1 The owner or operator may temporarily replace an existing turbine that is covered by this permit with a turbine that is the exact same make and model as the existing turbine without modifying this permit, so long as the temporary replacement turbine complies with the emission limitations for the existing permitted turbine and other requirements applicable to the original turbine. Measurement of emissions from the temporary replacement turbine shall be made as set forth in section 2.2. 2.1.2 The owner or operator may permanently replace the existing turbine that is covered by this permit with a turbine that is the exact same make and model as the existing turbine without modifying this permit so long as the permanent replacement turbine complies with the emission limitations and other requirements applicable to the original turbine as well as any new applicable requirements for the replacement turbine. Measurement of emissions from the temporary replacement turbine shall be made as set forth in section 2.2. 2.1.3 An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model and serial number and horsepower of the permanent replacement turbine shall be filed with the Division for the permanent replacement turbine within 14 calendar days of commencing operation of the replacement turbine. 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 turbine. This AOS cannot be used for permanent turbine replacement of a grandfathered or permit exempt turbine or a turbine 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 turbine replacement. AIRS ID: 123/9D12/001,002 Page 37 of 40 DCP Midstream, LP Colorado Department of Public Health and Environment Permit No. 14WE1326 Air Pollution Control Division Issuance 1 The AOS cannot be used for the permanent replacement of an entire turbine at any source that is currently a major stationary source for purposes of Prevention of Significant Deterioration or Non-Attainment Area New Source Review ("PSD/NANSR") unless the existing turbine has emission limits that are below the significance levels in keg 3, Part D, I I.A.42. Nothing in this AOS shall preclude the Division from taking an action, based on any permanent turbine replacement(s), for circumvention of any state or federal PSD/NANSR requirement. Additionally, in the event that any permanent turbine replacement(s) constitute(s) a circumvention of applicable PSD/NANSR requirements, nothing in this AOS shall excuse the owner or operator from complying with PSD/NANSR and applicable permitting requirements. 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 turbine using a portable flue gas analyzer within seven (7)calendar days of commencing operation of the replacement turbine. All portable analyzer testing required by this permit shall be conducted using the most current version of the Division's Portable Analyzer Monitoring Protocol as found on the Division's website. 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. 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 turbine 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 turbine 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 turbine will be considered to be out of compliance from the date of the AIRS ID: 123/9D12/001,002 Page 38 of 40 DCP Midstream, LP Colorado Department of Public Health and Environment Permit No. 14WE1326 Air Pollution Control Division Issuance 1 portable analyzer test until a portable analyzer test indicates compliance with both the NOX and CO emission limitations or until the turbine is taken offline. 2.3 Applicable Regulations for Permanent Turbine Replacements 2.3.1 NSPS for Stationary Gas Turbines: 40 CFR 60, Subpart GG §60.330 Applicability and designation of affected facility. (a) The provisions of this subpart are applicable to the following affected facilities: All stationary gas turbines with a heat input at peak load equal to or greater than 10.7 gigajoules (10 million Btu) per hour, based on the lower heating value of the fuel fired. (b)Any facility under paragraph (a) of this section which commences construction, modification, or reconstruction after October 3, 1977, is subject to the requirements of this part except as provided in paragraphs (e) and (j) of§60.332. A Subpart GG applicability determination as well as an analysis of applicable Subpart GG monitoring, recordkeeping, and reporting requirements for the permanent turbine replacement shall be included in any request for a permanent turbine replacement 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 commence construction date for purposes of determining the applicability of NSPS GG requirements). 2.3.2 NSPS for Stationary Combustion Turbines: 40 CFR 60, Subpart KKKK §60.4305 Does this subpart apply to my stationary combustion turbine? (a) If you are the owner or operator of a stationary combustion turbine with a heat input at peak load equal to or greater than 10.7 gigajoules (10 MMBtu) per hour, based on the higher heating value of the fuel, which commenced construction, modification, or reconstruction after February 18, 2005, your turbine is subject to this subpart. Only heat input to the combustion turbine should be included when determining whether or not this subpart is applicable to your turbine. Any additional heat input to associated heat recovery steam generators (HRSG) or duct burners should not be included when determining your peak heat input. However, this subpart does apply to emissions from any associated HRSG and duct burners. (b) Stationary combustion turbines regulated under this subpart are exempt from the requirements of subpart GG of this part. Heat recovery steam generators and duct burners regulated under this subpart are exempted from the requirements of subparts Da, Db, and Dc of this part. A Subpart KKKK applicability determination as well as an analysis of applicable Subpart KKKK monitoring, recordkeeping, and reporting requirements for the permanent turbine replacement shall be included in any request for a permanent turbine replacement 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 commence construction date for purposes of determining the applicability of NSPS KKKK requirements). AIRS ID: 123/9D12/001,002 Page 39 of 40 DCP Midstream, LP Colorado Department of Public Health and Environment Permit No. 14WE1326 Air Pollution Control Division Issuance 1 2.4 Additional Sources The replacement of an existing turbine with a new turbine 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; a turbine that is being installed as an entirely new emission point and not as part of an AOS-approved replacement of an existing onsite turbine has to go through the appropriate Construction/Operating permitting process prior to installation • AIRS ID: 123/9D121001,002 Page 40 of 40 Construction Permit Application Preliminary Analysis Summary Section 1 —Applicant Information Company Name: DCP Midstream LP Permit Number: 14WE1326 Source Location: Northeast Corner of WCR 49&WCR 44; SW SEC 18 T4N R64W Source Name: Mountain View Gas Plant AIRS ID: 12319D12 Date: November 11, 2014 Review Engineer: Christopher Kester Control Engineer: Stefanie Rucker Section 2—Action Completed Grandfathered Modification APEN Required/Permit Exempt X CP1 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? Yes X No If you answered "no"to any of the above, when did you mail an Via Email several times over last Information Request letter to the source? few weeks On what date was this application complete? November 17, 2014 Section 4—Source Description AIRS Point Equipment Description "TURB-1"—One (1) natural gas fired compression turbine (Make: Solar; Model: T70; SN: TBD)equipped with low NOx burners, site rated at 9,055 horsepower at 11,513 RPM. The 001 turbine is design rated for a heat input of 72.73 MMBtu/hr at 60°F ambient temperature. The turbine will be equipped with a Waste Heat Recovery Unit(WHRU) System. This combustion turbine will be used to power a compressor. "TURB-2"—One(1) natural gas fired compression turbine(Make: Solar; Model: T70; SN: TBD) equipped with low NOx burners, site rated at 9,055 horsepower at 11,513 RPM. The 002 turbine is design rated for a heat input of 72.73 MMBtu/hr at 60°F ambient temperature. The turbine will be equipped with a Waste Heat Recovery Unit(WHRU) System. This combustion turbine will be used to power a compressor. "HT-01"—One(1) natural gas fired hot oil heater(Make: Optimized Process Furnaces, 003 Inc.; Model: Custom (TBD); SN: TBD), equipped with low NOx burners. The heater is design rated at a heat input of 44 MMBtu/hr. This heater is used to heat oil for several processes within the plant. Page 1 "HT-02"—One(1) natural gas fired regeneration heater(Make: Optimized Process 004 Furnaces, Inc.; Model: Custom (TBD); SN: TBD), equipped with low NOx burners. The heater is design rated at a heat input of 9.6 MMBtu/hr. This heater is used to heat oil for several processes within the plant. "AU-01"—One(1) Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 230 MMscf/day(Make: TBD; Model: TBD; SN: TBD). This emissions unit is equipped with two(2) amine recirculation pumps with a total limited capacity of 945 gallons per minute of lean amine. This system includes a natural gas/amine contactor, reflux condenser, a flash tank, still vent, and an indirect fired hot oil 005 (of waste heat from the WHRU's)amine regeneration reboiler(point 003). The amine flash stream is routed to a closed loop system that utilizes a vapor recovery unit (maximum 5%annual downtime). Emissions during the downtime will be routed to a flare with 95% destruction efficiency. The acid gas stream from the still vent condenser outlet is routed to a regenerative thermal oxidizer(Make:Anguil; Model: 150 RTO; SN: TBD) rated at 15,000 scf/min with a minimum destruction efficiency of 96%. "D-01"—One(1)Triethylene Glycol (TEG)dehydrator unit with a design capacity of 230 MMscf/day(Make: TBD; Model: TBD; SN: TBD). This emissions unit is equipped with two (2)electric glycol pumps with a limited total combined capacity of 40 gallons per minute. 006 This system includes a condenser, reboiler, still vent, and a flash tank. The flash gas is routed to a closed loop system that utilizes a vapor recovery unit(maximum 1%annual downtime). Emissions during the downtime will be routed to a flare with a minimum 95% destruction efficiency. The still vent emissions are routed to a condenser and then to an enclosed combustor with a minimum destruction efficiency of 95%. "Tanks"—Four(4) 1,000 bbl stabilized atmospheric condensate storage tanks. 007 Emissions from the tanks are routed to an enclosed combustor with a minimum destruction efficiency of 95%. 008 "Load"—Condensate truck loading of stabilized condensate. Emissions from the loadout will be routed to an enclosed combustor with a minimum destruction efficiency of 95%. "TURB-BD"—Turbine purging blowdown events for turbine maintenance will be performed no more than two(2)times per month. Each purging event will take place for a 010 maximum of one(1) minute. Emissions from the turbine purging blowdown events are routed to a flare. (This point was determined to be APEN Exempt and is filed under APEN Exempt number 15WE0192.XA) 011 "FUG"—Fugitive emission component leaks from this natural gas processing plant. Is this location in a non-attainment area for any criteria X Yes No pollutant? If"yes", for what pollutant? PM10 CO X 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) Is this source located in the 8-hour ozone non- attainment region?(Note: If"yes"the provisions of X Yes No Regulation 7, Sections XII and XVII.C may apply) Is this source located at a facility that is considered a major source of hazardous air pollutant(HAP) Yes No emissions? Section 5—Emission Estimate Information AIRS Point Emission Factor Source 001 AP-42, Tables 3.1-2a and 3.1-3 for VOC, PM10, PM25, SON, and HAPs; Manufacturer data for CO and NOx Page 2 002 AP-42, Tables 3.1-2a and 3.1-3 for VOC, PMA°, PM25, SON, and HAPs; Manufacturer data for CO and NO, AP-42, Tables 1.4-1, 1.4-2, 1.4-3, and 1.4-4 for VOC, CO, and SON; Manufacturer data for 003 PM; NO,emission factor for hot oil heater approved by Bailey Smith of CDPHE on April 3, 2013; see section 14 for calculations AP-42, Tables 1.4-1, 1.4-2, 1.4-3, and 1.4-4 for VOC, CO, and SON; Manufacturer data for 004 PM; NO„emission factor for hot oil heater approved by Bailey Smith of CDPHE on April 3, 2013; see section 14 for calculations Promax Simulation Model for VOC H2S, and HAPs; AP-42, Table 13.5-1 for CO and NO,; 005 ' z Combustion mass balance for SOX 006 GRI-GLYCalc v4.0 Simulation Model for VOC and HAPs; AP-42, Table 13.5-1 for CO and NO, 007 EPA TANKS 4.09d Simulation Model for VOC and HAPs;AP-42, Table 13.5-1 for CO and NO, 008 AP-42, Chapter 5.2, Equation 1 for VOC and HAPs; AP-42, Table 13.5-1 for CO and NO, 010 Site-Specific Emission factors developed for VOC and HAPs using compositional analysis of gas to be vented 011 EPA Protocol for Equipment Leak emission Estimates, EPA, November 1995, EPA-453/R- 95-017, Table 2-4 Did the applicant provide actual process data for the emission inventory? Yes X No Basis for Potential to Emit(PTE) AIRS Point Process Consumption/Throughput/Production [66.13 MMBtu/hr * 1.1 *8760 hr/yr]/999 Btu/scf= 637.8 MMscf/yr 001 [(LHV Fuel Input Rate) * (LHV to HHV Conversion Factor) *(Hrs of Operation)]/(Heat Content of Gas) = Permitted Limit [66.13 MMBtu/hr * 1.1 *8760 hr/yr]/999 Btu/scf=637.8 MMscf/yr 002 [(LHV Fuel Input Rate) * (LHV to HHV Conversion Factor) * (Hrs of Operation)]/(Heat Content of Gas) = Permitted Limit 003 [44 MMBtu/hr*8760 hr/yr]/999 Btu/scf=385.83 MMscf/yr [(Fuel Input Rate) * (Hrs of Operation)]/(Heat Content of Gas) = Permitted Limit 004 [9.6 MMBtu/hr* 8760 hr/yr]/999 Btu/scf= 84.2 MMscf/yr [(Fuel Input Rate) * (Hrs of Operation)]/(Heat Content of Gas) = Permitted Limit 005 Natural gas throughput 83,950 MMscf/yr; 945 gal/min lean amine circulation rate, RTO throughput 2,869 MMscf/yr 006 Natural gas throughput 83.950 MMscf/yr, 40 gal/min glycol circulation rate 007 Condensate Throughput 912,500 bbl/yr 008 Condensate Throughput 912,500 bbl/yr 010 Requested Volume of 0.69 MMscf/yr Equipment Type I Gas I Light Liquid Wt% Gas Light Liquid Connectors 15258 2524 VOC 26.92 100 Flanges 1031 494 Benzene 0.06 0.06 011 Open-Ended Lines 0 0 Toluene 0.04 0.04 Pump Seals 0 36 Ethyl benzene 0.003 0.003 Valves 3652 1224 Xylene 0.01 0.01 Other 61 14 n-Hexane 1.21 1.21 Basis for Permitted Emissions (Permit Limits) AIRS Point Process Consumption/Throughput/Production 001 637.8 MMscf/yr 002 637.8 MMscf/yr 003 245 MMscf/yr(Operator Limiting Capacity to about 63.5%) Page 3 004 70 MMscf/yr(Operator Limiting Capacity to about 83.2%) 005 83,950 MMscf/yr, 945 gal/min lean amine circulation rate RTO Throughput 2,869 MMscf/yr (20% Buffer applied to emission limits for conservatism to VOC and HAPs) 006 83,950 MMscf/yr, 40 gal/min glycol circulation rate 007 912,500 bbl/yr 008 912,500 bbl/yr 010 0.69 MMscf/yr Equipment Type J Gas T Light Liquid Wt% I Gas ! Light Liquid® Connectors 15258 2524 VOC 26.92 100 Flanges 1031 494 Benzene 0.06 0.06 011 Open-Ended Lines 0 0 Toluene _ 0.04 0.04 Pump Seals 0 36 Ethyl benzene 0.003 0.003 Valves 3652 1224 Xylene 0.01 0.01 Other 61 14 n-Hexane 1.21 1.21 AIRS Point Proc. Control Device Description % Reduction Granted VRU (closed loop)and backup flare 100% during VRU uptime (95% 01 during VRU downtime to control flash minimum VRU uptime) 005 tank 95% during VRU downtime 02 Regenerative Thermal Oxidizer to control 96% for VOC and HAP Acid Gas stream VRU (closed loop)and backup flare 100% during VRU uptime (95% 01 during VRU downtime to control flash minimum VRU uptime) 006 tank 95% during VRU downtime 02 Enclosed Combustor to control still vent 95% 007 01 Enclosed Combustor to control 95% emissions from Condensate Tanks 008 01 Enclosed Combustor to control 95% emissions from Loadout Enclosed Combustor to control 0% (point will receive APEN 010 01 emissions from TURB-BD Exemption letter, no federally enforceable limit) Connectors 30% Flanges 30% LDAR-See Section 12 for further details Open-Ended 75% 011 01 on source for control % reductions Lines Pump Seals 88% Valves 95% Other 75% Section 6—Emissions Summary Point NOx VOC CO SOx PM/PM H2S Largest Total HAP to/PM2.5 Single HAP 0.3 001 15.0 0.7 17.6 1.1 2.1 --- (formaldehyde) 0.3 002 15.0 0.7 17.6 1.1 2.1 --- 0.3 (formaldehyde) 0.3 0.4 003 7.1 1.1 0.1 0.9 --- (n hexane) 0.4 PTE: 004 1.6 0.3 3.6 0.1 0.3 --- --- --- 005 1.4 731.2 7.7 31.5 --- 18.1 72.7 119.82 (benzene) 006 1.5 856.2 8.3 --- --- --- 70.3 169.8 (benzene) Page 4 4.5 007 0.1 60.4 0.5 "' (n-hexane) 9.5 008 0.2 92.3 0.7 - "- 6.8 (n hexane) 13.9 010 0.03 0.77 0.14 --- --- --- --- --- 4.1 011 131.1 --- (n-hexane) 4.4 001 15.0 0.7 17.6 1.1 2.1 --- 0.3 0.3 (formaldehyde) 002 15.0 0.7 17.6 1.1 2.1 --- 0.3 0.3 (formaldehyde) 0.3 003 4.5 0.7 10.3 0.1 0.6 --- 0.3 (n-hexane) 004 1.4 0.2 3.0 0.1 0.2 --- --- --- Requested Uncontrolled 005 1.4 731.2 7.7 31.5 --- 18.1 72'7 119.82 (benzene) point source emission 006 1.5 856.2 8.3 --- --- --- 70.3 169.8 (benzene) rate: 007 0.1 60.4 0.5 --- --- --- (n hexane) 9.5 6.8 008 0.2 92.3 0.7 (n hexane) 13.9 010 0.03 0.77 0.14 --- --- --- --- --- 4.1 011 131.1 --- - (n hexane) 4.4 001 15.1 0.7 17.7 1.1 2.1 ( 0.3 formaldehyde) 0.3 002 15.1 0.7 17.7 1.1 2.1 --- 0.3 0.3 (formaldehyde) 0.3 003 4.5 0.7 10.3 0.1 0.6 --- (n hexane) 0.3 004 1.3 0.2 3.0 0.1 0.2 --- --- --- Permitted 5.9 Controlled 005 1.4 16.8 7.7 31.5 --- 1.4 (benzene) 9.1 point source 3.4 emission 006 1.5 25.5 8.3 --- --- --- (benzene) 7.5 rate: 0.3 007 0.1 3.0 0.5 --- --- --- (n-hexane) 0.5 0.4 008 0.2 4.6 0.7 --- (n-hexane) 0.8 010 Point will not be on permit. APEN Exempt 011 --- 21.0* --- --- --- --- (n-hexane) 0.8 Total Permitted 39.2 52.2 65.9 33.9 5.0 1.4 18.8 emissions: 21.0 *Fugitive Section 7—Non-Criteria/Hazardous Air Pollutants Uncontrolled q�the emissions Controlled Emission Pollutant CAS# Emission Rate reportable? Rate(Ib/yr) (Ib/yr) Point 001 Formaldehyde 50000 453 Yes 453 Acetaldehyde 75070 26 No 26 Acrolein 107028 5 No 5 Benzene 71432 8 No 8 Page 5 Toluene 108883 83 No 83 Point 002 Formaldehyde 50000 453 Yes 453 Acetaldehyde 75070 26 No 26 Acrolein 107028 5 No 5 Benzene 71432 8 No 8 Toluene 108883 83 No 83 Point 003 n-Hexane 110543 441 Yes 441 Point 004 n-Hexane 110543 126 No 126 Point 005 Benzene 71432 145,320 Yes 11,715 Toluene 108883 68,308 Yes 5,562 Ethylbenzene 100414 2,504 Yes 202 Xylenes 1330207 5,138 Yes 422 n-Hexane 110543 18,362 Yes 189 H2S 7783064 36,200 Yes 2,800 Point 006 Benzene 71432 140,560 Yes 6,822 Toluene 108883 90,648 Yes 4,435 Ethylbenzene 100414 5,769 Yes 284 Xylenes 1330207 11,960 Yes 592 n-Hexane 110543 90,595 Yes 2,908 Point 007 Benzene 71432 1,644 Yes 83 Toluene 108883 4,555 Yes 228 Ethylbenzene 100414 339 Yes 17 Xylenes 1330207 3,443 Yes 173 n-Hexane 110543 8,843 Yes 442 Point 008 Benzene 71432 2,520 Yes 126 Toluene 108883 6,965 Yes 348 Ethylbenzene 100414 519 Yes 26 Xylenes 1330207 5,265 Yes 263 n-Hexane 110543 13,524 Yes 676 Point 010—No HAPs above de minimis thresholds Page 6 Point 011 Benzene 71432 392 Yes 64 Toluene 108883 289 Yes 47 Ethylbenzene 100414 23 Yes 4 Xylenes 1330207 39 Yes 6 n-Hexane 110543 8,025 Yes 1,309 Note: Regulation 3, Part A, Section II.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. Section 8—Testing Requirements Will testing be required to show compliance with any emission rate or regulatory X Yes No standard? If"yes", complete the information listed below AIRS Point Frequency Pollutant Regulatory Basis Test Method 001 Initial NOx, CO Regulation No. 3, Part B, Section III.G.3,40 Stack Test CFR Part 60 Subpart KKKK§60. 002 Initial NOx, CO Regulation No. 3, Part B, Section III.G.3,40 Stack Test CFR Part 60 Subpart KKKK§60.4335 001 Quarterly NOx, CO State only requirement Portable Analyzer 002 Quarterly NOx, CO State only requirement Portable Analyzer 003 Initial NOx Regulation No. 3, Part B, Section III.G.3 Stack Test 004 Initial NOx Regulation No. 3, Part B, Section III.G.3 Stack Test 005 Initial and VOC, HAP Regulation No. 3, Part B Section III.E Extended Sour Gas annually Analysis 005 Initial and SO2, CO, Regulation No. 3, Part B, Section III.G.3 Stack Test annually NOx, VOC g 006 Initial and VOC, HAP Regulation No. 3, Part B Section III.E Extended Wet Gas annually Analysis 006 Initial NOx Regulation No. 3, Part B, Section III.G.3 Stack Test 006 Initial and Opacity Regulation No. 7 Section XVII.B.2.b EPA Method 22 weekly Initial and 007 weekly Opacity Regulation No. 7 Section XVII.B.2.b EPA Method 22 007 Initial NOx, Regulation No. 3, Part B, Section III.G.3 Stack Test 008 Initial and Opacity Regulation No. 7 Section XVII.B.2.b EPA Method 22 weekly 008 Initial NOx Regulation No. 3, Part B, Section III.G.3 Stack Test Initial and VOC, HAP State only requirement Extended Gas Analysis 011 annually Initial VOC, HAP State only requirement Component Hard Count Section 9—Source Classification Are all the points on permit 14WE1326 new X Yes No previously un-permitted sources? What is the existing facility classification? True X Synthetic Major Minor Minor Classification relates to what programs? X Title V X PSD X NA NSR X MACT Is this a modification to an existing stationary Yes X No source? Page 7 If"yes"what kind of modification? Minor 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? NON,VOC, and CO For Reg. 3, Part B, III.C.1.a (emissions increase>25/50 tpy)? X Yes No For Reg. 3, Part B, III.C.1.c.iii (subject to MACT)? Yes X No For Reg. 3, Part B, III.C.1.d (synthetic minor emission limits)? X Yes No For Reg. 3, Part D, IV(projects subject to PSD)? Yes X No Section 11 — Regulatory Review AIRS Point 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 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, 001-008, 011 1992)) in all subsections of Section II.A and B of this regulation. Section II.A.5-Smokeless Flare or Flares for the Combustion of Waste Gases No owner or operator of a smokeless flare or other flare for the combustion of waste gases shall allow or cause emissions into the atmosphere of any air pollutant which is in excess of 30% opacity for a period or periods aggregating more than six minutes in any sixty consecutive minutes. Section III.A.1 - No owner or operator shall cause or permit to be emitted into the atmosphere from any fuel-burning equipment, particulate matter in the flue gases which exceeds the following: For fuel burning equipment with designed heat inputs greater than 1x106 BTU per 001-004 hour, but less than or equal to 500x106 BTU per hour, the following equation will be used to determine the allowable particulate emission limitation. PE=0.5(FI)-o.267 Where: PE= Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. Section VI.B.4.c - Emissions of sulfur dioxide shall not emit sulfur dioxide in excess of the 001, 002 following combustion turbine limitations.: Combustion Turbines with a heat input of less than 250 Million BTU per hour: 0.8 pounds of sulfur dioxide per million BTU of heat input. 003-005 Section VI.B.5.a -Any new source of sulfur dioxide not specifically regulated above shall limit emissions to not more than two(2)tons per day of sulfur dioxide. 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 001-008, 011 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 Criteria Pollutants: For criteria pollutants, Air Pollutant Emission Notices are required for: 001-008, 011 each individual emission point in a non-attainment area with uncontrolled actual emissions of one ton per year or more of any individual criteria pollutant(pollutants are not summed) for which the area is non-attainment. Page 8 Part B—Construction Permit Exemptions Applicant is required to obtain a permit since uncontrolled emissions from this facility are greater than the permitting thresholds (Reg. 3, Part B, Section II.D.2.a) 001-008, 011 Section III.D.2—RACT Requirements Minor sources in designated nonattainment or attainment/maintenance areas that are otherwise not exempt pursuant to Section II.D. of this Part, shall apply Reasonably Available Control Technology for the pollutants for which the area is nonattainment or attainment/maintenance. Part B, III.D.2 - RACT requirements for new or modified minor sources This section of Regulation 3 requires RACT for new or modified minor sources located in nonattainment or attainment/maintenance areas. This source is located in the 8-hour ozone 005 nonattainment area. This amine unit is controlled by a VRU with a back-up flare and an RTO to meet RACT requirements. Part B, III.D.2- RACT requirements for new or modified minor sources This section of Regulation 3 requires RACT for new or modified minor sources located in nonattainment or attainment/maintenance areas. This source is located in the 8-hour ozone 006 nonattainment area. This glycol unit is controlled by a VRU and enclosed combustors to meet RACT requirements. Part B, III.D.2- RACT requirements for new or modified minor sources This section of Regulation 3 requires RACT for new or modified minor sources located in 007 nonattainment or attainment/maintenance areas. This source is located in the 8-hour ozone nonattainment area. These tanks are controlled by an enclosed combustor to meet RACT requirements. Part B, III.D.2 - RACT requirements for new or modified minor sources This section of Regulation 3 requires RACT for new or modified minor sources located in nonattainment or attainment/maintenance areas. This source is located in the 8-hour ozone 008 nonattainment area. Operator is using submerged fill (0.6 saturation factor), therefore, RACT requirements are satisfied. This loadout is also being controlled by an enclosed combustor. Part B, III.D.2 - RACT requirements for new or modified minor sources This section of Regulation 3 requires RACT for new or modified minor sources located in 011 nonattainment or attainment/maintenance areas. This source is located in the 8-hour ozone nonattainment area. These fugitives are subject to an LDAR program per NSPS OOOO. Part C—Operating Permit Requirements 001-008, 011 Applicant is not required to obtain an operating permit since potential emissions from this facility do not exceed the major source 100 tons per year permitting threshold for criteria pollutants or the 25 tons per year permitting threshold for hazardous air pollutants. Regulation 6- New Source Performance Standards NSPS KKKK: For combustion turbines with heat input at peak load equal to or greater than 10 MMBtu/hr and commenced construction, modification or reconstruction after February 18, 2005. 001, 002 This source subject to NSPS KKKK? Yes Why? These turbines will be constructed after the threshold date, so therefore, subject to NSPS KKKK. NSPS A-Source is subject to Regulation No. 6, Part A, Subpart A, General Provisions Page 9 Part B, Section II.C - Standard for Particulate Matter—On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere of any particulate matter which is: (i) For fuel burning equipment generating greater than one million but less than 250 million Btu per hour heat input, the following equation will be used to determine the 001-004 allowable particulate emission limitation: PE=0.5(FI)-°26 Where: PE is the allowable particulate emission in pounds per million Btu heat input. Fl is the fuel input in million Btu per hour. (ii) Greater than 20 percent opacity. Part B, Section II.D.3.a-Standard for Sulfur Dioxide—Combustion Turbines—On and after the date on which the required performance test is completed, no owner or operator 001, 002 subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere sulfur dioxide in excess of: Sources with a heat input of less than 250 million Btu per hour: 0.8 lbs. SO2/million Btu. NSPS Dc: for steam generating units for which construction, modification or reconstruction is commenced after June 9, 1989 and that have a maximum design heat input capacity of greater than or equal to 10 MMBtu/hr and less than or equal to 100 MMBtu/hr. 003 This source subject to NSPS Dc? Yes Why? According to the definition of a steam generating unit, this source meets this definition and has a design heat input capacity of 50 MMBtu/hr. (Point 004 is not subject because it has a design input rate of less than 10 MMBtu/hr) NSPS A-Source is subject to Regulation No. 6, Part A, Subpart A, General Provisions NSPS LLL: Each sweetening (amine) unit and each sweetening unit followed by a sulfur recovery unit; manufacturer date after January 24, 1984. This source is not subject to this subpart because construction will have commenced after 005 August 23, 2011. This source is instead subject to NSPS OOOO. NSPS OOOO: Each sweetening (amine) unit and each sweetening unit followed by a sulfur recovery unit; manufacturer date after August 23, 2011. This sweetening unit will have a design capacity less than 2 long tons/day H2S in the acid gas based on the information submitted in the application and is subject. NSPS Kb: for storage vessels greater than 19,800 gallons after 7/23/84. Is this source greater than 19,800 gallons (471 bbl)? Yes Is this source subject to NSPS Kb?Yes 007 NSPS OOOO-Each storage vessel which commenced construction, modification or reconstruction after August 23, 2011. These tanks will not be subject to NSPS OOOO since the unit will be controlled with an enclosed combustor, emissions will be less than the 6 tons VOC per year threshold. 008 No applicable subpart. This facility is not a bulk gasoline terminal. NSPS OOOO-Equipment Leaks of VOC from onshore natural gas processing plants. Affected facilities at onshore natural gas facilities(any processing site engaged in the extraction of natural gas liquids from field gas,fractionation of mixed natural gas liquids (NGLs)or both which commenced construction, modification or reconstruction after August 23, 2011. 011 Is this source at a"natural gas processing plant?" Yes Is this source subject to NSPS OOOO? Yes This source is a natural gas processing plant that is extracting NGLs. The equipment covered by this point was constructed after the applicability date of the rule and are therefore subject to its provisions. NSPS A-Source is subject to Regulation No. 6, Part A, Subpart A, General Provisions Regulation 7—Volatile Organic Compounds Section II.C.2-All new sources shall utilize controls representing RACT, pursuant to 001-008, 011 Regulation Number 7 and Regulation Number 3, Part B, Section III.D., upon commencement of operation. Page 10 Section XII.C.1.d - The combustion device used to control emissions of volatile organic compounds from these units to comply with Section XII.D shall be enclosed, have no visible emissions, and be designed so that an observer can, by means of visual observation from 006, 007 the outside of the enclosed combustion device, or by other means approved by the Division, determine whether it is operating properly. The operator shall comply with all applicable requirements of Section XII. Is this source subject to the control requirements of MACT HH? (Regulation 8-Hazardous Air Pollutants review). No 006 Is this source subject to the exemptions under MACT HH (i.e. throughput exemption less than 3 MMSCFD or benzene exemption of less than 1984 Ib/yr)? No Section XII.H: Is this source located in the non-attainment area? Yes 006 This source is subject to Regulation 7, Section XII.H. 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 at least 90 percent through the use of air pollution control equipment. Section XVII.B.2—General requirements for air pollution control equipment used to 005-008 comply with Section XVII Source is subject to these requirements. Section XVII.D(State only enforceable). 006 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. Section XVII.C - Emission reduction from condensate storage tanks at oil and gas exploration and production operations, natural gas compressor stations, natural gas drip stations and natural gas processing plants. 007 These requirements will apply to the condensate storage tanks because uncontrolled actual emissions exceed 6 tons per year of VOC. (The produced water tanks at this facility, point 009, are below the threshold of 6 tpy and are not subject to the requirements under XVII.C) No sections apply. Per Regulation 7, Section VI.C, a terminal is defined as a petroleum liquid storage and distribution facility that has a daily average throughput of more than 008 76,000 liters of gasoline(20,000 gallons), which is loaded directly into transport vehicles. This facility is neither a terminal, nor a bulk plant per definitions in Reg 7, Section VI.C. Section XII.G - If facility is a natural gas processing plant located in non-attainment area, then subject to Section XII.G. 011 This source is a natural gas processing plant in non-attainment. Therefore, it is subject to Section XII.G. The provisions require the facility to comply with NSPS Subpart KKK. However, the fugitive components are also subject NSPS Subpart OOOO, which is more stringent than Subpart KKK. Regulation 8 Hazardous Air Pollutants 001-005, None 007-008, 011 Page 11 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 006 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. This dehydrator is not located within an urban cluster or within two miles of an urban area, and is subject to the optimal circulation rate work practice standard in HH. 008 MACT EEEE: Not subject because minor source of HAPs Section 12—Aerometric Information Retrieval System Coding Information Fugiti Overall Process Throughput Emission Pollutant/Emission Point Process Description limit Factor CAS# (YENye) Factor Source Control 0.0472 NOx N Manufacturer 0 lb/MMBtu 0.0553 CO N Manufacturer 0 lb/MMBtu 0.0021 VOC N AP-42,Table 0 01 Combustion 637.9 lb/MMBtu 3.1-2a 001 Turbine MMscf/yr 0.0034 AP-42,Table lb/MMBtu SO2 N 3.1-2a 0 0.0066 PM/PM1o/ AP-42,Table lb/MMBtu PM2.5 N 3.1-2a 0 0.00071 Formaldehyde/ N AP-42,Table 0 lb/MMBtu 50000 3.1-3 SCC 20200201 —Turbine(natural gas) 0.0472 NOx N Manufacturer 0 lb/MMBtu 0.0553 CO N Manufacturer 0 lb/MMBtu 0.0021 VOC N AP-42, Table 0 01 Combustion 637.9 Ib/MMBtu 3.1-2a 002 Turbine MMscf/yr 0.0034 SO2 N AP-42, Table 0 lb/MMBtu 3.1-2a 0.0066 PM/PM 1o/ AP-42, Table lb/MMBtu PM2.5 N 3.1-2a 0 0.00071 Formaldehyde/ N AP-42, Table 0 lb/MMBtu 50000 3.1-3 SCC 20200201 —Turbine(natural gas) Approved by Bailey Smith 37 lb/MMscf NOx N (CDPHE) 0 4/3/2013—see section 13) 01 Hot oil 245 84 Ib/MMscf CO N AP-421.4 table 0 003 heater MMscf/yr AP-42,Table 5.5 Ib/MMscf VOC N 1.4-2 0 5.0 lb/MMscf PM/PMio/ N Manufacturer 0 PM2.5 1.8 Ib/MMscf n-Hexane/ N AP-42,Table 0 110543 1.4-3 SCC 31000404—Process heaters; Natural gas Page 12 Approved by Bailey Smith 37 lb/MMscf NOx N (CDPHE) 0 4/3/2013—see section 13) Hot 01 oheatell r MMscf/yr c 84 lb/MMscf CO N AP-42, Table 0 0041.4-1 5.5 lb/MMscf VOC N AP 42, Table 0 1.4-2 5.0 lb/MMscf PM/PMio/ N Manufacturer 0 PM2.5 SCC 31000404— Process heaters; Natural gas AP-42,Table 0.068 13.5-1 (Gas MMscf/yr lb/MMBtu NOx N Heat Content 0 (Acid 12.5 btu/scf) Waste AP-42,Table Gas) 0.37 CO N 13.5-1 (Gas 0 lb/MMBtu Heat Content 12.5 btu/scf) Mass Balance 0.7504 SO2 N using H2S 0 lb/MMscf composition from ProMax 01 Amine Unit 0.431 H2S N ProMax 92.4 005 lb/MMscf 83,950 17.42 VOC N ProMax 97.8 MMscf/yr lb/MMscf (Total 1.731 Benzene/ N ProMax 91.6 Plant lb/MMscf 71432 Volume) 0.814 Toluene/ N ProMax 91.5 lb/MMscf 108883 0.030 Ethylbenzene N ProMax 91.6 lb/MMscf /100414 0.061 Xylene/ N ProMax 91.5 lb/MMscf 1330207 0.219 n-Hexane/ N ProMax 99.2 lb/MMscf 110543 SCC 31000305—Gas Sweetening; Amine Process AP-42, Table 0.068 13.5-1 (Gas lb/MMBtu NOx N Heat Content 0 1067 btu/scf) AP-42, Table 0.37 13.5-1 (Gas lb/MMBtu CO N Heat Content 0 1067 btu/scf) 20.3977 VOC N GlyCalc 96.8 01 Glycol 83,950 lb/MMscf Dehydrator MMscf/yr 1.6744 Benzene/ 006 N GlyCalc 95.1 lb/MMscf 71432 1.0798 Toluene/ lb/MMscf 108883 N GlyCalc 95.0 0.0687 Ethylbenzene N GlyCalc 95.1 lb/MMscf /100414 0.1428 Xylene/ N GlyCalc 95.0 lb/MMscf 1330207 1.0792 n-Hexane/ N GlyCalc 96.5 lb/MMscf 110543 SCC 31000301 —Glycol Dehydrator; reboiler still vent; Triethylene Glycol Condensate AP 42,Table 007 01 Storage 912,500 0.068 NOx N 13.5 1 (Gas 0 Tanks bbl/yr lb/MMBtu Heat Content 3397 btu/scf) Page 13 AP-42, Table 0.37 13.5-1 (Gas lb/MMBtu CO N Heat Content 0 3397 btu/scf) 0.132 EPA Tank lb/bbl VOC N 4.09d 95 0.00180 Benzene/ EPA Tank lb/bbl 71432 N 4.09d 95 0.00499 Toluene/ EPA Tank lb/bbl 108883 N 4.09d 95 0.00037 Ethylbenzene N EPA Tank 95 lb/bbl /100414 4.09d 0.00377 Xylene/ N EPA Tank 95 lb/bbl 1330207 4.09d 0.010 n-Hexane/ EPA Tank lb/bbl 110543 N 4.09d 95 SCC 40400311 —Fixed Roof Tank; Condensate,Working + Breathing + Flashing losses AP-42,Table 0.068 13.5-1 (Gas lb/MMBtu NOx N Heat Content 0 3397 btu/scf) AP-42,Table 0.37 CO N 13.5-1 (Gas 0 lb/MMBtu Heat Content 3397 btu/scf) 4.82 AP-42 Chapter VOC N 95 lb/1000 gal 5.2 Equation 1 AP-42 Chapter 0.0656 Benzene/ 5.2 Equation 1 lb/1000 gal 71432 N with mass 95 Truck fraction 912,500 AP-42 Chapter 01 Condensate 008 Loadout bbl/yr 0.0076 Toluene/ N 5.2 Equation 1 95 lb/1000 gal 108883 with mass fraction AP-42 Chapter 0.0006 Ethylbenzene N 5.2 Equation 1 95 lb/1000 gal /100414 with mass fraction AP-42 Chapter 0.0058 Xylene/ 5.2 Equation 1 lb/1000 gal 1330207 N with mass 95 fraction AP-42 Chapter 0.3529 n-Hexane/ 5.2 Equation 1 lb/1000 gal 110543 N with mass 95 fraction SCC 40600132—Crude Oil; Submerged Loading (Normal Service) Turbine 0.69 2242.04 Engineering 01 Purging MMscf/yr lb/MMscf VOC N Calculation 0 010 Blowdown SCC 20200201 —Turbine(natural gas)*Turbine Purging Blowdown Maintenance Emissions Several Emission Factors VOC Y EPA-453/R-95- 84 Used for 017 Table 2-4 Various Fugitive Components 011 01 VOC Leak N/A Emissions N/A Benzene/ Y 84 71432 N/A Toluene/ Y HAP wt 84 108883 fraction in VOC n-Hexane/ N/A 110543 Y 84 Page 14 SCC 31000220—All Equipment Leak Fugitives (Valves, Flanges, Connections, Seals, Drains) _ Section 13—Miscellaneous Application Notes AIRS Points 001 &002 Natural gas turbines A permit will be issued because the uncontrolled emissions are greater than the permitting threshold for a non- attainment area. PM,VOC, and SO2 emissions were calculated using emission factors from AP-42 table 3.1-2a: VOC= 0.0021 lb 999 Btu* 637.9 MMscf 1 T =0.67 TPY MMBtu scf yr 2000 lb PM(0.0066 lb/MMBtu) 2.10 TPY SO2(0.0034 Ib/MMBtu)-* 1.08 TPY All Particulate Matter is assumed to be 2.5 microns or less. HAP emissions were calculated using emissions from AP-42 Table 3.1-3 Acetaldehyde= 0.00004 lb 999 Btu 637.9 MMscf =25.5 lb/yr MMBtu scf yr Acrolein(0.000006 lb/MMBtu) 4.1 lb/yr Benzene(0.000012 lb/MMBtu)--p 7.7 lb/yr Formaldehyde(0.00071 lb/MMBtu)--*452.5 lb/yr Toluene(0.00013 lb/MMBtu)—>82.8 lb/yr Solar Turbines manufacturer data emission rates were provided for NOx and CO in lb/hr(and TPY). New Emission factors were generated for so that they are consistent with other emission factors at the facility. NOx= 3.43 lb 8760 hr yr scf =0.0472 lb/MMBtu hr yr 637.9 MMscf 999 btu CO= 4.02 lb 8760 hr yr scf =0.05531b/MMBtu hr yr 637.9 MMscf 999 btu NOx(0.0472 lb/MMBtu)—> 15.02 TPY CO(0.0553 lb/MMBtu)—> 17.6 TPY *The LHV of the Fuel Gas Properties provided in the Solar Turbines was converted to HHV for conservative permitting purposes. This conversion was done by DCP's rule of thumb of HHV= LHV* 1.1 LHV* 1.1 =908 btu/scf* 1.1 = HHV=999 btu/scf Page 15 AIRS Point 003 Hot Oil Heater A permit will be issued because the uncontrolled emissions are greater than the permitting threshold for a non- attainment area. Note that DCP chose to limit the capacity of the heater to 63.5%of full utilization.This is requested by the fuel use restriction of 245 MMscf/yr. (100%utilization—>44 MMBtu/hr*8760 hr/yr/999 MMBtu/scf=385.8 MMscf/yr) CO emissions calculated with emission factors from AP-42 Table 1.4-1, VOC emissions calculated using emission factors from AP-42 Table 1.4-2, PM emissions calculated using emission factors provided by Optimized Process Furnaces Manufacturer Guarantee, HAP emissions calculated using emission factors from AP-42 Table 1.4-3, and NOx emission calculated using emission factors approved by the APCD on 4/3/2013*. CO= 84 lb 245 MMscf 1 T lb =10.29 TPY MMscf VOC(5.5 lb/MMscf)-+0.67 TPY PM(5.0 lb/MMscf)—+0.61 TPY NOx(37 lb/MMscf)—>4.53 TPY n-Hexane= 1.8 lb 245 MMscf =441 lb/yr MMscf yr *History of NOx emission factor for hot oil heater: -In 2013,while working on a similar project for DCP,the source was contacted regarding the emission factor provided with the application of 25 lb/MMscf. The source was asked to provide documentation from the manufacturer guaranteeing the proposed emission factor.The manufacturer's response asserted the unit was capable of emissions "as low as"the proposed rate.The Division accepts manufacturer's certifications that guarantee"not to exceed"emission rates.The Division did not consider the provided documentation which states an"as low as"emission rate to be sufficient. Based on review of test data of other hot oil heaters operating at other gas plants,the average tested emission rate is 0.037 lb/MMBtu(converting to lb/MMscf=0.037 lb/MMBtu*999 Btu/scf=37 lb/MMscf). The Division notified the source that we would be willing to accept this rate with performance testing verification. DCP proposed to permit the heater at 37 lb/MMscf,to which the Division agreed. -Based on this decision made for a very similar DCP project,the Division is again willing to accept this emission rate with performance testing verification. DCP is accepting a fuel use limit on the emission unit to restrict emissions below potential to emit. This limit is required to enable this permit to remain below the 40 TPY NOx threshold and the 5 TPY PM2.5 threshold for ambient air impact modeling. Page 16 AIRS Point 004 Hot Oil Heater A permit will be issued to limit the potential to emit of this source. None of the emissions are above permitting thresholds, but without a federally enforceable limit on the PTE, the source would breach ambient air quality modeling thresholds. Note that DCP chose to limit the capacity of the heater to 83%of full utilization. This is requested by the fuel use restriction of 70 MMscf/yr. (100% utilization >9.6 MMBtu/hr*8760 hr/yr/999 MMBtu/scf= 85 MMscf/yr) CO emissions calculated with emission factors from AP-42 Table 1.4-1, VOC emissions calculated using emission factors from AP-42 Table 1.4-2, PM emissions calculated using emission factors provided by Optimized Process Furnaces Manufacturer Guarantee, HAP emissions calculated using emission factors from AP-42 Table 1.4-3, and NOx emission calculated using emission factors approved by the APCD on 4/3/2013*. CO= 84 lb 70MMscf 1 T =2.94 TPY MMscf yr 2000 lb VOC(5.5 lb/MMscf)->0.19 TPY PM(5.0 lb/MMscf)—>0.18 TPY NOx(37 lb/MMscf)—> 1.30 TPY n-Hexane= 1.8 lb 70 MMscf =126 lb/yr MMscf yr *History of NOx emission factor for hot oil heater: -In 2013,while working on a similar project for DCP,the source was contacted regarding the emission factor provided with the application of 25 lb/MMscf. The source was asked to provide documentation from the manufacturer guaranteeing the proposed emission factor.The manufacturer's response asserted the unit was capable of emissions "as low as"the proposed rate. The Division accepts manufacturer's certifications that guarantee"not to exceed"emission rates.The Division did not consider the provided documentation which states an"as low as"emission rate to be sufficient. Based on review of test data of other hot oil heaters operating at other gas plants, the average tested emission rate is 0.037 lb/MMBtu (converting to lb/MMscf=0.037 lb/MMBtu*999 Btu/scf=37 lb/MMscf). The Division notified the source that we would be willing to accept this rate with performance testing verification. DCP proposed to permit the heater at 37 lb/MMscf,to which the Division agreed. -Based on this decision made for a very similar DCP project,the Division is again willing to accept this emission rate with performance testing verification. DCP is accepting a fuel use limit on the emission unit to restrict emissions below potential to emit. This limit is required to enable this permit to remain below the 40 TPY NOx threshold and the 5 TPY PM2.5 threshold for ambient air impact modeling. Page 17 AIRS Point 005 Amine unit A permit will be issued because the uncontrolled emissions are greater than the permitting threshold for a non- attainment area. The table below summarizes the inputs to the process simulation (Promax) used to calculate PTE for this equipment. Process Parameter Value Inlet gas temperature 78.14°F Inlet pressure 900.5 psia Throughput 83,950 MMscf/yr Lean amine circulation rate 945 gpm Lean amine concentration 50 wt% Flash tank temperature 158°F Flash tank pressure 72.33 psia Inlet composition Estimated from representative DCP source Acid Gas Stream Emissions: Uncontrolled emissions from the acid gas stream (routed to a regenerative thermal oxidizer—RTO +vented during RTO downtine)from the Promax simulation: VOC = 166.9 +7.11 = 174.01 TPY Benzene=64.47+2.75 =67.22 TPY Toluene=30.62 + 1.3 = 31.92 TPY Ethylbenzene= 1.11 + 0.05= 1.16 TPY Xylenes=2.32+ 0.10=2.42 TPY n-Hexane= 0.76 +0.03 =0.79 TPY H2S = 17.34+ 0.62 = 17.96 TPY These emissions are controlled with an RTO that achieves 96% destruction efficiency during up-time (a 20% buffer is used for conservatism with the exception of H2S emissions because these are already conservatively estimated). During RTO downtime, 3.6%of the year, the acid gas stream is vented directly to atmosphere. While the manufacturer of this unit guarantees a 99%control efficiency, the permittee is claiming a 96% control efficiency.A stack test will be required on the unit to confirm control efficiency. The unit is a smokeless combustion device and no particulate matter emissions are expected according the unit's manufacturer. Controlled emissions example calculations for acid gas stream: VOC = 166.9 TPY*(1 - 0.96)* 1.2) + (166.9 TPY*0.036* 1.2) = 15.22 TPY Benzene=5.84 TPY Toluene=2.77 TPY Ethylbenzene=0.10 TPY Xylenes= 0.21 TPY n-Hexane=0.69 TPY H2S = 17.34 TPY* (1 -0.96)+ 17.34 TPY* 0.036 = 1.32 TPY NOx and CO emissions were calculated using emission factors from AP-42 Table 13.5-1; based on the manufacturer's specification sheet for the RTO, the HHV is limited to 12.5 Btu/scf: NOx= 0.068 lb 12.5 Btu 7.86 MMscf 365 day T =1.22 TPY MMBtu scf day yr 2000 lb CO= 0.37 lb 12.5 Btu 7.86 MMscf 365 day T =6.63 TPY MMBtu scf day yr 2000 lb Page 18 AIRS Point 005 Amine unit-Continued Flash Tank Stream Emissions: Uncontrolled emissions from the flash tank stream (routed to a vapor recovery unit -VRU)from the Promax simulation: VOC= 557.2 TPY Benzene= 5.44 TPY Toluene =2.23 TPY Ethylbenzene = 0.09 TPY Xylenes= 0.15 TPY n-Hexane = 8.39 TPY H2S = 0.11 TPY These emissions are controlled with a VRU that achieves a 100% control efficiency during up-time (a 20% buffer is used for conservatism with the exception of H2S emissions because these are already conservatively estimated). During VRU downtime, 5% of the year, the flash stream is routed to a back-up emergency flare that achieves a 95% destruction efficiency. Controlled emissions example calculations for flash tank stream: VOC = 557.2 TPY* (1 -0.95) * (1 -0.95) * 1.2 = 1.67 TPY Benzene= 0.0163 TPY Toluene=0.0067 TPY Ethylbenzene=0.00028 TPY Xylenes = 0.00044 TPY n-Hexane= 0.03 TPY H2S = 0.11 TPY* (1 -0.95) * (1 -0.95) = 0.000275 TPY Total SOx emissions for the entire amine unit were calculated using a mass balance: SOx(RTO)= 17.34 TPY-1.32 TPY H2S 64.06 Ib/Ibmol SOx 30.11 TPY 34.08 Ib/Ibmol H2S SOx(Flare)= 0.11 TPY-2.75e-4 TPY H2S 64.06 Ib/Ibmol SOx 0.21 TPY 34.08 Ib/Ibmol H2S Total Emissions from Amine Unit: Acid Gas Stream Flash Tank Stream Total Emissions Emission Factors (TRY) (TPY) (TRY) (ib/MMscf) Component ;,, Uncon. Controlled Uncon. Controlled Uncon. Controlled Uncon. Controlled VOC 174.01 15.22 557.2 1.67 731.2 16.8 17.42 0.402 Benzene 67.22 5.84 5.44 0.0163 7.66 5.86 1.731 0.140 Toluene 31.92 2.77 2.23 0.0067 34.15 2.78 0.814 0.067 Ethylbenzene 1.16 0.10 0.09 0.00028 1.25 0.10 0.030 0.0024 Xylenes 2.42 0.21 0.15 0.00044 2.47 0.21 0.061 0.0050 n-Hexane 0.79 0.07 8.39 0.03 9.18 0.09 0.219 0.0017 H2S 17.96 1.32 0.11 0.000563 18.07 1.32 0.431 0.033 SOx --- 31.3 --- 0.21 --- 31.5 --- 0.750 CO --- 6.63 --- 1.06 --- 7.69 --- 0.183 NOx --- 1.22 --- 0.19 --- 1.41 --- 0.033 Page 19 AIRS Point 006 Glycol Dehydrator A permit will be issued because the uncontrolled emissions are greater than the permitting threshold for a non- attainment area. In order to determine emissions,the operator used GRI GlyCALC 4.0. The source assumed the inlet gas temperature of 110°F and a pressure of 850 psig. The permitted glycol recirculation rate is 40 gpm. The source is limiting capacity to minimize emissions. The inlet wet gas stream in the GlyCalc model was based off of the amine promax simulation model. The amine unit sweetened gas stream is connected to the dehydrator. The permit will require periodic extended gas analysis to support actual emission calculation because the gas analysis provided was for a similar DCP facility and a simulation model was used to predict the emissions. Regenerator Still Vent Emissions: Uncontrolled emissions from the TEG regenerator still vent(routed to an enclosed combustor)from Gly-Calc Simulation: VOC=492.51 TPY Benzene=68.11 TPY Toluene=44.29 TPY Ethylbenzene=2.84 TPY Xylenes= 5.92 TPY n-Hexane =28.23 TPY These emissions are controlled by an enclosed combustor that achieves a 95% destruction efficiency. An example calculation is shown below with the other controlled emissions values from the regenerator still vent. VOC=492.51 TPY*(1 -0.95) =24.63 TPY Benzene=3.41 TPY Toluene=2.21 TPY Ethylbenzene=0.14 TPY Xylenes=0.30 TPY n-Hexane= 1.41 TPY NOx and CO emissions were calculated using emission factors from AP-42 Table 13.5-1. From the GlyCALC simulation composition of this stream, the heat content of the gas was calculated to be 1067 btu/scf based on the individual component's heat content: NOx= 0.068 b 11 Btu 0.00403 MM scf 8f 2000 lb 60 hr T =1.48 TPY MMBtu scf CO= 0.37 lb 1231 Btu 0.00403 MM scf 8760 hr T =8.04 TPY MMBtu scf hr yr 2000 lb Flash Tank Stream Emissions: Uncontrolled emissions from the flash tank (routed to a VRU)from the Gly-CALC Simulation: VOC= 363.68 TPY Benzene=2.17 TPY Toluene= 1.03 TPY Ethylbenzene=0.04 TPY Xylenes=0.06 TPY n-Hexane = 17.07 TPY Page 20 AIRS Point 006 Glycol Dehydrator-Continued These emissions are controlled with a VRU that achieves a 100% control efficiency during up-time. During VRU downtime, 5% of the year, the flash stream is routed to a back-up emergency flare that achieves a 95% destruction efficiency. An example calculation is shown below with the other controlled emissions values from the flash tank. VOC = 363.68 TPY* (1 -0.95) *(1 -0.95) = 0.91 TPY Benzene =0.00544 TPY Toluene = 0.00257 TPY Ethylbenzene = 0.0001 TPY Xylenes = 0.00016 TPY n-Hexane= 0.04 TPY Total Emissions from the Dehydrator: Regenerator Stilt Flash Tank Stream Total Emissions Emission.Factors Vent(TRY) (TPY) (TPY) (tb/MMscf) Component Uncon. Controlled Uncon. Controlled Uncon. Controlled Uncon. Controlled VOC 492.51 24.63 363.68 0.91 856.2 25.5 20.40 0.608 Benzene 68.11 3.41 2.17 0.00544 70.3 3.42 1.67 0.082 Toluene 44.29 2.21 1.03 0.00257 45.32 2.23 1.08 0.053 Ethylbenzene 2.84 0.14 0.04 0.0001 2.88 0.14 0.069 0.0033 Xylenes 5.92 0.30 0.06 0.00016 5.99 0.30 0.142 0.0071 n-Hexane 28.23 1.41 17.07 0.043 45.3 1.45 1.08 0.035 I'' CO --- 8.04 --- 0.29 --- 8.33 --- 0.198 NOx --- 1.48 --- 0.05 --- 1.53 --- 0.036 Page 21 AIRS Point 007 Condensate storage tanks A permit will be issued because the uncontrolled emissions are greater than the permitting threshold for a non-attainment area. Because there will be no flash emissions associated with the loading of the tanks, EPA TANKS 4.09d was used to model working and breathing losses. VOC and HAP emissions were calculated based on the estimated emissions output from EPA TANKS and the wt% of the component in the extended gas analysis used. Example calculations are shown below: Total uncontrolled working and breathing emissions =60.37 TPY(99.999%VOC) VOC =60.37 TPY* 1.0 =60.37 TPY Benzene=60.37 TPY* .013287= 0.81 TPY Toluene=60.37 TPY*0.03682 =2.22 TPY Ethylbenzene=60.37 TPY*0.002743= 0.17 TPY Xylenes= 60.37 TPY* 0.0278 = 1.72 TPY n-Hexane=60.37 TPY* 0.0715=4.42 TPY The emissions from the tanks are routed to an enclosed flare that achieves a 95% destruction efficiency. Example calculations and controlled emission rates are shown below: VOC=60.37 TPY*(1 -0.95)= 3.02 TPY Benzene=0.04 TPY Toluene=0.11 TPY Ethylbenzene=0.01 TPY Xylenes=0.09 TPY n-Hexane=0.22 TPY Operator used AP-42 Table 13.5-1 emission factors for NOx and CO. The emission calculation for flared gas used heat input(calculated as an interpolated value based on the molecular weight of the flared gas obtained from EPA TANKS ) and the input flowrate (calculated with the ideal gas law to convert the mass emission rate from EPA TANKS to a Volume to use with the emission factors.) V= nRT/P n = (120732 lb/yr)/(66 Ib/Ibmol) = 1829.3 Ibmol/yr V= (1829.3 Ibmol/yr) *(10.731 scf*psi/R/Ibmol) *(519.67 R)/(14.7 psia) = 0.694 MMscf/yr NOx= 0.068 lb 3397 Btu 0.694 MMscf T =0.08 TPY MMBtu scf yr 2000 lb CO = 0.37 lb 3397 Btu 0.694 MMscf T =0.44 TPY MMBtu scf yr 2000 lb Page 22 AIRS Point 008 Truck Condensate Loadout A permit will be issued because the uncontrolled emissions are greater than the permitting threshold for a non- attainment area. AP-42: Chapter 5.2 Equation 1 L= 12.46*S*P*M/T L= loading losses in lb per 1000 gallons loaded S=Saturation Factor P=true vapor pressure of liquid loaded[psia] M =molecular weight of vapors[lb/lb-mole] T=temperature of bulk liquid loaded[deg. R] Units Basis S 0.6 Submerged loading: dedicated normal service P 5.0032 Psia Estimated based on extended natural gas sample at a DCP facility. M 66 lb/lb-mole Estimated based on extended natural gas sample at a DCP facility. T 512.45 Deg R Estimated based on extended natural gas sample at a DCP facility. L 4.81 lb VOC/10^3 gal 0.202 lb VOC/bbl This value is used to calculate annual emissions. Based on a throughput of 912,500 BBL/yr and the extended gas analysis, uncontrolled emissions are shown below: VOC = 0.202 lb/BBL* 912500 BBL/yr/(2000 lb/T) = 92.2 TPY Benzene= 92.2 TPY* 0.0133 = 1.23 TPY Toluene = 3.48 TPY Ethylbenzene = 0.26 TPY Xylenes=2.63 TPY n-Hexane = 6.76 TPY Emissions from the loadout are routed back to an enclosed flare that achieves a 95% destruction efficiency. Example calculations and controlled emission rates are shown below: VOC = 92.2 TPY* (1 —0.95) =4.62 TPY Benzene= 0.0628 TPY Toluene =0.174 TPY Ethylbenzene=0.0130 TPY Xylenes = 0.132 TPY n-Hexane =0.338 TPY Operator used AP-42 Table 13.5-1 emission factors for NOx and CO. The emission calculation for flared gas used heat input(calculated as an interpolated value based on the molecular weight of the flared gas obtained from EPA TANKS) and the input flowrate (calculated with the ideal gas law to convert the mass emission rate from the Loading Loss equation above to a Volume to use with the emission factors.) V= nRT/P n = (184625.5 lb/yr)/(66 Ib/Ibmol) =2797.34 Ibmol/yr V= (2797.34 Ibmol/yr) * (10.731 scf*psi/R/Ibmol) *(519.67 R)/(14.7 psia) = 1.06 MMscf/yr NOx= 0.068 lb 3397 Btu 1.06 MMscf T =0.123 TPY MMBtu scf yr 2000 lb CO= 0.37 lb 3397 Btu 1.06 MMscf T =0.667 TPY MMBtu scf yr 2000 lb Page 23 AIRS Point l 010 I Turbine Purging Slowdown ***On 2/20/2015 the operator sent in a revised calculation for this emission source based on the use of a residue gas analysis instead of the original inlet gas analysis used.The content of this section has been revised based on this submittal. An APEN exempt letter will be issued because the uncontrolled emissions are greater than the APEN reporting threshold for a non-attainment area. (This point was determined to be APEN Exempt and is filed under APEN Exempt number 15WE0192.XA) DCP estimated the emissions from the purging of the turbines with a conservative estimate of three blowdown events per month for each of the two turbines. Each purging event is assumed to take place for a maximum of 1 minute. The purging volume of 9.58 MMscf/min was estimated from similar events at another similar facility. Emissions from the turbine are not controlled. Calculations of uncontrolled emissions shown below: Total Volume,V= 3 events 12 Months 2 Turbines 1 min 0.00958 MMscf = 0.6898 MMscf/yr Month*Turbines yr event min Calculations 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(Q) 0.69 MMscf/yr 78.76712329 scf/hr MW 22.7337 Ib/Ib-mol 0.001890411 MMscf/d mole% MW Ibx/Ibmol mass fraction lb/hr lb/yr tpy Helium 0.0000 4.0026 0.000 0.000 0.00 0.00 0.00 CO2 0.4129 44.01 0.182 0.008 0.04 330.83 0.17 N2 0.3630 28.013 0.102 0.004 0.02 185.13 0.09 methane 90.6104 16.041 14.535 0.639 3.02 26461.80 13.23 ethane 6.8731 30.063 2.066 0.091 0.43 3761.79 1.88 propane 1.2493 44.092 0.551 0.024 0.11 1002.85 0.50 isobutane 0.1178 58.118 0.068 0.003 0.01 124.64 0.06 n-butane 0.2874 58.118 0.167 0.007 0.03 304.09 0.15 isopentane 0.0382 72.114 0.028 0.001 0.01 50.15 0.03 n-pentane 0.0380 72.114 0.027 0.001 0.01 49.89 0.02 cyclopentane 0.0000 70.13 0.000 0.000 0.00 0.00 0.00 n-Hexane 0.0098 86.18 0.008 0.000 0.00 15.38 0.01 cyclohexane 0.0000 84.16 0.000 0.000 0.00 0.00 0.00 Other hexanes 0.0000 86.18 0.000 0.000 0.00 0.00 0.00 heptanes 0.0000 100.21 0.000 0.000 0.00 0.00 0.00 methylcyclohexane 0.0000 98.19 0.000 0.000 0.00 0.00 0.00 224-TMP 0.0000 114.23 0.000 0.000 0.00 0.00 0.00 Benzene 0.0000 78.12 0.000 0.000 0.00 0.00 0.00 Toluene 0.0000 92.15 0.000 0.000 0.00 0.00 0.00 Ethylbenzene 0.0000 106.17 0.000 0.000 0.00 0.00 0.00 Xylenes 0.0000 106.17 0.000 0.000 0.00 0.00 0.00 C8+Heavies 0.0000 114 0.000 0.000 0.00 0.00 0.00 99.9999 VOC mass fraction: 0.037 Total VOC(Uncontrolled) 0.77 Page 24 AIRS Point I 011 I' Fugitive Component Leak Emissions A permit will be issued because the uncontrolled emissions are greater than the permitting threshold for a non- attainment area. The source is required to have a LDAR program in accordance with state and federal regulations. The following emission reductions have been approved by component type for the LDAR program. Component '' Control Efficiency Connections 30 Flanges 30 Open-Ends 75 Pumps 88 Valves 95 Other 75 Emissions were calculated using emission factors from EPA Protocol for Equipment Leak Emission Estimates, EPA, November 1995, EPA-453/R-95-017. The control factors for pumps and valves were taken from EPA's"LDAR—A Best Practices Guide"for a representative LDAR program. The control factors for the remaining component types are identical to Division approved control factors for similar LDAR programs implemented by DCP at other Colorado facilities. A 40%safety buffer has been applied to all fugitive component leak emissions. 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