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Home My WebLink About20142077.tiff STATE OF COLORADO John W.Hickenlooper,Governor Larry W MD,MSPH of S,0 Executive Director and Chief Medical Officer T r) Dedicated to protecting and improving the health and environment of the people of Colorado r .@ Y:** 4300 Cherry Creek Dr.S. Laboratory Services Division •1876 • Denver,Colorado 80246-1530 8100 Lowry Blvd. Phone(303)692-2000 Denver,Colorado 80230-6928 Colorado Department Located in Glendale,Colorado (303)692-3090 of Public Health www.colorado.gov/cdphe and Environment Weld County -Clerk to the Board 1150 O St PO Box 758 Greeley, CO 80632 July 3, 2014 Dear Sir or Madam: On July 9,2014,the Air Pollution Control Division will publish a public notice for DCP Midstream, LP— Rocky Compressor Station, in the The Greeley Tribune. 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 date the public notice is published. Please send any comment regarding this public notice to the address below. Colorado Dept. of Public Health & Environment APCD-SS-B I 4300 Cherry Creek Drive South Denver, Colorado 80246-1530 Attention: Clara Gonzales Regards, 7; RECEIVED `� ( JUL 0 9 2014 Clara Gonzales WELD COUNTY Public Notice Coordinator COMMISSIONERS Stationary Sources Program Air Pollution Control Division Enclosure 1)WIDLAc )e 7LCmml CER,Uf,3wtt)itt 2014-2077 —1— I �l-201q 9 Zing STATE OF COLORADO John W.Hickenlooper,Governor Larry Wolk, MD,MSPH �oF for Executive Director and Chief Medical Officer /re "` 90 Dedicated to protecting and improving the health and environment of the people of Colorado 1* A rr* ly 4300 Cherry Creek Dr.S. Laboratory Services Division ��, • 1876 -- Denver,Colorado 80246-1530 8100 Lowry Blvd. Phone(303)692-2000 Denver,Colorado 80230-6928 Colorado Department Located in Glendale,Colorado (303)692-3090 of Public Health www.colorado.gov/cdphe and Environment Website Title: DCP Midstream, LP—Rocky Compressor Station— Weld County Released To: The Greeley Tribune On: July 3,2014 Published: July 9, 2014 PUBLIC NOTICE OF A PROPOSED PROJECT OR ACTIVITY WARRANTING PUBLIC COMMENT 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: Rocky Compressor Station compressor station Section 26,T6N, R63 W Weld County The proposed project or activity is as follows: New compressor station consisting of two(2)turbines, one(1) TEG glycol dehydrator and combustor, truck loadout, pigging blowdowns and associated fugitives. 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.I.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 14WE0446 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 www.colorado.gov/cdphe/AirPublicNotices The Division hereby solicits submission of public comment from any interested person concerning the ability of the proposed project or activity to comply with the applicable standards and regulations of the Commission. The Division will receive and consider written public comments for thirty calendar days after the date of this Notice. Any such comment must be submitted in writing to the following addressee: Stephanie Chaousy Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South,APCD-SS-Bl Denver,Colorado 80246-1530 cdphe.commentsapcd@state.co.us STATE OF COLORADO aaF.=o� COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT r o ' AIR POLLUTION CONTROL DIVISION *" iti TELEPHONE: (303) 692-3150 S•,e,b42 CONSTRUCTION PERMIT PERMIT NO: 14W E0446 Issuance 1 DATE ISSUED: ISSUED TO: DCP Midstream, LP THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS: Natural gas compression facility, known as the Rocky Turbine Compressor Station, located in Section 26, Township 6N, Range 63W, in Weld County, Colorado. THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING: Facility AIRS Description Equipment ID Point One (1) natural gas fired combustion turbine (Solar Model Taurus 70 serial number: TBD), equipped with low NOx TURB-1 001 burners, site rated at 8,534 horsepower at 11,575 RPM. The turbine is design rated for a heat input of 72.21 MMBtu/hr at (HHV) 60°F ambient temperature. One (1) natural gas fired combustion turbine (Solar Model Taurus 70, serial number: TBD), equipped with low NOx TURB-2 002 burners, site rated at 8,534 horsepower at 11,575 RPM. The turbine is design rated for a heat input of 72.21 MMBtu/hr (HHV) at 60°F ambient temperature. One (1) Triethylene glycol (TEG) natural gas dehydration unit (make, model, serial number: not submitted) with a design capacity of 125 MMscf per day. This emissions unit is equipped with either one (1) electric pump or one (1) gas injection pump (make, model: not submitted) plus one backup pump with an operational capacity of 40 gallons per D-1 003 minute each. This unit is equipped with a flash tank, reboiler and still vent. Emissions from the still vent are routed to an enclosed combustor. Emissions from the flash tank are routed to a vapor recovery unit (VRU) which returns vapors back to the inlet of the compressor station. The VRU is estimated to be down one percent of the time. When the VRU is down, emissions from the flash tank are routed to an enclosed combustor. AIRS ID: 123/9C79 Page 1 of 27 NGEngine Version 2009-1 D Co do p e o Public Health and Environment Air Pollution Control Division Facility AIRS Description Equipment ID Point FUG 004 Equipment leaks (fugitive VOCs) from a natural gas compression facility. Enclosed combustor(manufacturer, model, SN: not ECD-1 005 submitted) controlling the TEG dehydrator non-condensable still vent emissions (Point 003) at a minimum control efficiency of 95%. L-1 007 Pressurized condensate truck loading. PIG 008 Associated blowdowns with pig launching and receiving activities. AIRS 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 accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as Attachment A. THIS PERMIT IS GRANTED SUBJECT TO ALL RULES AND REGULATIONS OF THE COLORADO AIR QUALITY CONTROL COMMISSION AND THE COLORADO AIR POLLUTION PREVENTION AND CONTROL ACT C.R.S. (25-7-101 et seq), TO THOSE GENERAL TERMS AND CONDITIONS INCLUDED IN THIS DOCUMENT AND THE FOLLOWING SPECIFIC TERMS AND CONDITIONS: REQUIREMENTS TO SELF-CERTIFY FOR FINAL AUTHORIZATION 1. YOU MUST notify the 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 III.G.1 and can result in the revocation of the permit. 2. Within one hundred and eighty days (180) after commencement of operation, compliance with the conditions contained 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.) AIRS ID: 123/9C79 Page 2 of 27 pCo do p e o Public Health and Environment Air Pollution Control Division 4. The operator shall complete all initial compliance testing and sampling as required in this permit and submit the results to the Division as part of the self-certification process. (Reference: Regulation No. 3, Part B, Section III.E.) 5. The 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) Monthly Limits: Facility AIRS Pounds per Month Emission Equipment ID Point SOx NO, VOC CO Type TURB-1 001 187 2,940 --- 2,940 Point TURB-2 002 187 2,940 --- 2,940 Point D-1 003 --- --- 5,168 --- Point FUG 004 --- --- 9,122 --- Fugitive ECD-1 005 --- 394 365 2,144 Point L-1 007 --- --- 221 --- Point PIG 008 --- --- 905 --- Point Facility-wide emissions of each individual hazardous air pollutant shall be less than 1,358.9 lb/month. Facility-wide emissions of total hazardous air pollutants shall be less than 3,958 lb/month. Annual Limits: Facility AIRS Tons per Year Emission Equipment ID Point SOx NO, VOC CO Type TURB-1 001 1.1 17.3 --- 17.3 Point TURB-2 002 1.1 17.3 --- 17.3 Point O-1 003 --- --- 30.4 --- Point FUG 004 --- --- 53.7 --- Fugitive ECD-1 005 --- 2.3 2.1 12.6 Point L-1 007 --- --- 1.3 --- Point PIG 008 --- --- 5.3 --- Point AIRS ID: 123/9C79 Page 3 of 27 DCo do p e o Public PollutionHealthand ControlEnvironment Division See "Notes to Permit Holder #4 for information on emission factors and methods used to calculate limits. Facility-wide emissions of each individual hazardous air pollutant shall be less than 8.0 tpy. Facility-wide emissions of total hazardous air pollutants shall be less than 23.3 tpy., During the first twelve (12) months of operation, compliance with both the monthly 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 synthetic minor status of this facility 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: • 25 tons per year of total hazardous air pollutants (HAP). 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.) 9. 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 TURB-1, 001, Low NOx burner combustion technology NOx TURB2, 002 D-1 003 Vapor recovery unit and Combustion device VOC, HAP (detailed in condition 21) 10. Point 008: The operator shall calculate actual emissions from this emissions point based on the most recent gas analysis, as required in the Compliance Testing and Sampling section of this permit. AIRS ID: 123/9C79 Page 4 of 27 Go l do n;p e o Public Health and Environment Air Pollution Control Division PROCESS LIMITATIONS AND RECORDS 11. This source shall be limited to the following maximum processing rates as listed below. Monthly records of the actual processing rate shall be maintained by the applicant and made available to the Division for inspection upon request. (Reference: Regulation 3, Part B, II.A.4) Process/Consumption Limits Facility AIRS Annual Monthly Limit Equipment Point Process Parameter Limit (31 days) ID TURB-1 001 Consumption of natural gas as fuel 618.3 52.5 MMscf/yr• MMscf/month TURB-2 002 Consumption of natural gas as fuel 618.3 52.5 MMscf/yr MMscf/month D-1 003 Natural gas throughput 45,625 3,875 MMscf/yr MMscf/month FUG 004 Not applicable ECD-1 005 Natural gas and waste gas throughput 66.7 5.7 MMscf/yr MMscf/month L-1 007 Condensate throughput 476,200 40,445 BBL/yr BBL/month PIG 008 Blowdown volume 677 Mscf/yr -- During the first twelve (12) months of operation, compliance with both the monthly and yearly consumption 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 consumption limits shall be determined on a rolling twelve (12) month total. By the end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate monthly consumption of natural gas and keep a compliance record on site or at a local field office with site responsibility, for Division review. STATE AND FEDERAL REGULATORY REQUIREMENTS 12. 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). 13. 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.) 14. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable) Turbines (AIRS Points 001 and 002) 15. 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: AIRS ID: 123/9C79 Page 5 of 27 Co do p e o Pu and Airblic PollutionHealth Control DivisionEnvironment D • §60.4320— Nitrogen Oxide Emissions Limits o (a) NOx emissions shall not exceed 25 ppm at 15% O2or 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 your stationary combustion turbine, air pollution control equipment, and monitoring equipment in a manner consistent with good air pollution control practices for minimizing emissions at all times including during startup, shutdown and malfunction. • §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. • H60.4400 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. 16. These units are subject to the Particulate Matter and Sulfur Dioxide Emission Regulations of Regulation 1 including, but not limited to, the following: a. No owner or operator shall cause or permit to be emitted into the atmosphere from any fuel-burning equipment, particulate matter in the flue gases which exceeds the following (Regulation 1, Section III.A.1): (1) For fuel burning equipment with designed heat inputs greater than 1x106 BTU per hour, but less than or equal to 500x106 BTU per hour, the AIRS ID: 123/9C79 Page 6 of 27 t' Co clomp e _ a"Public Health and Environment Air Pollution Control Division i i t following equation will be used to determine the allowable particulate emission limitation. PE=0.5(FI)-°s6 Where: PE = Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. b. The owner or operator shall not emit sulfur dioxide in excess of the following combustion turbine 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): 17. 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(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. 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. 18. The source is subject to the requirements of Regulation No. 6, Pad 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 AIRS ID: 12319C79 Page 7 of 27 Co do p e o Public HealthPollution andControl EnvironmentDivision 1M Ai 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. TEG Dehydrator(AIRS Point 0031 19. 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, VRU downtime 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. 20. The emissions that result from the flash tank associated with this dehydrator shall be recycled to the compressor station inlet and recompressed. The VRU used to control the flash tank is estimated to be down one percent of the time. When the VRU is down, emissions are controlled with an enclosed combustor. 21. This unit shall be configured such that the flash tank vapors are routed to the VRU to be recycled to the compressor station inlet and still vent vapors are routed to an enclosed combustor. The control system shall reduce uncontrolled emissions of VOC and HAP from the TEG dehydration unit to the emission levels listed in Condition 7, above. Operating parameters of the control equipment are identified in the operation and maintenance plan. (Reference: Regulation No.3, Part B, Section III.E.) 22. 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 is deemed exempt under §63.764 (e)(1), then maximum recirculation rate shall not exceed 40.0 gallons per minute. The owner or operator shall maintain weekly records of the actual lean glycol recirculation rate and make them available to the Division for inspection upon request. 23. 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. AIRS ID: 123/9C79 Page 8 of 27 �� x r Co r .ado • jp e r o Public Health and Environment i , Air Pollution Control Division This source shall comply with all applicable general provisions of Regulation 7, Section XII. 24. 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. 25. This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XVII.D (State only enforceable). Beginning May 1, 2008, uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas-condensate-glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by an average of at least 90 percent through the use of air pollution control equipment. This source shall comply with all applicable general provisions of Regulation 7, Section XVII. 26. 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 §63.760 (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. • §63.760 (f)(6) - The owner or operator of an affected area source that is not located in an Urban-1 county, as defined in §63.761, the construction or reconstruction of which commences on or after July 8, 2005, shall achieve compliance with the provisions of this subpart immediately upon initial startup or January 3, 2007, whichever date is later. • §63.764 - General Standards o §63.764 (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. • §63.764 (d)(2)(i) — Determine the optimum glycol circulation rate using the following equation: L„pr =1.75*3.0 gal TEG * F*(I—O) lb H20 24hr/day AIRS ID: 123/9C79 Page 9 of 27 DCo do p e o Public PollutionHealthand Control DivisionEnvironment Where: Loa-= Optimal circulation rate, gal/hr. F = Gas flowrate (MMSCF/D) I = Inlet water content (lb/MMSCF) O = Outlet water content (lb/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. I • §63.764 (d)(2)(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 altemate 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). • §63.764 (d)(2)(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 §63.774 (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: • §63.774 (b)(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. • §63.774 (b)(1)(i) — All applicable records shall be maintained in such a manner that they can be readily accessed. • §63.774 (b)(1)(ii) — The most recent 12 months of records shall be retained on site or shall be accessible from a central location by computer or other means that provides access within 2 hours after a request. • §63.774 (b)(1)(iii) — The remaining 4 years of records may be retained offsite. AIRS ID: 12319C79 Page 10 of 27 Co do p e o Public Health and Environment Air Pollution Control Division • §63.774 (b)(1)(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 §63.774 (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 §63.775 (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). • §63.775 (c)(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. • §63.775 (c)(7) - The information listed in paragraphs (c)(1)(i) through (v) of this section. This information shall be submitted with the initial notification. • §63.775 (c)(7)(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. • §63.775 (c)(7)(ii) - Calculation of the optimum glycol circulation rate determined in accordance with §63.764(d)(2)(i). • §63.775 (c)(7)(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. AIRS ID: 123/9C79 Page 11 of 27 D Co do p e o Public Health and Environment Air Pollution Control Division • §63.775 (c)(7)(iv) - The name of the manufacturer and the model number of the glycol circulation pump(s) in operation. • §63.775 (c)(7)(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 §63.775 (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: • §63.775 (f)(1) -A brief description of the process change; • §63.775 (f)(2) - A description of any modification to standard procedures or quality assurance procedures • §63.775 (f)(3) — Revisions to any of the information reported in the original Notification of Compliance Status Report under paragraph (d) of this section; and • §63.775 (f)(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. Fugitive Emissions (AIRS Point 004) 27. The operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent gas analysis, as required in the Compliance Testing and Sampling section of this permit. The operator shall maintain records of the results of component counts and sampling events used to calculate actual emissions and the dates that these counts and events were completed. These records shall be provided to the Division upon request. 28. The reciprocating compressors grouped with the fugitive emissions addressed by AIRS ID 004 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: • §60.5380(a) — Owner or operator must replace the centrifugal compressor rod packing according to either paragraph §60.5380(a)(1) or (2). (i) §60.5380(a)(1)- You must reduce VOC emissions from each centrifugal compressor wet seal fluid degassing system by 95.0 percent or greater. (ii) §60.5380(a)(2) - If you use a control device to reduce emissions, you must equip the wet seal fluid degassing system with a cover that meets the requirements of§60.5411(b), that is connected through a closed vent system that meets the requirements of§60.5411(a) and routed to a control device that meets the conditions specified in §60.5412(a), (b) and (c). As an alternative to routing the closed vent system to a control device, you may route the closed vent system to a process. AIRS ID: 123/9C79 Page 12 of 27 , Er" •Co do •p e 4 o Public Health and Environment ll I IlkA Air Pollution Control Division rp1 n_ • §60.5380(b) You must demonstrate initial compliance with the standards that apply to centrifugal compressor affected facilities as required by§60.5410(b). • §60.5380(c) You must demonstrate continuous compliance with the standards that apply to centrifugal compressor affected facilities as required by §60.5415(b). • §60.5380(d) You must perform the required notification, recordkeeping, and reporting as required by §60.5420.§60.5410 — Owner or operator must demonstrate initial compliance with the standards as detailed in §60.5410(b)(1). • §60.5415 — Owner or operator must demonstrate continuous compliance with the standards as detailed in §60.5415(b). • §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)(3), and §60.5420(c)(2). 29. Minor sources in designated nonattainment or attainment/maintenance areas that are otherwise not exempt pursuant to Section II.D. of Regulation No. 3, Part B, shall apply Reasonably Available Control Technology (RACT) for the pollutants for which the area is nonattainment or attainment/maintenance (Reference: Regulation No. 3, Part B, III.D.2.a). Compliance with the requirements of an inspection and repair program, as required by Condition 30, shall satisfy the requirement to apply RACT. 30. The operator shall use optical gas imaging (i.e. IR camera) to screen all pumps, valves, connectors, and pressure relief devices that contain or contact a process stream that is at least 10 percent VOC by weight. The operator shall perform screening on a semi- annual basis. The IR camera shall be maintained per the manufacturer's recommendations. In addition, the source shall follow procedures for implementing an alternative work practice for monitoring equipment for leaks as specified below: • Any emissions imaged by the optical gas instrument (i.e. IR camera) at the required detection sensitivity level qualify as a leak. Additionally, any indications of liquids dripping shall qualify as a leak. • The detection sensitivity level shall be 60 grams per hour which correlates to the least frequent monitoring schedule listed in Table 1 of 40 CFR 60 Subpart A. • The operator shall comply with the instrument specifications in 40 CFR 60.18(i)(1). • The operator shall comply with the daily instrument checks in 40 CFR 60.18(i)(2). • The operator shall perform screening in accordance with 40 CFR 60.18 (i)(3). • The operator shall tag all leaking components with date of leak detected, date of repair and date of rescreening to confirm repair. Once a leak is repaired, the leaker tag may be removed. • Component leaks detected shall be repaired as set forth below: o The leak will be repaired within 15 days. Repaired components shall be re- screened within five days of repair to determine if the leak is repaired. If the rescreening shows a leak, then the leak shall be repaired as soon as practicable, but no later than 15 days after the rescreening. Repeat the process until the rescreening shows no leak. AIRS ID: 123/9C79 Page 13 of 27 D Co do p e o Public Health and Environment 1■�_ Air Pollution Control Division o As an alternative to using the IR camera, re-screening may be performed in accordance with the Alternative Screening Procedure as specified in 40 CFR 60 Appendix A, Method 21, Section 8.3.3. o If a leak is detected but it is technically infeasible to make the repair without a process unit shutdown, repair of this equipment shall occur before the end of the next process unit shutdown. Facility records shall be maintained documenting the rationale for placing a leaking component on the Delay of Repair list, identifying the repair methods applied in each attempt to repair the leak, identifying the leaking component ID number, and listing an estimated date for repairing the component. Monitoring to verify the repair must occur within 15 days after startup of the process unit. • The following records shall be maintained and kept onsite for two years.and shall be made available to the Division upon request: o A video record must be used to document leak survey results. The video record must include a time and date stamp for each monitoring event. o A video record must be used to document leaks that are found and to confirm repairs showing the date/time of screening for each event. The video record must include a time and date stamp for each monitoring event. If the Alternative Screening Procedure per 40 CFR 60 Appendix 7, Method 21, Section 8.3.3 is used for re-screening, then records of re-screening dates, re-screening method, and re-screening results must be maintained in lieu of a video record. o List of components screened and associated dates. o List of currently leaking components. o List of repaired components along with the repair method and associated repair dates. o List of successful repairs, repair delays, and post-repair screenings and associated dates. o Records of daily instrument check including the distance and flow meter reading at which the leak was imaged. Keep a video record of the daily instrument check for each configuration of the optical gas imaging instrument used during the leak survey (for example, the daily instrument check must be conducted for each lens used). The video record must include a time and date stamp for each daily instrument check. The video record must be kept for two years. Pressurized Condensate Truck Loading (Point 0071 31. This source is located in an ozone non-attainment or attainment-maintenance area and is subject to the Reasonably Available Control Technology (RACT) requirements of Regulation Number 3, Part B, III.D.2.a. Condensate loading to truck tanks shall be conducted by loading from a pressurized tank to a pressurized tank truck. (Reference: Regulation 3, Part B, III.E) Pigging/Receiving Blowdowns (Point 0081 AIRS ID: 12319C79 Page 14 of 27 IllCo : do • p e o`Public Health and Environment o ii. Ill `� Air Pollution Control Division Vin._ 32. The permittee shall record each time a blowdown event occurs. The permittee shall record the start and finish time of each such event. 33. The permittee shall calculate the volume of gas released from each event. The permittee shall record such parameters necessary to calculate the volume of gas released such as pressure and pipeline dimensions. The calculations determining the volume from each release shall clearly show the methodology to estimate the volume of gas vented and shall be made available to the Division upon request. 34. The permittee shall calculate the VOC emissions from each event using the volume of gas estimated in accordance with Condition 33 and a representative gas analysis as required by Condition 44. Note that the most recent gas analysis shall be used to calculate emissions. VOC from each event shall be summed to obtain monthly emissions from venting. Monthly emissions shall be used in a rolling twelve month total to monitor compliance with the annual limitations. Each month a new twelve month total shall be calculated using the previous twelve months data. OPERATING & MAINTENANCE REQUIREMENTS 35. AIRS Points 003 and 004: Upon startup of these points, the applicant shall follow the operating and maintenance (O&M) plan and record keeping format approved by the Division, in 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 36. AIRS 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. 37. AIRS Point 003: 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 of the self-certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section III.E.) 38. AIRS Point 003: The owner or operator shall demonstrate compliance with Condition 24, using EPA Method 22 to measure opacity from the enclosed combustor. 39. AIRS Points 004 and 008: 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 (point 004) and point source emissions (point 008). 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. 40. AIRS Point 004: Within one hundred and eighty days (180) after commencement of operation, the operator shall complete a hard count of components at the source and establish the number of components that are operated in "heavy liquid service", "light liquid service", "water/oil service" and "gas service". The operator shall submit the AIRS ID: 12319C79 Page 15 of 27 DCo do p e o Public and ■LM_ Air PollutionHealth ControlEnvironment Division results to the Division as part of the self-certification process to ensure compliance with emissions limits. Periodic Testing Requirements 41. AIRS 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. 42. AIRS 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. 43. AIRS Point 003: 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. 44. AIRS Points 004 and 008: On an annual basis, the permittee shall complete an extended gas analysis of gas samples that are representative of VOC and HAP that may be released as fugitive emissions (Point 004) and point source emissions (Point 008). 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 45. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation No. 3, Part A, II.C) a. Annually by April 30th whenever a significant increase in emissions occurs as follows: For any criteria pollutant: For sources emitting less than 100 tons per year, a change in actual emissions of five (5)tons per year or more, above the level reported on the last APEN; or For volatile organic compounds (VOC) and nitrogen oxides sources (NO,) in ozone nonattainment areas emitting less than 100 tons 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. AIRS ID: 123/9C79 Page 16 of 27 co ' tdo yap e o` Public Health and Environment ll Air Pollution Control Division > f. AIRS 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. 46. Federal regulatory program requirements (i.e. PSD or NANSR Permitting) shall apply to this source at any such time that this source becomes major solely by virtue of a relaxation in any permit condition. Any relaxation that increases the potential to emit above the applicable Federal program threshold will require a full review of the source as though construction had not yet commenced on the source. The source shall not exceed the Federal program threshold until a permit is granted. (Regulation No. 3 Part D). 47. 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 source at any such time that this source becomes major solely by virtue of a relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of Subpart HH. (Reference: Regulation No. 8, Part E) GENERAL TERMS AND CONDITIONS: 48. This permit and any attachments must be retained and made available for inspection upon request. The permit may be reissued to a new owner by the APCD as provided in AQCC Regulation No. 3, Part B, Section II.B upon a request for transfer of ownership and the submittal of a revised APEN and the required fee. 49. 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. 50. 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. 51. 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. 52. 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 AIRS ID: 123/9C79 Page 17 of 27 Co do p e o PublicAir HealthPollution andControl EnvironmentDivision D .i■r. 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. 53. 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. 54. Violation of the terms of a permit or of the provisions of the Colorado Air Pollution Prevention and Control Act or the regulations of the AQCC may result in administrative, civil or criminal enforcement actions under Sections 25-7-115 (enforcement), -121 (injunctions), -122 (civil penalties), -122.1 (criminal penalties), C.R.S. By: . Stephanie Chaousy, PE Permit Engineer Permit History Issuance Date Description Issuance 1 This Issuance Issued to DCP Midstream, LP. Newly permitted compressor station with (2) turbines, (1) TEG dehydrator and combustor, truck loadout, pigging blowdowns and associated fugitives. Synthetic minor facility. • AIRS ID: 12319C79 Page 18 of 27 ' Cojtdo pp r e ; oPublic Health and Environment Air Pollution Control Division Notes to Permit Holder: 1) The permit holder is required to pay fees for the processing time for this permit. An invoice for these fees will be issued after the permit is issued. The permit holder shall pay the invoice within 30 days of receipt of the invoice. Failure to pay the invoice will result in revocation of this permit (Reference: Regulation No. 3, Part A, Section VI.B.) 2) The production or raw material processing limits and emission limits contained in this permit are based on the consumption rates requested in the permit application. These limits may be revised upon request of the permittee providing there is no exceedance of any specific emission control regulation or any ambient air quality standard. A revised air pollution emission notice (APEN) and application form must be submitted with a request for a permit revision. 3) This source is subject to the Common Provisions Regulation Part II, Subpart E, Affirmative Defense Provision for Excess Emissions During Malfunctions. The permittee shall notify the Division of any malfunction condition which causes a violation of any emission limit or limits stated in this permit as soon as possible, but no later than noon of the next working day, followed by written notice to the Division addressing all of the criteria set forth in Part II.E.1. of the Common Provisions Regulation. See: http://www.cdphe.state.co.us/requlations/airreqs/100102agcccommonprovisionsreq.pdf. 4) The following emissions of non-criteria reportable air pollutants are estimated based upon the process limits as indicated in this permit. This information is listed to inform the operator of the Division's analysis of the specific compounds emitted if the source(s) operate at the permitted limitations. Reportable threshold for each criteria pollutant is 250 Ib/yr: Uncontrolled Emission Are the Controlled AIRS Rate emissions Emission Point Pollutant CAS # (Ib/yr) reportable? Rate(Ib/yr) 001 and Formaldehyde 50000 449 Yes 449 002 each Benzene 71432 204,381 Yes 11,717 Toluene 108883 247,540 Yes 14,355 003 Ethylbenzene 100414 10,333 Yes 605 Xylenes 1330207 123,077 Yes 7,241 n-Hexane 110543 105,412 Yes 3,258 004 n-Hexane 110543 7,919 Yes 7,919 008 n-Hexane 110543 537 Yes 537 5) The emission levels contained in this permit are based on the following emission factors: Points 001 and 002: Emission Factors - Uncontrolled CAS Pollutant Source NOx 0.0547 lb/mmbtu Vendor Data CO 0.0547 lb/mmbtu Vendor Data VOC 0.0021 lb/MMBtu AP-42, Chapter 3.1-2a SO2 0.0034 lb/MMBtu AP-42, Chapter 3.1-2a PM25 0.0066 lb/MMBtu AP-42, Chapter 3.1-2a AIRS ID: 12319C79 Page 19 of 27 p Co do .i. e o PuR En D Airblic PollutionHeahoand Control Divisionvironment Emission Factors- Uncontrolled CAS Pollutant Source 50000 Formaldehyde 0.00071 lb/MMBtu AP-42, Chapter 3.1 Point 003: The emission levels contained in this permit are based on information provided in the application and the GRI GlyCalc 4.0 model. Controlled emissions are based on 99% recycle of the flash tank emissions, 1% downtime of the VRU during which time flash tank emissions are routed to the enclosed combustor, and 95% control of the still vent vapors. Optimal recirculation rate per MACT HH (63.764(d)(2)(i)) is based on the following information submitted with the application: F = 125MMscfd; I = 112.89 lb/MMscf; and O =6.7 lb/MMscf. Point 004: Component Gas Service Heavy Oil Light Oil ervi S Oil Service Connectors 2365 --- 2653 0 Flanges 449 --- 1123 0 Open-ended Lines --- --- — 0 Pump Seals --- --- 14 0 Valves 545 --- 1358 0 Other* 34 --- 47 0 VOC Content(wt%) 27.87% -- 100% --- n-hexane content 1 4 — (wt%) 8.0% *Other equipment type includes compressors, pressure relief valves, relief valves, diaphragms, drains, dump arms, hatches, instrument meters, polish rods and vents TOC Emission Factors(kg/hr-component): Component Gas Service Heavy Oil Light Oil Water/Oil Service Connectors 2.0E-04 7.5E-06 2.1E-04 1.1E-04 Flanges 3.9E-04 3.9E-07 1.1E-04 2.9E-06 Open-ended Lines 2.0E-03 1.4E-04 1.4E-03 2.5E-04 Pump Seals 2.4E-03 NA 1.3E-02 2.4E-05 Valves 4.5E-03 8.4E-06 2.5E-03 9.8E-05 Other 8.8E-03 3.2E-05 7.5E-03 1.4E-02 Source: EPA-453/R95-017 Compliance with emissions limits in this permit will be demonstrated by using the TOC emission factors listed in the table above with representative component counts, multiplied by the VOC content from the most recent gas analysis. Point 005: Emission Factors -Uncontrolled • CAS Pollutant Source NOX 0.068 lb/mmbtu AP-42, Table 13.5-1 CO 0.37 lb/mmbtu AP-42,Table 13.5-1 VOC 0.063 lb/MMBtu Engineering Calculation AIRS ID: 123/9C79 Page 20 of 27 Co do p e o Public Health and Environment Air Pollution Control Division Point 007: Emission Factors - Uncontrolled CAS Pollutant lb/BBL loaded Source VOC 0.0054 Engineering Calculation Point 008: CAS Pollutant lb/MSCF Source VOC 15.75 Engineering Calculation 110543 n-hexane 0.79 Engineering Calculation 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) The following equipment is currently exempt from construction permitting requirements and/or APEN reporting requirements based on information provided by the operator for the Division's analysis: AIRS ID Facility ID Description Notes NA TEG TEG Dehy unit reboiler, This unit is exempt from APEN reporting Reboiler rated at 3.0 MMBtu/hr requirements because the design rate is less than 5 MMBtu/hr (Regulation No. 3, Part A, II.D.1.k), and is therefore also exempt from construction permitting requirements (Regulation no. 3, Part B, II.D.1.a). Criteria pollutant emission levels for this unit are based on factors from AP-42, Chapter 1.4, Small Boilers < 100 MMBtu/hr(7/1998). 8) This facility is classified as follows: Applicable Status Requirement Operating Permit Synthetic Minor Source VOC, benzene, toluene, xylenes, n-hexane, total HAPs NANSR Synthetic Minor Source VOC MACT HH Area Source Requirements: Applicable NSPS OOOO Area Source Requirements: Applicable 9) Full text of the Title 40, Protection of Environment Electronic Code of Federal Regulations can be found at the website listed below: AIRS ID: 123/9C79 Page 21 of 27 D Co do p e o Pult and Environment Airblic PollutionHeah Control Division http://ecfr.gpoaccess.gov/ Part 60: Standards of Performance for New Stationary Sources NSPS 60.1-End Subpart A—Subpart KKKK NSPS Part 60,Appendixes Appendix A—Appendix I Part 63: National Emission Standards for Hazardous Air Pollutants for Source Categories MACT 63.1-63.599 Subpart A—Subpart Z MACT 63.600-63.1199 Subpart AA—Subpart DDD MACT 63.1200-63.1439 Subpart EEE—Subpart PPP MACT 63.1440-63.6175 Subpart QQQ—Subpart YYYY MACT 63.6580-63.8830 Subpart ZZZZ—Subpart MMMMM MACT 63.8980-End Subpart NNNNN—Subpart XXXXXX 10) An Oil and Gas Industry Construction Permit Self-Certification Form is included with this permit packet. Please use this form to complete the self-certification requirements as specified in the permit conditions. Further guidance on self-certification can be found on our website at: http://www.cdphe.state.co.us/ap/oilgaspermitting.html ' AIRS ID: 123/9C79 Page 22 of 27 � x kt co do •$p t e o Public Health and Environment Air Pollution Control Division ATTACHMENT A: ALTERNATIVE OPERATING SCENARIOS TURBINES WITHOUT CONTINUOUS EMISSIONS MONITORING August 16, 2011 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: 12319C79 Page 2 of 27 Co do p e o Pulth Environment lr Airblic PollutionHeaand Control Division 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: 12319C79 Page 3 of 27 Co kdo p e a Public Health and Environment Air Pollution Control Division 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 Reg 3, Part D, II.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 (Ib/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 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. AIRS ID: 123/9C79 Page 4 of 27 D Co do p e o Publicr Health andControl Environment Ai Pollution Division ' 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 w 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 bumers 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). 2.4 Additional Sources AIRS ID: 123/9C79 Page 5 of 27 s Co>1 do ray p , e s o Public Health and Environment Air Pollution Control Division 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: 123/9C79 Page 6 of 27 Construction Permit Application Preliminary Analysis Summary Section 1 —Applicant Information Company Name: DCP Midstream, LP Permit Number: 14WE0446 Source Location: Rocky Turbine Compressor Station Section 26, T6N, R63W, Weld County (non-attainment0 Point 001: Turbine Point 002: Turbine Point 003: TEG Dehydrator Equipment Description: Point 004: Fugitive emissions Point 005: Dehydrator still vent control device Point 007: Truck loadout Point 008: Pigging/Receiving blowdowns AIRS ID: 123-9C79 Date: March 24, 2014 Review Engineer: Stephanie Chaousy, PE Control Engineer Chris Laplante 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? X Yes No If you answered "no" to any of the above, when did you mail an See Section 14 Information Request letter to the source? September 11, 2013. Division On what date was this application complete? received modifications to this application March 12, 2014. Section 4—Source Description AIRS Point Equipment Description One (1) natural gas fired combustion turbine (Solar Model Taurus 70 serial number: TBD), 001 equipped with low NOx burners, site rated at 8,534 horsepower at 11,575 RPM. The turbine is design rated for a heat input of 72.21 MMBtu/hr at 60°F ambient temperature. Page 1 One(1) natural gas fired combustion turbine(Solar Model Taurus 70, serial number:TBD), 002 equipped with low NOx burners, site rated at 8,534 horsepower at 11,575 RPM.The turbine is design rated for a heat input of 72.21 MMBtu/hr at 60°F ambient temperature. One(1)Triethylene glycol (TEG) natural gas dehydration unit(make, model, serial number: not submitted)with a design capacity of 125 MMscf per day. This emissions unit is equipped with either one (1) electric pump or one (1)gas injection pump (make, model: not submitted) plus one backup pump with an operational capacity of 40 gallons per 003 minute each. This unit is equipped with a flash tank, reboiler and still vent. Emissions from the still vent are routed to an enclosed combustor. Emissions from the flash tank are routed to a vapor recovery unit(VRU)which returns vapors back to the inlet of the compressor station. The VRU is estimated to be down one percent of the time. When the VRU is down, emissions from the flash tank are routed to an enclosed combustor. 004 Equipment leaks(fugitive VOCs)from a natural gas compression facility. Enclosed combustor(manufacturer, model, SN: not submitted) controlling the TEG 005 dehydrator non-condensable still vent emissions(Point 003)at a minimum control efficiency of 95%. - 007 Pressurized condensate truck loading. 008 Associated blowdowns with pig launching and receiving activities. Is this a portable source? Yes X No 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 PM10 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) Section 5—Emission Estimate Information AIRS Point Emission Factor Source NOx and CO: Vendor data 001 VOC,SO2, PM: AP-42,Tables 3.1a HAPS: AP-42,Table 3.13 NOx and CO: Vendor data 002 VOC, SO2, PM: AP-42,Tables 3.1a HAPS: AP-42, Table 3.1-3 003 GRI Gly-Calc v4.0(Refer to Section 14 for calculations) 004 EPA-453/R-95-017, Table 2-4 005 AP-42, Table 13.5-1 007 AP-42, Chapter 5.2, Equation 1 008 Engineering Calculation. See Section 14 for calculations. 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 Page 2 001 618.3 MMSCF per year 002 618.3 MMSCF per year 003 45,625 MMSCF per year, 40 gallons per minute glycol circulation rate Equipment Type Gas Light Liquid Connectors 2365 2653 Flanges 449 1123 004 Open-Ended Lines --- -- Pump Seals --- 14 Valves 545 1358 Other 34 47 005 66.7 MMscf per year 007 476,200 bbl per year 008 677 MSCF per year Basis for Actual Emissions Reported During this APEN Filing (Reported to Inventory) AIRS Point Process Consumption/Throughput/Production Data Year Did not report actual —new facility Basis for Permitted Emissions(Permit Limits) AIRS Point Process Consumption/Throughput/Production 001 618.3 MMSCF per year 002 618.3 MMSCF per year 003 45,625 MMSCF per year, 40 gallons per minute glycol circulation rate Equipment Type Gas Light Liquid Connectors 2365 2653 Flanges 449 1123 004 Open-Ended Lines --- -- Pump Seals --- 14 Valves 545 1358 Other 34 _ 47 005 66.7 MMscf per year 007 476,200 bbl per year 008 677 MSCF per year Does this facility use control devices? X Yes No %Reduction AIRS Point Process Control Device Description Granted 003 of Enclosed combustor 95 Section 6—Emission Summary (tons per year) Point NO, VOC CO Single HAP Total HAP 0.2 001 17.3 0.7 17.3 0.3 (formaldehyde)0.2 002 17.3 0.7 17.3 0.3 (formaldehyde) PTE: 003 --- 847.9 --- 112.5 (toluene) 314.0 004 --- 53.7 --- 4.0 (n-hexane) 4.0 005 2.3 2.1 12.6 Page 3 007 - 1.3 - - - 008 - 5.3 - 0.3(n-hexane) 0.3 0.2 001 17.3 0.7 17.3 (formaldehyde)0.2 0.3 002 17.3 0.7 17.3 (formaldehyde) 0.3 003 — 847.9 — 112.5 (toluene) 314.0 Uncontrolled point source emission rate: 004 - 53.7 - 4.0(n-hexane) 4.0 005 2.3 2.1 12.6 --- --- 007 - 1.3 - - --- 008 - 5.3 - 0.3 (n-hexane) 0.3 0.2 001 17.3 0.7 17.3 (formaldehyde)0.2 0.3 002 17.3 0.7 17.3 (formaldehyde) 0.3 003 -- 30.4 — 7.2 (toluene) 18.6 Controlled point source emission rate: 004 -- 53.7^ -- 4.0 (n-hexane) 4.0 005 2.3 2.1 12.6 - -- 007 - 1.3 - - - 008 - 5.3 - 0.3 (n-hexane) 0.3 Total APEN Reported 36.9 94.2 47.2 4.0(toluene) 21.1 emissions: ^Not used when determining facility status Section 7—Non-Criteria/Hazardous Air Pollutants I UncontrolledMe the emissions Controlled Actual Emission Pollutant CAS# Emission Rate Tapley Rate(lb/yr) I (lb/yr) Each criteria pollutant reportable threshold is 250 lb/yr Points 001 and 002 each Benzene 71432 8 No 8 Toluene 108883 83 No 83 Ethylbenzene 100414 20 No 20 . Xylenes 1330207 41 , No 41 Formaldehyde 50000 449 Yes 449 Acetaldehyde 75070 26 No 26 Acrolein 107028 4 No 4 Point 003—Operator requested a 10%buffer. Actual emissions are in () Benzene 71432 204'381 Yes 11, 717 (10,651) (185,801) Toluene 108883 247'540 Yes 14,355(13,050) (225,036) 10 605 Ethylbenzene 100414 (9,394)94 Yes (550) 7241 Xylenes 1330207 (123'077111,889) Yes (6583) Page 4 3258 n-Hexane 110543 105,412 (95,829) Yes (2962) Point 004 n-Hexane 110543 7,919 Yes s 7,919 Point 008 n-Hexane 110543 537 Yes 537 Note: Regulation 3, Part A, Section lI.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 Process Pollutant Regulatory Basis Test Method 001 01 NOx,CO2 Regulation No. 3, Part B., Section III.G.3, Stack Test 40 CFR Part 60 Subpart KKKK§60.4335 002 01 NOx,CO2 Regulation No. 3, Part B., Section III.G.3, Stack Test 40 CFR Part 60 Subpart KKKK§60.4335 003 01 VOC, Regulation No. 3, Part B., Section III.G.3 Stack Test HAPS 004 01 VOC, State only requirement Extended gas HAPS analysis 004 01 VOC, State only requirement Component hard HAPS count Section 9—Source Classification Is this a new previously un-permitted source? X Yes No What is this facility classification? True X Synthetic Major Minor Minor Classification relates to what programs? X Title V PSD X NA NSR X MACT Is this a modification to an existing permit? Yes X No 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? VOC 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)? X Yes No For Reg. 3, Part B, III.C.1.d(synthetic minor emission limits)? X Yes No Section 11 —Modeling Is modeling required to demonstrate compliance with National Ambient Yes X No Air Quality Standards(NAAQS)? If"yes", for which pollutants?Why? AIRS Point Section 12—Regulatory RevieSV Regulation 1 - Particulate, Smoke, Carbon Monoxide and Sulfur Dioxide Page 5 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 001-005, is in excess of 20% opacity. This standard is based on 24 consecutive opacity readings 007, 008 taken at 15-second intervals for six minutes. The approved reference test method for visible emissions measurement is EPA Method 9 (40 CFR, Part 60,Appendix A(July, 1992)) in all subsections of Section II. A and B of this regulation. 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: (i) For fuel burning equipment with designed heat inputs greater than 1x106 BTU per hour, but less than or equal to 500x106 BTU per hour, the following equation will be 001 and used to determine the allowable particulate emission limitation. 002 PE=0.5(FI)-ose 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 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. Rice uta;ion 2—Odor Section I.A- No person, wherever located, shall cause or allow the emission of odorous air 001-005, contaminants from any single source such as to result in detectable odors which are 007, 008 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 001-005, Part A-APEN Requirements 007, 008 Applicant is required to file an APEN since emissions exceed 1 ton per year VOC in an nonattainment area for ozone. 001-005, Part B—Construction Permit Exemptions 007, 008 Applicant is required to obtain a permit since uncontrolled VOC emissions from this facility are greater than the 2.0 TPY threshold(Reg. 3, Part B, Section II.D.2.a) 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/is not located in the 8-hour ozone nonattainment area, but not the 1-hour ozone area. 007 The date of interest for determining whether the source is new or modified is therefore November 20, 2007 (the date of the 8-hour ozone NA area designation). Since the tank battery from which loadout is occurring will be in service since after the date above, this source is considered"new or modified." I emailed the operator on 3/27/14 regarding RACT for the loadout. I receive their response on 3/27/14: RACT for condensate loading is loading from a pressurized tank to a pressurized tank truck. 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 001 and reconstruction after February 18, 2005. 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 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)-oss 001 and Where: PE is the allowable particulate emission in pounds per million Btu heat 002 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—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: Sources with a heat input of less than 250 million Btu per hour: 0.8 lbs. SO2/million Btu. 003, 005, None 008 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 004 reconstruction after August 23, 2011. Is this source at a"natural gas processing plant?" No Is this source subject to NSPS OOOO? No This source is not 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 not subject to its provisions. 007 No applicable subpart. This facility is not a bulk gasoline terminal. Regulation 7—Volatile Organic Compounds 001, 002, None 005, 008 Is this source subject to the control requirements of MACT HH? (Regulation 8-Hazardous Air Pollutants review). No 003 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 This source is subject to review for the Regulation 7 control requirements. Section XII.H: Is this source located in the non-attainment area? Yes 003 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.D (State only enforceable). 003 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 XII.G - If facility is a natural gas processing plant located in non-attainment area, 004 then subject to Section XII.G. This source is not a natural gas processing plant in non-attainment. Therefore, it is not subject to Section XII.G. 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 007 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. Page 7 Regulation 8—Hazardous Air Pollutants 001, 002, None 004, 005, 007, 008 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)?Yes 2.If facility is defined as a production facility, then is it a major source of HAPS when 003 summing up dehydrator and flash tank emissions? 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. Section 13—Aerometric Information Retrieval System Coding Information Point Process Process Throughput Emission Pollutant/ Fugitive Emission Control Description limit Factor CAS# (YIN) Factor Source (%) 0.21 g/hp-hr N0x No Vendor Data 0 0.21 g/hp-hr CO No Vendor Data 0 0.0021 V0C No AP-42,Table 0 001 Combustion 618.3 Ib/MMBtu 3.1-2a and 01 Turbine MMscf/yr 0.0034 SO2 No AP-42, Table 0 002 Ib/MMbtu 3.1-2a each 0.0066 pM PM,dPzs M No AP-42, Table 0 lb/MMBtu 3.1-2a 0.00071 Formaldehyde/ No 0 AP-42,Table • lb/MMBtu 50000 3.1-3 SCC 20200201: Turbine(natural gas) 37.1667VOC No GlyCalc 4.0 96.41 Ibs/mmscF mms 4.0723 Benzene/ No GlyCalc 4.0 93.69 Ibs/mmscf 71432 4.9323 Toluene/ 45,625 No GlyCalc 4.O 93.62 01 Glycol MMSCF a Ibs/mmscf 108883 003 Dehydrator year p 0.2059 Ethylbenzene No GlyCalc 4.0 93.56 bs mmscf 100414 2.4524 Xylenes/ No GlyCalc 4.0 93.53 Ibs/mmscf 1330207 2.1004 n-Hexane/ No GlyCalc 4.0 96.60 Ibs/mmscf 110543 SCC 31000301 —Glycol dehydrators: reboiler still vent: Triethylene glycol 004 01 Fugitive V0C Leak V0C Yes EPA-453/R-95-017, 59.50 Emissions Table 2-4 SCC 31000220: All Equip. Leak Fugitives (Valves,flanges, connections,seals,drains) 0.068 AP-42, Table lb/MMbtu NOx No 13 5-1 NA 01 Flare 66.7 0.063 VOC No Engineering NA 005 MMscf/yr lb/MMbtu calculation 0.37 CO No AP-42,Table NA lb/MMbtu 13.5-1 SCC 31000205: Flares 01 Truck 476,200 0.1281 VOC No Engineering NA 007 loadout bbl/yr lb/1000 gal calculation SCC 40600132: Crude Oil: Submerged Loading (Normal Service) i Page 8 15.7459 VOC No Engineering NA 01 Slowdowns Ib/mscf Calculation 008 0.7922 n-hexane No Engineering NA Ib/mscf Calculation SCC 306004002—blowdown system wio control Section 14—Miscellaneous Application Notes AIRS Point 001 Turbine A permit will be issued because the uncontrolled emissions are greater than permitting threshold for a non-attainment area. • PM10, PM25, VOC and HAPS were calculated from AP-42, Table 3.1-2a: VOC= I 0.0021 lb 1023 Btu 622.81 MMscf I T =0.669 TPY MMBtu scf yr 2000 lb PM = 0.0066 lb 1023 Btu 622.81 MMscf I T =2.103 TPY MMBtu scf yr 2000 lb Particulate matter emission calculations include both condensable and filterable particulate. All particulate is assumed to be 2.5 microns in diameter or less. AP-42,Table 3.1-3 Acetaldehyde= 0.00004 lb 11023 Btu 1622.81 MMscf =25.5 lb/yr MMBtu scf yr Acrolein (0.0000064 lb/MMBtu) 4 4.1 lb/yr Benzene(0.000015 lb/MMBtu) 4 7.7 lb/yr Ethylbenzene(0.000032 lb/MMBtu) 4 20.4 lb/yr Formaldehyde(0.00071 lb/MMBtu) 4 452 lb/yr Toluene(0.00013 lb/MMBtu) 4 82.8 lb/yr Xylenes (0.000064 lb/MMBtu)4 40.8 lb/yr Manufacturer data emission factors were provided for NOx and CO in lb/hr. I emailed DCP for the manufacturer specification sheet on 3/24/14. Emissions were calculated in lb/MMBtu so that they are consistent with the rest of the source's emission calculations. NOx= 116.5 T 2000 lb mmscf I year =0.0518 year 1 T 1023 mmBtu 623 MMscf lb/MMBtu CO= 19.4 T 2000 lb mmscf year =0.0609 year 1 T 1023 mmBtu 623 MMscf lb/MMBtu Page 9 AIRS Point 002 Turbine A permit will be issued because the uncontrolled emissions are greater than permitting threshold for a non-attainment area. PMK°, PM2.5,VOC and HAPS were calculated from AP-42,Table 3.1-2a: VOC= 0.0021 lb 1023 Btu I 622.81 MMscf I T =0.669 TPY MMBtu scf yr 12000lb PM= 0.0066 lb 1102 1023 Btu 162 622.81 MMscf I T lb =2.103 TPY MMBtu yrParticulate matter emission calculations include both condensable and filterable particulate. All particulate is assumed to be 2.5 microns in diameter or less. AP-42,Table 3.1-3 Acetaldehyde= 10.06004 lb 110023 Btu f , 622.81 MMscf =25.5 lb/yr s yr Acrolein(0.0000064 lb/MMBtu)4 4.1 lb/yr Benzene(0.000015 lb/MMBtu) 4 7.7 lb/yr Ethylbenzene(0.000032 lb/MMBtu) 4 20.4 lb/yr Formaldehyde(0.00071 lb/MMBtu)4 452 lb/yr Toluene(0.00013 lb/MMBtu) 4 82.8 lb/yr Xylenes(0.000064 lb/MMBtu)4 40.8 lb/yr Manufacturer data emission factors were provided for NOx and CO in lb/hr. I emailed DCP for the manufacturer specification sheet on 3/24/14. Emissions were calculated in lb/MMBtu so that they are consistent with the rest of the source's emission calculations. NOx= I 16.5 T 2000 lb mmscf year 0.0518 year 11 T 1023 mmBtu 1623 MMscf lb/MMBtu Ib/MMBtu CO = 19.4 T 2000 lb mmscf year =0.0609 year 1 T 1023 mmBtu 623 MMscf Ib/MMBtu Page 10 AIRS Point 003 Glycol Dehydrator In order to determine emissions,the operator used GRI GlyCALC 4.0. The source assumed the inlet gas temperature of 125"F and pressure of 1050 psig. The permitted glycol recirculation rate is 40 gallons per minute. The GlyCalc model was based off of an average of 6 gas analyses from similar facilities in approximately the area (county). An extended gas analysis will be required because the source is a new source at a new facility and an actual sample was not available for emission calculations. A test performed at the source once constructed will provide an accurate emissions sampling. Revised with March 2014 modification application using the provided GlyCalc model Component Glycalc Glycalc Total Total 1% 1% 1% Total With Uncontrol Uncontrol Uncontrol uncontrol downtime downtime downtime controlled 10% Still Vent Flash tank emissions emission ECD(99% ECD(1%of flash gas emissions safety (TPY) (TRY) (TPY) (Ib/yr) control uncontrol emissions (TPY) factor regen em.) regen em) (VRU is (WY) (TPY) down) (TRY) VOC 461.6278 386.2596 847.8874 -- 22.8506 4.6163 0.19313 27.6600 30.43 Benzene 89.4779 3.4224 92.9003 185800.6 4.4292 0.8948 0.001711 5.3257 5.86 Toluene 109.6412 2.8766 112.5178 225035.6 5.4273 1.0964 0.001438 6.5251 7.18 Ethylbenzene 4.6224 0.0744 4.6968 9393.6 0.2288 0.0462 0.000037 0.2750 0.303 Xylenes 55.3130 0.6313 55.9443 111888.6 2.7380 0.5531 0.000316 3.2914 3.62 n-hexane 24.6968 23.2179 47.9147 95829.4 1.2225 0.2470 0.011609 1.4811 1.629 Gly-Galt-Uncontrolled Emission factors VOC=((847.8874)*2000)/(125*365) =37.1677 lb/mmscf Benzene=((92.9003)"2000)/(125*365) =4.0723 lb/mmscf Toluene= ((112.5178)"2000)/(125"365) =4.9323 lb/mmscf Ethylbenzene=((4.6968)*2000)/(125*365) =0.2059lb/mmscf Xylenes= ((55.9443)*2000)/(125*365)=2.4524 lb/mmscf N-hexane=((47.9147)*2000)/(125*365) =2.1004 lb/mmscf MACT HH includes requirements for both major and area sources of HAPs. The definition of major source for MACT HH (63.761) states: (3) For facilities that are production field facilities, only HAP emissions from glycol dehydration units and storage vessels with the potential for flash emissions shall be aggregated for a major source determination. For facilities that are not production field facilities, HAP emissions from all HAP emission units shall be aggregated for a major source determination. The following definitions from 63.761 are also needed to determine major source applicability: Production field facilities means those facilities located prior to the point of custody transfer Custody transfer means the transfer of hydrocarbon liquids or natural gas: after processing and/or treatment in the producing operations, or from storage vessels or automatic transfer facilities or other such equipment, induding product loading racks,to pipelines or any other forms of transportation. For the purposes of this subpart, the point at which such liquids or natural gas enters a natural gas processing plant is a point of custody transfer. Natural gas processing plant(gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, or the fractionation of mixed NGL to natural gas products, or a combination of both. Based on the definitions above, this source qualifies as a production field facility. Does this dehydrator have a reboiler?Yes If Yes, what is the reboiler rated? 3.0 mmbtu/hr(originally APEN had a reboiler of 7.15 mmbtu/hr but was modified with a new application received 3/14/14). The source is less than 5 mmbtu/hr, therefore, it meets the APEN exemption(it is also permit exempt). It is Point 006 at the facility. March 25, 2014: I received an email from D. Stephens (DCP) saying that a modification to the application was submitted to the division on 3/12/14(she attached it to the email). They requested to add 1%downtime for the vapor recovery unit(VRU) for the dehydrator flash tank to account for maintenance activities. During downtime, the emissions from the flash tank will be routed to the enclosed combustor. Add 1%of downtime for the enclosed combustor to account for maintenance activities. I modified the table above to indude an additional 1%for downtime. Page 11 I — AIRS Point 004 Fugitive emissions A permit will be issued because the uncontrolled VOC emissions are greater than 2 TPY(permit threshold). March 25, 2014: I received an email from D. Stephens(DCP) saying that a modification to the application was submitted to the division on 3/12/14(she attached it to the email). Source is subject to RACT requirements. Operator provided some RACT discussion, but I followed a similar permit issued to DCP and used that RACT condition. They requested to revise the fugitive emissions based on hard counts and an inlet analysis for a newly constructed facility. I received an email on 3/27/14 requesting the implementation of an LDAR program.With this also included certain component controls. I redlined the APEN and revised the PA and permit. However, on 4/23/14, DCP requested to go back to the original APEN with no control and no LDAR program. I made the changes back to the original APEN and modified the PA, permit and history file. AIRS Point 005 Dehydrator still vent control device A permit will be issued because the uncontrolled CO emissions are greater than 2 TPY and the total facility uncontrolled CO emissions are greater than 5 TPY(permit threshold). I emailed the operator on 3/26/14: For the dehydrator combustor,the calculation sheet and APEN are showing that the VOC emission factor came from AP-42,table 13.5-1 of 0.063 lb/mmbtu. However, the total hydrocarbons in Table 13.5-1 shows and emission factor of 0.14 lb/mmbtu. How did you come up with the 0.063 lb/mmbtu? I am sure I have asked this before, but please refresh my memory if you can. She responded on 3/26/14: Table 13.5-1 has a value of 014 Ib/MMBtu for hydrocarbons. Then Table 13.5-2 has a value of 55%methane of the hydrocarbons. To estimate the emission factor for VOC, we took the 014 lb/MM8tu x 045(the portion that's VOC) and obtained 0063lb/MMBtu. Although Table 13.5-2 lists the ethane portion too, we conservatively did not include that in the non-VOC portion to account for the fact that Table 13.5-2 is in vol%, while Table 13.5-1 is on a mass basis. NOx= 0.068 lb 1102 3 btu 166.scf f mmscf 1 T lb =2.31 TPY VOC=2.15 TPY COl = 12.62 TPY AIRS Point 007 Truck loadout The liquids are stored in a pressurized bullet tank and hauled off site via a pressurized truck loading rack. P: Pressure in hose at time of 102.9 psia disconnect(storage tank pressure(psia)) V: Volume of hoses(ft') 0.0218 ft' n: number of Ibmoles in hoses Solve R: Universal gas constant 10.73 ft'`psi/ibmol`degR T: average loadout temp(R) 519.67 degR Specific gravity condensate 0.65 Density of water(lb/gal) 8.33 lb/gal Molecular weight of vapor 32.4 Ib/Ib`mole Loads per month 238.10 Conversion 1 ft'=7.48 gallons Emissions were calculated looking at vapor and liquid then added together. n=(PV)/(RT)=(102.9`0.0218)/(10.73`519.67) =0.0004269 Ibmole Vapor density=n(Ibmol/ft3)`MW=(0.0004269/0.0218)`32.4=0.6345 lb/ft3 Liquid density=Specific gravity`density of water`(ft3/gal)=0.65`8.33`7.48=40.50 lb/ft3 Product Density(lb/ft') Hose volume Loads per Emissions Emissions Emissions (ft3/load) month (lb/month) (ton/month) (TPY) Vapor 0.6345 0.0218 238.10 3.29 0.00165 0.0198 Liquid 40.50 0.0218 238.10 210.27 0.11 1.261 Total emissions= 1.2808 TPY BBL per year= 238.10 load 7000 gal 1 BBL 12 months =476,200 month load 42 gal 1 year BBUyr VOC E.F. =(1.2808'2000)/476200=a0054lb/bbl *1000/42=0.1281 lb/1000 gal Page 12 AIRS Point 008 Pig launching A permit will be issued because the uncontrolled VOC emissions are greater than 5 TPY(permit threshold). Operator requested a new point source during the application review process. The Division received an APEN and calculations on 3/14/2014. I am not going to request monthly emissions because blowdowns will occur whenever the equipment needs the maintenance. There are 91 MSCF/yr for the 16" receiver, 218 MSCF/yr for each of the 12" launcher, 6 MSCF/yr for the 8"fule receiver and 143 MMSCF/yr for the 20" receiver totaling 677 MSCF/year. Emission factors are calculated as follows: VOC=5.33*2000/677= 15.7459 lb/mscf-blowdown event n-hexane=536.33/677=0.7922 lb/mscf-blowdown event Insignificant Activities The source provided emission estimates for several insignificant activities at the facility. Since APENs were not submitted for these insignificant activities, emissions and regulatory applicability were not evaluated for these activities/points. Emissions listed in the application were induded in the history file to understand total facility emissions but otherwise not reviewed as part of this permit action. The facility's insignificant activities indude one 3.0 MMBtu/hr dehy reboiler, one 60,000 gallon pressurized condensate storage tank, 400 gallon waste oil tank, compressor blowdowns, two 420 bbl wastewater tanks, one 1000 gallon methanol tank, 400 gallon lube oil tank, 2000 gallon glycol tank and 160 bbl drain tank. Facility Wide Comments DCP is proposing to construct and operate a natural gas compression facility with a capacity of 125 MMscfd. This stationary source will be located in Weld County which is currently considered a non-attainment area for ozone. The facility will install emissions controls in order to be considered a synthetic minor source for Non-attainment New Source Review(NANSR) requirements that would have otherwise been triggered due to emissions of nitrogen oxides (NOx) and volatile organic compounds(VOC)in excess of 100 tons per year. The facility will also be considered a minor source for Prevention of Significant Deterioration(PSD) requirements that would have otherwise been triggered due to emissions of carbon monoxide(CO) in excess of 250 tons per year. The source will be a synthetic minor source of criteria pollutants and HAP emissions for Title V Operating Permit program. Facility Wide Comments continued Page 13 • DCP is a"midstream"natural gas company and thus does not own, operate, or control any oil or natural gas leases, production wells or production lease sites(E&P sites). Additionally, DCP stated on 3/27/13 that no DCP compressor stations are currently located, or will be located,within a quarter mile of the Rocky compressor station. DCP also stated that no DCP compressor stations or gas plants that are greater than a quarter mile from the Rocky compressor station will be wholly dependent with Rocky.The closest DCP.facility to the proposed Rocky compressor station is the Wells Ranch compressor station which is approximately 1.2 miles away. There is no dedicated relationship between the proposed Rocky compressor station and the Wells Ranch compressor station;the two facilities function independently. The Prevention of Significant Deterioration (PSD) rule, under 40 CFR §51.166(b)(5) and (6), specifies a single stationary source includes all "activities which belong to the same industrial grouping, are located on one or more contiguous or adjacent properties, and are under the control of the same person(or persons under common control)." (hereinafter referred to as the "three-part test"). The Division applied the three-part test to accurately define the Rocky Compressor Station stationary source pollutant-emitting activities for this permit action. The Division acknowledges DCP Midstream owns and operates multiple compressor stations and gas plants within the Weld County region of Colorado. These facilities, along with the Rocky compressor station, operate under common ownership and are classified under the same major SIC code. Therefore, two out of three parts of the stationary source determination test are met for these facilities. Therefore, the remainder of the Division's response will focus on this part of the source determination analysis. The Division determined there are no other pollutant-emitting activities under common ownership or control and with the same major SIC code that are contiguous (i.e., sharing a common border) with the Rocky compressor station. Therefore, we requested information from DCP to ascertain if there are any DCP facilities that would be considered adjacent to the Rocky compressor station. The term adjacent implies the facilities/pollutant-emitting activities are not widely separated, though they may not actually touch. The determination whether two sources are considered to be contiguous or adjacent is made on a case-by-case basis. This is stated in the preamble to the August 7, 1980 PSD regulations and reiterated in a number of EPA guidance documents. When the Division evaluates adjacency,there is no fixed distance that defines two sources as being adjacent and the reviewing agency must make the determination on a case-by-case basis. Recent EPA decisions have also considered the operational dependence of pollutant-emitting activities as a factor in making this determination, though it is important to note that the consideration of operational dependence is based on interpretation and not a fixed part of the rule or the definition of a term under the rule'. Furthermore, there have been significant conflicting determinations made by the individual regional offices of the EPA. In the case of Summit Petroleum Corp. vs. United States EPA, et aL, as cited in RMELC's comments, an EPA Region 5 decision relying heavily on operational dependence to establish adjacency was rejected by the 6th Circuit Court of Appeals. In light of the inconsistencies, the Division must base its decision on the text of the PSD rule,the Division's own interpretations of regulations based on decades of experience with source determinations, and the direct guidance of our own EPA Region 8. To that end, the Division considered both proximity and operational dependency when establishing the pollutant-emitting activities that comprise the 70 Ranch compressor station for this permit action. As summarized in the Division's preliminary analysis, the Division asked DCP several questions to evaluate if there were other DCP pollutant-emitting activities that should be considered adjacent to the Rocky'compressor station. Based on the response provided by DCP, the Division determined there are no other DCP compressor stations or gas plants that are either sufficiently proximate or substantially dependant on the Rocky compressor station to be considered adjacent. For example, the closest DCP facility to the proposed Rocky compressor station is the Wells Ranch Compressor Station which is approximately 1.2 miles away. There is no dedicated relationship between the proposed Rocky compressor station and the Eaton gas plant; the two facilities function independently. During our permitting process, the Division relies on information supplied by the applicant. Therefore, based on the common sense notion of a plant and the three-part analysis as discussed above, the Division determined our initial source determination for the Rocky Compressor Station is appropriate. Accordingly, the stationary source determination of the Rocky Compressor Station will remain, as reflected in the draft construction permit. The term adjacency, as written in the 1980 PSD rule and associated preamble, has no relation to interdependence or operational relationship. The EPA has introduced this factor as an aide in making these case-by-case adjacency determinations. The Division considers EPA's guidance and exemplar decisions when conducting singlesource determinations. As such,the Division has considered interdependence as a factor in determining adjacency, as warranted, on a case-by-case basis. 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