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Home My WebLink About20141356.tiff STATE OF COLORADO John W.Hickenlooper,Governor ��q Karin McGowan ��9-,cozop Interim Executive Director Nc fS�Z, Dedicated to protecting and improving the health and environment of the people of Colorado ,` ,b 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 http://www.cdphe.state.co.us and Environment Weld County - Clerk to the Board 1 150 O Street PO Box 758 Greeley,CO 80632 April 25, 2014 Dear Sir or Madam: On May 1, 2014,the Air Pollution Control Division will publish a public notice for DCP Midstream, LP—70 Ranch Compressor Station, in the The Greek:). 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, /f •4.A-& ( _�• -a�' !"3/ Clara Gonzales Public Notice Coordinator Stationary Sources Program Air Pollution Control Division Enclosure �xblic� " / CC . ?L Lim) H-LLre 6/01Tu3( tckV/ e 2014-1356 15O STATE OF COLORADO John W.Hickenlooper,Governor Karin McGowan v.cozo Interim Executive Director e Dedicated to protecting and improving the health and environment of the people of Colorado 4300 Cherry Creek Dr.S. Laboratory Services Division \�E96 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 http://www.cdphe.state.co.us and Environment Website Title: DCP Midstream, LP—70 Ranch Compressor Station— Weld County Released To: The Greeley Tribune On: April 25, 2014 Published: May 1, 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: 70 Ranch Compressor Station Oil and gas compressor station SWNW Section 20, T5N, R63W Weld County The proposed project or activity is as follows: Oil and gas compressor station consisting of five(5)reciprocating internal combustion engines (1 as backup), one(1)TEG glycol dehydrator and associated control device and associated fugitive emissions. 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 IILC.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 13WE2169 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-BI Denver,Colorado 80246-1530 cdphe.commentsapcd@state.co.us D I x F TSTATE OF COLORADO 0c•CO4,O40 COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT 1_= -- 1`, AIR POLLUTION CONTROL DIVISION *� .* TELEPHONE: (303) 692-3150 *1876• CONSTRUCTION PERMIT PERMIT NO: 13WE2169 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 70 Ranch Compressor Station, located in the SWNW of Section 20, Township 5N, 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)Waukesha, Model L7044GSI, Serial Number TBD, natural gas-fired, turbo-charged, 4SRB reciprocating internal C-311 001 combustion engine, site rated at 1680 horsepower at 1200 RPM. This engine shall be equipped with non-selective catalytic reduction (NSCR) system and air-fuel ratio control. I This emission unit is used for natural gas compression. One (1)Waukesha, Model L7044GSI, Serial Number TBD, natural gas-fired, turbo-charged, 4SRB reciprocating internal C-312 002 combustion engine, site rated at 1680 horsepower at 1200 I RPM. This engine shall be equipped with non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. One (1)Waukesha, Model L7044GSI, Serial Number TBD, natural gas-fired, turbo-charged, 4SRB reciprocating internal C-313 003 combustion engine, site rated at 1680 horsepower at 1200 RPM. This engine shall be equipped with non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. AIRS ID: 123/9667 Page 1 of 28 NGEngine Version 2009-1 DCo do p e o Public PollutionHealthand Control DivisionEnvironment Facility AIRS Description Equipment ID Point One(1)Waukesha, Model L7044GSI, Serial Number TBD, natural gas-fired, turbo-charged, 4SRB reciprocating internal C-314 004 combustion engine, site rated at 1680 horsepower at 1200 RPM. This engine shall be equipped with non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. One(1)Waukesha, Model L7044GSI, Serial Number TBD, natural gas-fired, turbo-charged, 4SRB reciprocating internal C-315 005 combustion engine, site rated at 1680 horsepower at 1200 RPM. This engine shall be equipped with non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. One (1) Triethylene glycol (TEG) natural gas dehydration unit (make, model, serial number: not submitted)with a design capacity of 60 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 a design capacity of 24 gallons per D-1 006 minute each. This unit is equipped with a flash tank, reboiler and still vent. Emissions from the still vent are routed to the condenser and then 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 flash tank recycle flow line is equipped with primary and backup VRUs. FUG 007 Equipment leaks (fugitive VOCs)from a natural gas compression facility. Enclosed combustor(manufacturer, model, SN: not ECD-1 008 submitted) controlling the TEG dehydrator non-condensable still vent emissions (Point 006) at a minimum control efficiency of 95%. PIG 009 Associated blowdowns with pig launching and receiving activities. The engines addressed under AIRS Points 001 through 005 may be replaced with another engine in accordance with the temporary engine replacement provision or with another Waukesha L7044GSI engine 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: AIRS ID: 12319B67 Page 2 of 28 Aik p . Co do e p e o Public Health and Environment II Air Pollution Control Division 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/downloadformshtml. 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, I I I.F.4.) 4. The operator shall complete all initial compliance testing and sampling as required in this permit and submit the results to the Division as part of the self-certification process. (Reference: Regulation No. 3, Part B, Section III.E.) 5. The manufacturer, model number, and serial number of the subject equipment shall be provided to the Division within fifteen days (15) after commencement of operation. This information shall be included on the Notice of Startup (NOS) submitted for the equipment. (Reference: Regulation No. 3, Part B, III.E.) 6. The operator shall retain the permit final authorization letter issued by the Division after completion of self-certification, with the most current construction permit. This construction permit alone does not provide final authority for the operation of this source. EMISSION LIMITATIONS AND RECORDS 7. Emissions of air pollutants shall not exceed the following limitations (as calculated in the Division's preliminary analysis). (Reference: Regulation No. 3, Part B, Section II.A.4) Monthly Limits: Facility AIRS Pounds per Month Emission Type Equipment ID Point NO,, VOC CO C-311 001 1,376 1,934 2,756 Point C-312 002 1,376 1,934 2,756 Point C-313 003 1,376 1,934 2,756 Point C-314 004 1,376 1,934 2,756 Point C-315 005 1,376 1,934 2,756 Point I AIRS ID: 123/9B67 Page 3 of 28 D Col do p i e o Pu Airblic PollutionHealthand Control DivisionEnvironment O-1 006 --- 3,873 --- Point FUG 007 --- 9,122 --- Fugitive ECD-1 008 340 323 1,869 Point PIG 009 --- 816 --- Point Facility AIRS Pounds per Month' Equipment ID Points NO, VOC CO Emission Type C-311 001 Point C-312 002 Point C-313 003 5,504 7,746 11,024 Point C-314 004 Point C-315 005 Point Monthly limits are based on a 31-day month. 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 3,397.3 lb/month. Annual Limits: Facility AIRS Tons per Year Emission Type Equipment ID Point NO, VOC CO C-311 001 8.1 11.4 16.2 Point C-312 002 8.1 11.4 16.2 Point C-313 003 8.1 11.4 16.2 Point C-314 004 8.1 11.4 16.2 Point C-315 005 8.1 11.4 16.2 Point O-1 006 --- 22.8 --- Point FUG 007 --- 53.7 --- Fugitive ECD-1 008 2.0 1.9 11.0 Point PIG 009 --- 4.8 --- Point Facility AIRS Tons per Year' Equipment ID Point NO, VOC CO Emission Type C-311 001 Point C-312 002 32.4 45.6 64.8 Point C-313 003 Point AIRS ID: 123/9B67 Page 4 of 28 lik Col ido e p e o Public Health and EnvironmentII Air Pollution Control Division C-314 004 Point C-315 005 Point ' The monthly and annual emissions limits contained in these tables represent the combined allowable emissions for all five emissions points combined. DCP's emissions for these five points are limited to the equivalent of four engines operating at 100% annual capacity. 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 20.0 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 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 C-311 001 Non-selective catalytic reduction system and air/fuel NOx, VOC, and CO ratio controller C-312 002 Non-selective catalytic reduction system and air/fuel NOx, VOC, and CO ratio controller C-313 003 Non-selective catalytic reduction system and air/fuel NOx, VOC, and CO ratio controller C-314 004 Non-selective catalytic reduction system and air/fuel NOx, VOC, and CO ratio controller C-315 005 Non-selective catalytic reduction system and air/fuel NON, VOC, and CO ratio controller D-1 006 Vapor recovery unit, Condenser, and Combustion VOC device (detailed in condition 18) FUG 007 RACT VOC 9. Point 009: 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: 123/9667 Page 5 of 28 Co do p e o Public Environment Air PollutionHealthand Control Division PROCESS LIMITATIONS AND RECORDS 10. This source shall be limited to the following maximum processing rates as listed below. • Monthly records of the actual processing rate shall be maintained by the applicant and made available to the Division for inspection upon request. (Reference: Regulation 3, Part B, II.A.4) Process/Consumption Limits Facility AIRS Annual Monthly Limit Equipment Point Process Parameter Limit (31 days) ID 115.99.84 C-311 001 Consumption of natural gas as fuel MMscf/yr cf/m MMscf/month 115.91 C-312 002 Consumption of natural gas as fuel MMscf/yr MMscf/month 115.99.84 C-313 003 Consumption of natural gas as fuel Mscf/ cf/m MMscf/yr MMscf/month 115.91 C-314 004 Consumption of natural gas as fuel MMscf/yr MMscf/month 115.91 C-315 005 Consumption of natural gas as fuel MMscf/yr MMscf/month 1 D-1 006 Natural gas throughput fm MMscf/yr 900 1,MMscf/month FUG 007 Not applicable 59.63 5.06 ECD-1 008 Fuel and Process Streams MMscf/yr MMscf/month PIG 009 Consumption of natural gas as fuel 697 Mscf/yr Facility AIRS Annual Monthly Limit Equipment Point Process Parameter Limit2 (31 days)2 ID C-311 001 C-312 002 Consumption of natural gas as fuel for 463.64 39.4 C-313 003 all 5 compressor engines. Total run MMscf/yr MMscf/month time shall not exceed 35,040 total total C-314 004 compressor engine-hours per year. C-315 005 The monthly and annual process limits contained in these tables represent the combined allowable emissions for all five emissions points combined. DCP's fuel consumption and hours of operation for these five points are limited to the equivalent of four engines operating at 100% annual capacity. 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. AIRS ID: 123/9B67 Page 6 of 28 Col = do • p e o Public Health and Environment ]::) Air Pollution Control Division STATE AND FEDERAL REGULATORY REQUIREMENTS 11. 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). 12. 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.) 13. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable) Waukesha Engines (AIRS Points 001 through 0051 14. This equipment is subject to the control requirements for stationary and portable engines in the 8-hour ozone control area under Regulation No. 7, Section XVI.B.1. For rich burn reciprocating internal combustion engines, a non-selective catalyst reduction system and an air fuel controller shall be required. 15. This equipment is subject to the control requirements for natural gas-fired reciprocating internal combustion engines under Regulation No. 7, Section XVII.E (State only enforceable). The owner or operator of any natural gas-fired reciprocating internal combustion engine that is either constructed or relocated to the state of Colorado from another state after the date listed in the table below shall operate and maintain each engine according to the manufacturer's written instructions or procedures to the extent practicable and consistent with technological limitations and good engineering and maintenance practices over the entire life of the engine so that it achieves the emission standards required in the table below: Maximum Engine Construction or Emission Standard in g/hp-hr HP Relocation Date NOx CO VOC z500HP July 1, 2007 2.0 4.0 1.0 July 1, 2010 1.0 2.0 0.7 Note: Per Regulation No. 7, Section XVII.B.4, internal combustion engines that are subject to an emissions control requirement in a federal maximum achievable control technology ("MACT") standard under 40 CFR Part 63, a Best Available Control Technology ("BACT") limit, or a New Source Performance Standard under 40 CFR Part 60 are not subject to this Section XVII. TEG Dehydrator(AIRS Point 006) 16. 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. I 17. 100% of emissions that result from the flash tank associated with this dehydrator shall be recycled to the compressor station inlet and recompressed. AIRS ID: 123/9667 Page 7 of 28 D Co do p e o Public Health and Environment Air Pollution Control Division 18. 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 a condenser and then 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.) 19. 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 24.0 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. 20. This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XII.H. Beginning May 1, 2005, uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas- condensate-glycol (GCG) separator(flash separator or flash tank), if present, shall be reduced by at least 90 percent through the use of air pollution control equipment. This source shall comply with all applicable general provisions of Regulation 7, Section XII. 21. The enclosed flare 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. 22. 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. 23. 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 AIRS ID: 123/9667 Page 8 of 28 I Col do p e o Public Health and Environment Air Pollution Control Division 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: Lo,,. =1.15*3.Ogal TEG * F*(/—O) lbH2O 24hr/day Where: LOFT = Optimal circulation rate, gal/hr. F = Gas flowrate (MMSCF/D) I = Inlet water content (Ib/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. • §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 alternate circulation rate using GRI— GLYCalcTM, Version 3.0 or higher. The owner or operator must document why the TEG dehydration unit must be operated using the alternate circulation rate and submit this documentation with the initial notification in accordance with §63.775(c)(7). • §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 (H) of this section and submit the information specified under§63.775(c)(7)(ii) through (v). AIRS ID: 123/9B67 Page 9 of 28 D Co do p e o Public HealthPollution andControl Environment Air Division • §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. • §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. • §63.776—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. AIRS ID: 123/9667 Page 10 of 28 Col do e o PublicAir HealthPollution andContro EnvlironmentDivision D • §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. • §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 007) AIRS ID: 12319B67 Page 11 of 28 D Col do C p e o Public Health and Environment 1M Air Pollution Control Division 24. 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. 25. The reciprocating compressors grouped with the fugitive emissions addressed by AIRS point 007 are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: • §60.5385(a) — Owner or operator must replace the reciprocating compressor rod packing according to either paragraph §60.5385(a)(1) or (2). (1) §60.5385(a)(1) - Before the compressor has operated for 26,000 hours. The number of hours of operation must be continuously monitored beginning upon initial startup of your reciprocating compressor affected facility, or October 15, 2012, or the date of the most recent reciprocating compressor rod packing replacement, whichever is later. (2) §60.5385(a)(2) - Prior to 36 months from the date of the most recent rod packing replacement, or 36 months from the date of startup for a new reciprocating compressor for which the rod packing has not yet been replaced. • §60.5410 — Owner or operator must demonstrate initial compliance with the standards as detailed in §60.5410(c). • §60.5415— Owner or operator must demonstrate continuous compliance with the standards as detailed in §60.5415(c). • §60.5420 - Owner or operator must comply with the notification, reporting, and recordkeeping requirements as specified in §60.5420(a), §60.5420(b)(1), §60.5420(b)(4), and §60.5420(c)(3). 26. 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 27, shall satisfy the requirement to apply RACT. 27. 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. AIRS ID: 12319B67 Page 12 of 28 Col do p me or Pu and D Airblic PollutionHealth Control DivisionEnvironment • 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. 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 AIRS ID: 123/9B67 Page 13 of 28 D Co do p e o Public Health and Environment Air Pollution Control Division 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. Pigging/Receiving Blowdowns (Point 0091 28. The permittee shall record each time a blowdown event occurs. The permittee shall record the start and finish time of each such event. 29. 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. 30. The permittee shall calculate the VOC emissions from each event using the volume of gas estimated in accordance with Condition 29 and a representative gas analysis as required by Condition 40. 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 31. AIRS Points 001-006: 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.) 32. AIRS Point 006: The condenser outlet temperature shall be recorded as per the frequency required in the approved O&M Plan. This information shall be maintained in a log on site and made available to the Division for inspection upon request. The condenser outlet temperature shall not exceed 160 °F on a monthly average basis. COMPLIANCE TESTING AND SAMPLING Initial Testing Requirements 33. AIRS Points 001 through 005: A source initial compliance test shall be conducted on emissions point 001, 002, 003, 004 and 005 to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits contained in this permit. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) AIRS ID: 123/9667 Page 14 of 28 Col do p r e o Public Health and Environment Air Pollution Control Division Oxides of Nitrogen Carbon Monoxide Volatile Organic Compounds Formaldehyde 34. AIRS Point 006: 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.) 35. AIRS Point 006: The owner or operator shall demonstrate compliance with Condition 21, using EPA Method 22 to measure opacity from the flare. 36. AIRS Points 007 and 009: Within one hundred and eighty days (180) after commencement of operation, the permittee shall complete the initial extended gas analysis of gas samples that are representative of volatile organic compound (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas analysis shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. The operator shall submit the results of the gas analysis and emission calculations to the Division as part of the self- certification process to ensure compliance with emissions limits. 37. AIRS Point 007: Within one hundred and eighty days (180) after commencement of operation, the operator shall complete a hard count of components at the source and establish the number of components that are operated in "heavy liquid service", "light liquid service", "water/oil service" and "gas service". The operator shall submit the results to the Division as part of the self-certification process to ensure compliance with emissions limits. Periodic Testing Requirements 38. AIRS Points 001 _ through 005: Each engine is subject to the periodic testing requirements as specified in the operating and maintenance (O&M) plan as approved by the Division. Revisions to your O&M plan are subject to Division approval. Replacements of this unit completed as Alternative Operating Scenarios may be subject to additional testing requirements as specified in Attachment A. 39. AIRS Point 006: The owner or operator shall complete an extended wet gas analysis prior to the inlet of the TEG dehydrator on an annual basis. Results of the wet gas analysis shall be used to calculate emissions of criteria pollutants and hazardous air pollutants per this permit. 40. AIRS Points 007 and 009: 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. 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 41. 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: AIRS ID: 123/9667 Page 15 of 28 D Co do p e o Public Health and Environment Air Pollution Control Division For any criteria pollutant: For sources emitting less than 100 tons per year, a change in actual emissions of five (5)tons per year or more, above the level reported on the last APEN; or For volatile organic compounds (VOC) and nitrogen oxides sources (NOr) in ozone nonattainment areas emitting less than 100 tons of VOC or NO per year, a change in annual actual emissions of one (1) ton per year or more or five percent, whichever is greater, above the level reported on the last APEN; or For sources emitting 100 tons per year or more, a change in actual emissions of five percent or 50 tons per year or more, whichever is less, above the level reported on the last APEN submitted; or For any non-criteria reportable pollutant: If the emissions increase by 50% or five (5) tons per year, whichever is less, above the level reported on the last APEN submitted to the Division. b. Whenever there is a change in the owner or operator of any facility, process, or activity; or c. Whenever new control equipment is installed, or whenever a different type of control equipment replaces an existing type of control equipment; or d. Whenever a permit limitation must be modified; or e. No later than 30 days before the existing APEN expires. f. AIRS Points 001-005: Within 14 calendar days of commencing operation of a permanent replacement engine under the alternative operating scenario outlined in this permit as Attachment A. The APEN shall include the specific manufacturer, model and serial number and horsepower of the permanent replacement engine, the appropriate APEN filing fee and a cover letter explaining that the permittee is exercising an alternative-operatirg scenario and is installing a permanent replacement engine. 42. Federal regulatory program requirements (i.e. PSD, NANSR or Title V Operating Permit) shall apply to this source at any such time that this source becomes major solely by virtue of a relaxation in any permit condition. Any relaxation that increases the potential to emit above the applicable Federal program threshold will require a full review of the source as though construction had not yet commenced on the source. The source shall not exceed the Federal program threshold until a permit is granted. (Regulation No. 3 Part D). 43. 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) . 44. MACT Subpart 7777 - National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines 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 AIRS ID: 123/9667 Page 16 of 28 Col do p e o Public Health and Environment Air Pollution Control Division that Subpart on the date as stated in the rule as published in the Federal Register. (Reference: Regulation No. 8, Part E) GENERAL TERMS AND CONDITIONS: 45. 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. 46. 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. 47. 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. 48. 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. 49. Each and every condition of this permit is a material part hereof and is not severable. Any challenge to or appeal of a condition hereof shall constitute a rejection of the entire permit and upon such occurrence, this permit shall be deemed denied ab initio. This permit may be revoked at any time prior to self-certification and final authorization by the Air Pollution Control Division (APCD) on grounds set forth in the Colorado Air Quality Control Act and regulations of the Air Quality Control Commission (AQCC), including failure to meet any express term or condition of the permit. If the Division denies a permit, conditions imposed upon a permit are contested by the applicant, or the Division revokes a permit, the applicant or owner or operator of a source may request a hearing before the AQCC for review of the Division's action. 50. 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. 51. Violation of the terms of a permit or of the provisions of the Colorado Air Pollution Prevention and Control Act or the regulations of the AQCC may result in administrative, civil or criminal enforcement actions under Sections 25-7-115 (enforcement), -121 (injunctions), -122 (civil penalties), -122.1 (criminal penalties), C.R.S. AIRS ID: 123/9B67 Page 17 of 28 DCo do C p e o Public PollutionHealthand Control DivisionEnvironment 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 (5) engines, (1) TEG dehydrator and combustor, blowdowns and associated fugitives. Synthetic minor facility. AIRS ID: 123/9867 Page 18 of 28 Col do p me o Public 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.cdohe.state.co.us/regulations/airreg.s/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. Uncontrolled Emission Are the Controlled AIRS Rate emissions Emission Point Pollutant CAS# BIN (Ib/yr) reportable? Rate(Ib/yr) 6488 (1622 for 1556 (389 for each individ. each individ. Formaldehyde 50000 A running Yes running engine) engine) 1420 (355 for 708 (177 for Methanol 67561 C each individ. No each individ. running running engine) engine) 1292 (323 for 648 (162 for Acetaldehyde 75070 A each individ. Yes each individ. running running engine) engine) 001- 1220 (305 for 608 (152 for each individ. Yes each individ. 005 Acrolein 107028 A each running running engine) engine) 732 (183 for 368 (92 for Benzene 71432 A each individ. Yes each individ. running running engine) engine) 308 (77 for 152 (38 for 1,3-Butadiene 106990 A each individ. Yes each individ. running running engine) engine) 260 (65 for 128 (32 for Toluene 108883 C each individ. No each individ. running running engine) engine) AIRS ID: 123/9667 Page 19 of 28 DCo do p e o Public PollutionHealthand Control DivisionEnvironment Benzene 71432 A 164,460 Yes 10,333 Toluene 108883 C 208,584 Yes 11,577 006 Ethylbenzene 100414 C 9,104 Yes 389 Xylenes 1330207 C 104,783 Yes 4,327 n-Hexane 110543 C 78,590 Yes 2,855 007 n-Hexane 110543 C 18,726 Yes 18,726 009 n-Hexane 110543 C 122 No NA Note: DCP shall be running four (4) engines from out of the five (5) engines onsite, therefore, combining HAP emissions between four engines. 5) The emission levels contained in this permit are based on the following emission factors: Points 001 through 005: Emission Factors- Emission Factors— Uncontrolled Controlled CAS Pollutant lb/MMBtu g/bhp-hr IbIMMBtu g/bhp-hr NOx 3.6669 13.1000 0.1400 0.5000 CO 3.2750 11.7000 0.2799 1.0000 VOC 0.4199 1.5000 0.1959 0.7000 5000 Formaldehyde 0.0140 0.0500 0.0034 0.0120 67561 Methanol 0.0031 0.0109 0.0015 0.0055 75070 Acetaldehyde 0.0028 0.0100 0.0014 0.0050 107028 _ Acrolein 0.0026 0.0094 0.0013 0.0047 , 71432 Benzene 0.0016 0.0056 0.0008 0.0028 106990 1,3-Butadiene 0.0007 0.0024 0.0003 0.0012 108883 Toluene 0.0006 0.0020 0.0003 0.0010 Emission factors are based on a Brake-Specific Fuel Consumption Factor of 7876 Btu/hp-hr, a site-rated horsepower value of 1680, and a fuel heat value of 1000 Btu/scf. Emission Factor Sources: CAS Pollutant Uncontrolled EFSource Controlled EF Source NOx Manufacturer's specifications Manufacturer's specifications CO Manufacturer's specifications Manufacturer's specifications VOC Manufacturer's specifications Manufacturer's specifications 50000 Formaldehyde Manufacturer's specifications Manufacturer's specifications 67561 Methanol AP-42; Table 3.2-3(7/2000); Manufacturer's specifications Natural Gas 75070 Acetaldehyde AP-42; Table 3.2-3(7/2000); Manufacturer's specifications Natural Gas 107028 Acrolein AP-42; Table 3.2-3(7/2000); Manufacturer's specifications Natural Gas 71432 Benzene AP-42; Table 3.2-3(7/2000); Manufacturer's specifications Natural Gas 106990 1,3-Butadiene AP-42; Table 3.2-3(7/2000); Manufacturer's specifications Natural Gas 108883 Toluene AP-42; Table 3.2-3 (7/2000); Manufacturer's specifications Natural Gas Point 006: AIRS ID: 12319B67 Page 20 of 28 . ColA•do p e o Public Health and Environment Air Pollution Control Division 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 100% recycle of the flash tank emissions 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 = 60MMscfd; I = 63.73 lb/MMscf; and O= 1.9 lb/MMscf. Point 007: Component Gas Service Heavy Oil Light Oil Water/Oil Service Connectors 2365 --- 2653 0 Flanges 449 --- 1123 0 Open-ended Lines 0 --- 0 0 Pump Seals 0 --- 14 0 Valves 545 --- 1358 0 Other* 34 --- 47 0 VOC Content(wt%) 24.74% 100% 100% 100% *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 008: CAS Pollutant lb/MMBtu Source NOx 0.068 AP-42, Table 13.5-1 VOC 0.063 AP-42, Table 13.5-1 CO 0.370 AP-42, Table 13.5-1 • Point 009: CAS Pollutant lb/MSCF Source VOC 13.7733 Engineering Calculation 110543 n-hexane 0.175 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 AIRS ID: 123/9667 Page 21 of 28 II) Co do p e o Public Health and Environment Air Pollution Control Division 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 1.5 MMBtu/hr requirements because the design rate is less than 5 MMBtWhr (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) AIRS Points 001 through 005: Each engine is subject to 40 CFR, Part 60, Subpart JJJJ— Standards of Performance for Stationary Spark Ignition Internal Combustion Engines (See January 18, 2008 Federal Register posting— effective March 18, 2008). This rule has not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 6. A copy of the complete subpart is available on the EPA website at: htto://www.eoa.aov/ttn/atw/area/fr18ia48.odf 9) AIRS Points 001 through 005: Each engine is subject to 40 CFR, Part 63, Subpart ZZZZ-National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines. (See January 18, 2008 Federal Register posting -effective March 18, 2008). The January 18, 2008 amendments to include requirements for area sources and engines < 500 hp located at major sources have not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 8. A copy of the complete subpart is available on the EPA website at: htto://www.eoa.aovAtn/atw/area/fr18ia08.ixtf Additional information regarding area source standards can be found on the EPA website at: htto://www.eoa.aov/ttn/atw/area/arearules.html 10) This facility is classified as follows: Applicable Status Requirement Operating Permit Synthetic Minor Source CO, VOC, NOx, benzene,toluene, xylenes, n-hexane, total HAPs PSD Synthetic Minor Source CO NANSR Synthetic Minor Source VOC, NOx MACT HH Area Source Requirements MACT 7777 Area Source Requirements 11) Full text of the Title 40, Protection of Environment Electronic Code of Federal Regulations can be found at the website listed below: http://ecfr.gpoaccess.gov/ AIRS ID: 123/9B67 Page 22 of 28 Col '4do D prt e o Public Health and Environment Il Air Pollution Control Division 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 12) 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:f/www.cdphe state co us/ap/oilgaspermitting html AIRS ID: 123/9B67 Page 23 of 28 D Co do p e o Pu Environment Airblic PollutionHealthand Control Division ATTACHMENT A: ALTERNATIVE OPERATING SCENARIOS RECIPROCATING INTERNAL COMBUSTION ENGINES December 10, 2008 The following Alternative Operating Scenario (AOS)for the temporary and permanent replacement of natural gas fired reciprocating internal combustion engines has been reviewed in accordance with the requirements of Regulation No. 3., Part A, Section IV.A, Operational Flexibility-Alternative Operating Scenarios, Regulation No. 3, Part B, Construction Permits, and Regulation No. 3, Part D, Major Stationary Source New Source Review and Prevention of Significant Deterioration, and it has been found to meet all applicable substantive and procedural requirements. This permit incorporates and shall be considered a Construction Permit for any engine replacement performed in accordance with this AOS, and the permittee shall be allowed to perform such engine replacement without applying for a revision to this permit or obtaining a new Construction Permit. A.1 Engine Replacement The following AOS is incorporated into this permit in order to deal with a compressor engine breakdown or periodic routine maintenance and repair of an existing onsite engine that requires the use of either a temporary or permanent replacement engine. "Temporary" is defined as in the same service for 90 operating days or less in any 12 month period. Permanent" is defined as in the same service for more than 90 operating days in any 12 month period. The 90 days is the total number of days that the engine is in operation. If the engine operates only part of a day, that day shall count as a single day towards the 90-day total. The compliance demonstrations and any periodic monitoring required by this AOS are in addition to any compliance demonstrations or periodic monitoring required by this permit. All replacement engines are subject to all federally applicable and state-only requirements set forth in this permit(including monitoring and record keeping). The results of all tests and the associated calculations required by this AOS shall be submitted to the Division within 30 calendar days of the test or within 60 days of the test if such testing is required to demonstrate compliance with NSPS or MACT requirements. Results of all tests shall be kept on site for five(5) years and made available to the Division upon request. The permittee shall maintain a log on-site and contemporaneously record the start and stop date of any engine replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number of the engine(s) that are replaced during the term of this permit, and the manufacturer, model number, horsepower, and serial number of the replacement engine. In addition to the log, the permittee shall maintain a copy of all Applicability Reports required under section A.1.2 and make them available to the Division upon request. A.1.1 The permittee may temporarily replace an existing compressor engine that is subject to the emission limits set forth in this permit with an engine that is of the same manufacturer, model, and horsepower or a different manufacturer, model, or horsepower as the existing engine without modifying this permit, so long as the emissions from the temporary replacement engine comply with the emission limitations for the existing permitted engine as determined in section A.2. Measurement of emissions from the temporary replacement engine shall be made as set forth in section A.2. A.1.2 The permittee may permanently replace the existing compressor engine with an engine that is of the same manufacturer, model and horsepower without modifying this permit so long as the emissions from the permanent replacement engine comply with 1) the permitted annual emission limitations for the existing engine, 2) any permitted short-term emission limitations for the existing permitted engine, and 3) AIRS ID: 123/9667 Page 24 of 28 - 1,. Cola do • px e o Public Health and Environment ` Air Pollution Control Division the applicable emission limitations as set forth in the Applicability Report submitted to the Division with the Air Pollutant Emissions Notice(APEN)for the replacement engine (see htto://www.cdphe.state.co.us/ap/oilgaspermittina.html for example applicability report formats). Measurement of emissions from the permanent replacement engine and compliance with the applicable emission limitations shall be made as set forth in section A.2. An Air Pollutant Emissions Notice(APEN)that includes the specific manufacturer, model and serial number and horsepower of the permanent replacement engine shall be filed with the Division for the permanent replacement engine within 14 calendar days of commencing operation of the replacement engine. The APEN shall be accompanied by the appropriate APEN filing fee, a cover letter explaining that the permittee is exercising an alternative operating scenario and is installing a permanent replacement engine, and a copy of the relevant Applicability Reports for the replacement engine. Example Applicability Reports can be found at http://www.cdphe.state.co.us/ap/oiloaspermittinq.html. This submittal shall be accompanied by a certification from a person legally authorized to act on behalf of the source indicating that"based on the information and belief formed after reasonable inquiry, the statements and information included in the submittal are true, accurate and complete". This AOS cannot be used for permanent engine replacement of a grandfathered or permit exempt engine or an engine that is not subject to emission limits. The permittee shall agree to pay fees based on the normal permit processing rate for review of information submitted to the Division in regard to any permanent engine replacement. A.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 permittee 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 permittee shall measure nitrogen oxide (NOX) and carbon monoxide(CO) emissions in the exhaust from the replacement engine using a portable flue gas analyzer within seven (7)calendar days of commencing operation of the replacement engine. All portable analyzer testing required by this permit shall be conducted using the Division's Portable Analyzer Monitoring Protocol (ver March 2006 or newer) as found on the Division's website at: http://www.cdphe.state.co.us/ap/down/portanalyzeproto.pdf Results of the portable analyzer tests shall be used to monitor the compliance status of this unit. For comparison with an annual (tons/year) or short term (lbs/unit of time) emission limit, the results of the tests shall be converted to a lb/hr basis and multiplied by the allowable operating hours in the month or year(whichever applies) in order to monitor compliance. If a source is not limited in its hours of operation the test results will be multiplied by the maximum number of hours in the month or year(8760), whichever applies. For comparison with a short-term limit that is either input based (lb/mmBtu), output based (g/hp-hr) or concentration based (ppmvd @ 15%O2)that the existing unit is currently subject to or the replacement AIRS ID: 123/9B67 Page 25 of 28 i Co do C�pa/t e o Public Health and Environment 1■p Air Pollution Control Division engine will be subject to, the results of the test shall be converted to the appropriate units as described in the above-mentioned Portable Analyzer Monitoring Protocol document. If the portable analyzer results indicate compliance with both the NOX and CO emission limitations, in the absence of credible evidence to the contrary, the source may certify that the engine is in compliance with both the NOX and CO emission limitations for the relevant time period. Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if the portable analyzer results fail to demonstrate compliance with either the NOX or CO emission limitations, the engine will be considered to be out of compliance from the date of the portable analyzer test until a portable analyzer test indicates compliance with both the NOX and CO emission limitations or until the engine is taken offline. A.3 Applicable Regulations for Permanent Engine Replacements A.3.1 Reasonably Available Control Technology (RACT): Reg 3, Part B§ II.D.2 All permanent replacement engines that are located in an area that is classified as attainment/maintenance or nonattainment must apply Reasonably Available Control Technology (RACT) for the pollutants for which the area is attainment/maintenance or nonattainment. Note that both VOC and NOX are precursors for ozone. RACT shall be applied for any level of emissions of the pollutant for which the area is in attainment/maintenance or nonattainment, except as follows: In the Denver Metropolitan PM10 attainment/maintenance area, RACT applies to PM10 at any level of emissions and to NOX and 8O2, as precursors to PM10, if the potential to emit of NOX or SO2 exceeds 40 tons/yr. For purposes of this AOS, the following shall be considered RACT for natural-gas fired reciprocating internal combustion engines: VOC: The emission limitations in NSPS JJJJ CO: The emission limitations in NSPS JJJJ NOX: The emission limitations in NSPS JJJJ SO2: Use of natural gas as fuel PM10: Use of natural gas as fuel As defined in 40 CFR Part 60 Subparts GG (§ 60.331)and 40 CFR Part 72 (§72.2), natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. ' A.3.2 Control Requirements and Emission Standards: Regulation No. 7, Sections XVI. and XVII.E (State-Only conditions). Control Requirements: Section XVI Any permanent replacement engine located within the boundaries of an ozone nonattainment area is subject to the applicable control requirements specified in Regulation No. 7, section XVI, as specified below: Rich burn engines with a manufacturer's design rate greater than 500 hp shall use a non- selective catalyst and air fuel controller to reduce emission. Lean burn engines with a manufacturer's design rate greater than 500 hp shall use an oxidation catalyst to reduce emissions. AIRS ID: 123/9B67 Page 26 of 28 Col do p meg. of PubD lic PollutionHealthand Control DivisionEnvironment The above emission control equipment shall be appropriately sized for the engine and shall be operated and maintained according to manufacturer specifications. The source shall submit copies of the relevant Applicability Reports required under Condition A.1.2. Emission Standards: Section XVII.E—State-only requirements Any permanent engine that is either constructed or relocated to the state of Colorado from another state, after the date listed in the table below shall operate and maintain each engine according to the manufacturer's written instructions or procedures to the extent practicable and consistent with technological limitations and good engineering and maintenance practices over the entire life of the engine so that it achieves the emission standards required in the table below: Construction or Emission Standards in G/hp-hr Max Engine HP Relocation Date NOx CO VOC January 1, 2008 2.0 4.0 1.0 100<Hp<500 January 1, 2011 1.0 2.0 0.7 July 1, 2007 2.0 4.0 1.0 500<Hp July 1, 2010 1.0 2.0 0.7 The source shall submit copies of the relevant Applicability Reports required under Condition A.1.2 A.3.3 NSPS for spark ignition internal combustion engines: 40 CFR 60, Subpart JJJJ A permanent replacement engine that is manufactured on or after 7/1/09 for emergency engines greater than 25 hp, 7/1/2008 for engines less than 500 hp, 7/1/2007 for engines greater than or equal to 500 hp except for lean burn engines greater than or equal to 500 hp and less than 1,350 hp, and 1/1/2008 for lean burn engines greater than or equal to 500 hp and less than 1,350 hp are subject 40 CFR 60, Subpart JJJJ. An analysis of applicable monitoring, recordkeeping, and reporting requirements for the permanent engine replacement shall be included in the Applicability Reports required under Condition A.1.2. Any testing required by the NSPS is in addition to that required by this AOS. Note that the initial test required by NSPS Subpart JJJJ can serve as the testing required by this AOS under Condition A.2, if approved in advance by the Division, provided that such test is conducted within the time frame specified in Condition A.2. Note that under the provisions of Regulation No. 6. Part B, section I.B. that Relocation of a source from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of Regulation No. 6 (i.e., the date that the source is first relocated to Colorado becomes equivalent to the manufacture date for purposes of determining the applicability of NSPS JJJJ requirements). However, as of November 1, 2008 the Division has not yet adopted NSPS.JJJJ. Until such time as it does, any engine subject to NSPS will be subject only under Federal law. Once the Division adopts NSPS JJJJ, there will be an additional step added to the determination of the NSPS. Under the provisions of Regulation No. 6, Part 8, §LB(which is referenced in Part A), any engine relocated from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of NSPS JJJJ. A.3.4 Reciprocating internal combustion engine(RICE) MACT: 40 CFR Part 63, Subpart ZZZZ A.3.4.1 Area Source for HAPs AIRS ID: 123/9B67 Page 27 of 28 iii) Co do p e o Public Health and Environment Air Pollution Control Division A permanent replacement engine located at an area source that commenced construction or reconstruction after June 12, 2006 as defined in §63.2,will meet the requirements of 40 CFR Part 63, Subpart ZZZZ by meeting the requirements of 40 CFR Part 60, Subpart JJJJ. An analysis of the applicable monitoring, recordkeeping, and reporting requirements for the permanent engine replacement shall be included in the Applicability Reports required under Condition A.1.2. Any testing required by the MACT is in addition to that required by this AOS. Note that the initial test required by the MACT can serve as the testing required by this AOS under Condition A.2, if approved in advance by the Division, provided that such test is conducted within the time frame specified in Condition A.2. A.3.4.2 Major source for HAPs A permanent replacement engine that is located at major source is subject to the requirements in 40 CFR Part 63 Subpart 7777 as follows: Existing, new or reconstructed spark ignition 4 stroke rich burn engines with a site rating of more than 500 hp are subject to the requirements in 40 CFR Part 63 Subpart ZZZZ. New or reconstructed (construction or reconstruction commenced after 12/19/02)2 stroke and 4 stroke lean burn engines with a site rating of more than 500 hp are subject to the requirements in 40 CFR Part 63 Subpart ZZZZ. New or reconstructed(construction or reconstruction commenced after 6/12/06)4 stroke lean burn engines with a site rating of greater than or equal to 250 but less or equal to 500 hp and were manufactured on or after 1/1/08 are subject to the requirements in 40 CFR Part 63 Subpart ZZZZ. New or reconstructed(construction or reconstruction commenced after 6/12/06)2 stroke lean burn or 4 stroke rich burn engines with a site rating of 500 hp or less will meet the requirements of 40 CFR 63, Subpart ZZZZ by meeting the requirements of 40 CFR 60, Subpart JJJJ. New or reconstructed(construction or reconstruction commenced after 6/12/06)4 stroke lean burn engines with a site rating of less than 250 hp will meet the requirements of 40 CFR 63, Subpart ZZZZ by meeting the requirements of 40 CFR 60, Subpart JJJJ. An analysis of the applicable monitoring, recordkeeping, and reporting requirements for the permanent engine replacement shall be included in the Applicability Reports required under Condition A.1.2. Any testing required by the MACT is in addition to that required by this AOS. Note that the initial test required by the MACT can serve as the testing required by this AOS under Condition A.2, if approved in advance by the Division, provided that such test is conducted within the time frame specified in Condition A.2. A.3.5 Additional Sources The replacement of an existing engine with a new engine is viewed by the Division as the installation of a new emissions unit, not"routine replacement"of an existing unit. The AOS is therefore essentially an advanced construction permit review. The AOS cannot be used for additional new emission points for any site; an engine that is being installed as an entirely new emission point and not as part of an AOS- approved replacement of an existing onsite engine has to go through the appropriate Construction/Operating permitting process prior to installation. AIRS ID: 123/9B67 Page 28 of 28 Construction Permit Application Preliminary Analysis Summary Section 1 —Applicant Information Company Name: DCP Midstream, LP Permit Number: 13WE2169 Source Location: 70 Ranch Compressor Station SWNW Section 20, T5N, R63W,Weld County (non-attainment) Point 001: 4SRB RICE Point 002: 4SRB RICE Point 003: 4SRB RICE Point 004: 4SRB RICE Equipment Description: Point 005: 4SRB RICE Point 006: TEG glycol dehydrator Point 007: Fugitive emissions Point 008: Dehydrator still vent control device Point 009: Pigging/Receiving blowdowns AIRS ID: 123/9667 Date: August 21, 2013; Picked up again January 9, 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? On what date was this application complete? May 8, 2013. Division received APEN for Point 009 via mail on 1/13/2014. Section 4—Source Description AIRS Point Equipment Description Page 1 One(1)Waukesha, Model L7044GSI, Serial Number TBD, natural gas-fired, turbo • - charged, 4SRB reciprocating internal combustion engine, site rated at 1680 horsepower 001 at 1200 RPM. This engine shall be equipped with non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. One (1)Waukesha, Model L7044GSI, Serial Number TBD, natural gas-fired, turbo- charged, 4SRB reciprocating internal combustion engine, site rated at 1680 horsepower 002 at 1200 RPM. This engine shall be equipped with non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. One (1)Waukesha, Model L7044GSI, Serial Number TBD, natural gas-fired, turbo- charged, 4SRB reciprocating internal combustion engine, site rated at 1680 horsepower 003 at 1200 RPM. This engine shall be equipped with non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. One (1)Waukesha, Model L7044GSI, Serial Number TBD, natural gas-fired, turbo- charged, 4SRB reciprocating internal combustion engine, site rated at 1680 horsepower 004 at 1200 RPM. This engine shall be equipped with non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. One (1)Waukesha, Model L7044GSI, Serial Number TBD, natural gas-fired, turbo- charged, 4SRB reciprocating internal combustion engine, site rated at 1680 horsepower 005 at 1200 RPM. This engine shall be equipped with non-selective catalytic reduction (NSCR) system and air-fuel ratio control. This emission unit is used for natural gas compression. One (1)Triethylene glycol (TEG) natural gas dehydration unit(make, model, serial number: not submitted)with a design capacity of 60 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 a design capacity of 24 gallons per minute 006 each. This unit is equipped with a flash tank, reboiler and still vent. Emissions from the still vent are routed to the condenser and then 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 flash tank recycle flow line is equipped with primary and backup VRUs. 007 Equipment leaks(fugitive VOCs)from a natural gas compression facility. Enclosed combustor(manufacturer, model, SN: not submitted) controlling the TEG 008 dehydrator non-condensable still vent emissions(Point 006) at a minimum control efficiency of 95%. 009 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? PM,() 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 PKo CO Ozone RACT per Regulation 3, Part B,Section III.D.2) Page 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 001 Manufacturer's specifications 002 Manufacturer's specifications 003 Manufacturer's specifications 004 Manufacturer's specifications 005 Manufacturer's specifications 006 GRI Gly-Calc v4.0. Refer to Section 14 for calculations. 007 EPA-453/R-95-017, Table 2-4 008 AP-42, Table 13.5-1 009 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 001 115.9 MMscf per year, 1680 hp 002 115.9 MMscf per year, 1680 hp 003 115.9 MMscf per year, 1680 hp 004 115.9 MMscf per year, 1680 hp 005 115.9 MMscf per year, 1680 hp 006 21,900 MMSCF per year, 24 gallons per minute glycol circulation rate Equipment Type Gas Heavy Oil (or Light Oil (or Water/Oil Heavy Liquid) Light Liquid) Connectors 2365 --- 2653 --- 007 Flanges 449 --- 1123 Open-Ended Lines 0 --- 0 --- Pump Seals 0 --- 14 Valves 545 --- 1358 Other 34 --- 47 008 59.63 MMSF per year 009 697 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 001 115.9 MMscf per year, 1680 hp 002 115.9 MMscf per year, 1680 hp 003 115.9 MMscf per year, 1680 hp Page 3 004 115.9 MMscf per year, 1680 hp 005 115.9 MMscf per year, 1680 hp 006 21,900 MMSCF per year, 24 gallons per minute glycol circulation rate Equipment Type Gas Heavy Oil(or Light Oil(or Water/Oil Heavy Liquid) Light Liquid) Connectors 2365 --- 2653 -- 007 Flanges 449 --- 1123 --- Open-Ended Lines 0 --- 0 --- Pump Seals 0 — 14 --- Valves 545 — 1358 --- Other 34 — 47 — 008 59.63 MMSF per year 009 697 MSCF per year Does this source use a control device? X Yes No %Reduction AIRS Point Process Control Device Description Pollutant Granted NOx 96.2% VOC 53.3% 001 through 01 NSCR and air fuel ratio controller CO 91.5% 005 HCHO 76% Other HAPs 50% 006 of VRU for flash tank and a condenser/enclosed VOC 97% combustor for Still Vent 007, 008, 01 None NA 009 Section 6—Emission Summary(tons per year) Point TSP NO, VOC CO Single HAP Total HAP 001 002 3.2 003 4.4 850.0 97.3 759.2 6.0 formaldehyde 004 005 Facility,PTE Before 104 3 Emissions 006 657.2 — 282.8 Controls/Limits: toluene 9.4 007A 53.7 n-hexane 9.4 008 --- 2.0 1.9 11.0 --- -- 009 -- --- 4.8 -- 0.06 0.06 n-hexane 99.1 TotalB 4.4 850.6 742.6 762.2 276.5 toluene Point TSP NO, VOC CO Single HAP Total HAP 001 002 Controlled point 0.8 source emission 003 4.4 32.4 45.6 64.8 formaldehyde 2.0 rate: 004 005 Page 4 5.8 006 --- --- 22.8 --- toluene 14.7 007A --- --- 53.7 9.4 9.4 n-hexane 008 --- 2.0 1.9 11.0 --- --- 009 --- --- 4.8 --- 0.06 0.06 n-hexane Insig. 0.1 0.6 2.0 1.1 0'02 0.02 n-hexane 9.5 Tota1B 4.5 35.0 130.8 76.9 26.2 hexane Total permitted plant-wide 5.8 emissionsc: 4.4 34.4 78.8 75.8 toluene 16.8 A: These emissions are fugitive sources so they are not included in the total for PTE. B: The total PTE values in this line also include emissions for insignificant activities. The facility's insignificant activities include one 1.5 MMBtu/hr dehy reboiler, pressurized condensate loadout, compressor blowdowns, two 100 bbl produced water tanks, one 1000 gallon methanol tank, 200 gallon lube oil tank, 1000 gallon glycol tanks and 80 bbl drain tank. Emission rates for insignificant activities are based on emission estimates provided with this package. C: These emissions do not include insignificant activities but do include fugitives that qualify as permitted emission sources. Section 7—Non-Criteria/Hazardous Air Pollutants Uncontrolled Are the emissions Controlled Emission AIRS ID Pollutant CAS# BIN Emission Rate reportable? Rate(Ib/yr) (lb/yr) 6488 (1622 for 1556 (389 for Formaldehyde 50000 A each individ. Yes each individ. running running engine) engine) 1420 (355 for 708 (177 for each Methanol 67561 C each individ. No individ. running running engine) engine) 1292 (323 for 648 (162 for each Acetaldehyde 75070 A each individ. Yes individ. running running engine) engine) 1220 (305 for 608 (152 for each 001-005 Acrolein 107028 A each individ. Yes individ. running each running engine) engine) 732 (183 for 368 (92 for each Benzene 71432 A each individ. Yes individ. running running engine) engine) 308 (77 for 152 (38 for each 1,3-Butadiene 106990 A each individ. Yes individ. running running engine) engine) 260 (65 for 128 (32 for each Toluene 108883 C each individ. No individ. running running engine) engine) Benzene 71432 A 164,460 YES 10,333 006 Toluene 108883 C 208,584 YES 11,577 Ethylbenzene 100414 C 9,104 YES 389 Page 5 Xylenes 1330207 C 104,783 YES 4,327 n-Hexane 110543 C 78,590 YES 2,855 007 n-Hexane 110543 C 18,726 YES 18,726 009 n-Hexane 110543 C 122 No NA Note: Regulation 3, Part A, Section II.B.3.b APEN emission reporting requirements for non-criteria air pollutants are based on potential emissions without credit for reductions achieved by control devices used by the operator. Section 8—Testing Requirements Will testing be required to show compliance with any emission rate or regulatory x yes No standard? If"yes", complete the information listed below AIRS Point Process Pollutant Regulatory Basis Test Method NOx, CO, 001-005 01 VOC, Regulation No. 3, Part B., Section III.G.3 Stack Test HAPS 006 01 VOC, Regulation No. 3, Part B, Section III.E. Extended gas HAPS analysis 006 01 VOC, State Only Requirement Method 22 HAPS 007 01 VOC, State Only Requirement Extended gas HAPS analysis 007 01 VOC, State Only Requirement Hard component 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 X 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? NOx, CO,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)? 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? Controlled NOx emissions<40 tpy. Controlled CO emissions< 100 tpy. AIRS Point Section 12—Regulatory Review Retaliation 1 - Particulate. Smoke. Carbon Monoxide and Sulfur Dioxide Page 6 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 001-009 is in excess of 20% opacity. This standard is based on 24 consecutive opacity readings taken at 15-second intervals for six minutes. The approved reference test method for visible emissions measurement is EPA Method 9 (40 CFR, Part 60, Appendix A(July, 1992)) in all subsections of Section II. A and B of this regulation. Regulation 2—Odor Section I.A- No person, wherever located, shall cause or allow the emission of odorous air contaminants from any single source such as to result in detectable odors which are 001-009 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 001-009 Part A-APEN Requirements Applicant is required to file an APEN since emissions exceed applicable thresholds. Part B—Construction Permit Exemptions 001-009 Applicant is required to obtain a permit since emissions exceed applicable thresholds. (Reg. 3, Pad B, Section II.D.2) Regulation 6- New Source Performance Standards 001-005 NSPS JJJ: Not currently adopted in Colorado regulations. Listed in "Notes to permit holder." 006, 008, None 009 NSPS OOOO: Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution. For fugitive emissions at natural gas processing plants subject to NSPS OOOO. This subpart establishes emission standards and compliance schedules for the control of volatile organic compounds (VOC)and sulfur dioxide (SO2) emissions from affected facilities that commence construction, 007 modification or reconstruction after August 23, 2011. Is this source at a "natural gas processing plant?" No; it is being called a compressor station Is this source subject to NSPS OOOO? Yes WHY? Operator believes that the compressors are subject to NSPS OOOO. Since we have devised a condition for the compressors in fugitives, the fugitives will be subject to NSPS OOOO and not directly the compressor engines. Page 7 Reaulation 7—Volatile Omanic Compounds Section XVI.B Applicant is located in NAA and thus required to install NSCR on rich burn engine rated greater than 500 hp. 001-005 Section XVII.E. Engines are subject to emission standards unless NSPS JJJJ and MACT ZZZZ requirements ultimately are applicable. Is this source subject to the control requirements of MACT HH? (Regulation 8-Hazardous Air Pollutants review). No 006 Is this source subject to the exemptions under MACT HH (i.e. throughput exemption less than 3 MMSCFD or benzene exemption of less than 1984 Ib/yr)? No 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 006 This source is subject to Regulation 7, Section XII.H. Uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas-condensate-glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by at least 90 percent through the use of air pollution control equipment. Section XVII.D(State only enforceable). 006 Applicant is required to reduce VOC emissions from this dehydrator by at least 90% since uncontrolled VOC emissions are greater than the 15.0 TPY threshold. Section XII.G.1. 007 Applicant is located in NAA but since it is not a gas processing facility, the requirements are not applicable. 008, 009 None B69ulafion 8—Hazardous Air Pollutants 001-005 MACT ZZZZ: Area source requirements are not currently adopted in Colorado regulations. Listed in"Notes to permit holder." 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 summing up dehydrator and flash tank emissions? No 006 3.Is this facility considered MAJOR for HAPS? No 4.Is this source subject to MACT HH? No 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. 007 MACT HH: This facility is an area source of HAPs. No fugitive requirements for area sources. 008,009 None Section 13—Aerometric Information Retrieval System Coding Information Point Process Process Throughp Emission Pollutant/ Fugitive Emission Control Description ut limit Factor CAS# (YIN) Factor Source (%) 001- 4SRB 115.9 13.1 g/hp-hr NOx No Manufacturer 96.2 005 01 RICE MMscf/yr 11.7 glhp-hr CO No Manufacturer 53.3 Page 8 1.5 g/hp-hr VOC No Manufacturer 91.5 0.05 /h hr Formaldehyde/ No Manufacturer 76 g/hp-hr 50000 3.06 e-3 Methanol/ AP-42, Table lb/MMbtu 67561 No 3.2-3 50 2.79e-3 Acetaldehyde AP 42, Table lb/MMbtu /75070 No 3.2-3 50 2.63e-3 Acrolein/ AP-42, Table lb/MMbtu 107028 No 3.2-3 50 1.58-3 Benzene/ AP-42, Table lb/MMbtu 71432 No 3.2-3 50 6.63e-4 Butadiene/ No AP-42, Table 50 lb/MMbtu 106990 3.2-3 5.58 e-4 Toluene/ AP-42, Table lb/MMbtu 108883 No 3.2-3 50 SCC 20200253: 4-cycle rich burn 60.0187 VOC No GlyCalc 4.0 96.5 lbs/mmscf 7.5096 Benzene/ No GlyCalc 4.0 93.4 lbs/mmscf 71432 9.5244 Toluene/ 21, 01 Glycol MMSCF lbs/mmscf 108883 006 Dehydrator per year 0.4157 Ethylbenzene No GlyCalc 4.0 95.7 lbs/mmscf / 100414 4.7846 Xylenes/ No GlyCalc 4.0 95.9 lbs/mmscf 1330207 3.5886 n-Hexane/ No GlyCalc 4.0 96.4 lbs/mmscf 110543 SCC 31000227: Glycol Dehydrator reboiler still stack Fugitive 01 VOC NA NA VOC Yes EPA-453/R-95- NA 007 Equipment 017, Table 2-4 Leaks SCC 31000220: All Equip. Leak Fugitives(Valves, flanges, connections, seals, drains) 0.068 NOx No AP-42, Table NA lb/MMbtu 13.5-1 59.63 0.063 AP-42, Table NA 008 MMscf/yr lb/MMbtu 13.5-1 -- AP-42,Table lb/MMbtu CO No 13.5-1 NA SCC 31000205: Flares 13.7733 Engineering 01 Blowdowns lb/mscf VOC No Calculation NA 009 0.1750 n-hexane No Engineering NA Ib/mscf Calculation SCC 306004002—blowdown system w/o control Section 14—Miscellaneous Application Notes AIRS Point 001-005 Waukesha Engines, 1680 hp each A permit will be issued because the uncontrolled VOC emissions are greater than 5 TPY CO(permit threshold). The engines have not yet been ordered so exact dates are not yet known for establishing regulatory applicability. The engines will most likely be subject to area source requirements under MACT Z777 and NSPS JJJJ requirements. The application consisted of 5 engine APENS, but DCP will only be running 4 engines at a time(one APEN reflected 0 emissions on the APEN). Due to other work done similarly for other DCP compressor stations, a combined emission limit for all 5 engines will be in permit 13WE2169 as well as individual permit limits for each engine(when running)to help with compliance issues. Page 9 AIRS Point 006 TEG Dehydrator The Division received a revised application for this point source on 1/13/2014. DCP requested to increase the throughput from 50 mmscfd to 60 mmscfd(which increased the emissions as well). Also they changed the dehydrator reboiler from 2.86 mmbtu/hr to 1.5 mmbtu/hr. I revised the PA and permit to reflect the revised calculations. This emissions point covers emissions from one triethylene glycol(TEG)dehydrator that treats field gas prior to sending the gas on for additional processing at a gas plant. The TEG dehydrator will have a maximum capacity of 60 MMscfd based on the APEN. The pump specifications are not yet known but the requested glycol recirculation rate is 24.0 gallons per minute. The still vent will be routed to a condenser and then to an enclosed combustor. The flash tank emissions are routed back to the plant inlet via a vapor recovery unit(VRU). The reboiler is rated at 1.5 MMbtu/hr. In order to determine emissions,the operator used GRI GlyCALC 4.0. The source assumed an inlet gas temperature of 100°F and pressure of 900 psig and I confirmed these values were used in the GlyCALC report. The permitted glycol recirculation rate of 24.0 gallons per minute is also used in the GlyCALC report. Since the facility is a proposed, new facility, a site-specific gas analysis was not available for emission calculations. The source stated that they compiled various gas samples from the area which they felt to be representative of the gas for the facility. This method is appropriate for a new facility. An extended gas analysis will be required as part of the self-certification process to confirm emissions. Gly-Calc-Uncontrolled Emission factors from the revised application 1113/2014. New APEN did not include emission factors: VOC=((394.2791+262.9258)`2000)/(60*365)=60.0187 lb/mmscf Benzene=((79.3517+2.8783)`2000)/(60*365)=7.5096 lb/mmscf Toluene=((101.7927+2.4992)*2000)/(60`365)=9.5244 lb/mmscf Ethylbenzene=((4.4851+0.0668)`2000)/(60*365)=0.4157 lb/mmscf Xylenes=((51.8358+0.5559)*2000)/(60*365) =4.7846 lb/mmscf N-hexane=((20.9873+18.3078)`2000)/(60`365) =3.5886 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 83.761 are also needed to determine major source applicability: Production field facilities means those facilities located prior to the pant of custody transfer Custody transfer means the transfer of hydrocarbon liquids or natural gas: after processing and/or treatment in the producing operations, or from storage vessels or automatic transfer facilities or other such equipment, including product loading racks,to pipelines or any other forms of transportation. For the purposes of this subpart, the point at which such liquids or natural gas enters a natural gas processing plant is a point of custody transfer. Natural gas processing plant(gas plant)means any processing site engaged in the extraction of natural gas liquids from field gas, or the fractionation of mixed NGL to natural gas products, or a combination of both. Based on the definitions above,this source qualifies as a production field facility since it is prior to entering a natural gas processing plant. For a production field facility, only HAP emissions from dehys and storage tanks with flash emissions are included for determining major source status. The facility's storage tanks are pressurized bullet tanks and there is only one dehy. Using the requested throughput limit of 60 MMscfd and glycol recirculation rate of 24 gpm, uncontrolled VOC emissions from the dehy are 657.2 tpy VOC, uncontrolled total HAP emissions are 282.8 tpy, and uncontrolled toluene emissions are 104.3 tpy. Controlled total HAP emissions from the dehy are 14.7 tpy and controlled toluene emissions are 5.8 tpy. Controlled emissions are based on 100% of flash tank emissions being recycled and 95%control of still vent emissions. The facility is an area source for MACT HH. As specified in 63.760(b)(2),the only affected sources for area sources are TEG dehydrators. Page 10 AIRS Point 006 TEG Dehydrator(continued) The source cannot meet the processing exemption limit in 63.764(e)(i) because the proposed process limit is 60 MMscfd which exceeds the exemption limit of 3.00 MMscfd. The source cannot meet the benzene exemption limit of 1,984 lb/yr in 63.764(e)(ii) because controlled benzene emissions are estimated at 10,333 lb/yr. Based on the location information provided in the application,the source is not within an UA Plus Offset and not within 2 miles of a UC boundary. Thus, it is eligible to follow Lopt. The dehydrator is controlled by an enclosed combustor. Regulation 7 control requirements will not be included in the permit since it meets the more stringent rules of MACT HH. The unit is equipped a reboiler rated at 1.5 MMbtu/hr. Since the reboiler burner has a design rate less than 5 mmbtu/hr,then it is APEN-exempt(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). AIRS Point 007 Fugitive Emissions from Equipment Leaks A permit will be issued because the uncontrolled VOC emissions are greater than 5 TPY(permit threshold). 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. AIRS Point 008 Enclosed combustor 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). Operator requested a throughput change to this source during the application review process. The Division received updated APEN and calculations on 1/13/2014. I redlined the original APEN to save some time in the review process. The operator provided the revised throughput in MMBtu/yr, but I believe that inventory prefers it in mmscf/yr. I emailed the operator to see if I can put 59.63 mmscf/yr on the APEN as the throughput AIRS Point 009 Pigging/Receiving Blowdowns 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). Operator requested a new point source during the application review process. The Division received an APEN and calculations on 1/13/2014. 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, 388 MSCF/yr for the 16" launcher and 218 MSCF/yr for the 12"launcher, totaling 697 MSCF/year. Emission factors are calculated as follows: VOC=4.8*2000/697= 13.7733 Ib/blowdown event n-hexane= 122/697=0.1750 Ib/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 included in the history file to understand total facility emissions but otherwise not reviewed as part of this permit action. The facility's insignificant activities include one 1.5 MMBtu/hr dehy reboiler,two 30,000 gallon pressurized condensate storage tanks, pressurized condensate • loadout, compressor blowdowns, two 100 bbl wastewater tanks, one 1000 gallon methanol tank, 200 gallon lube oil tank, 1000 gallon glycol tanks and 80 bbl drain tank. Facility Wide Comments • • DCP is proposing to construct and operate a natural gas compression facility with a capacity of 60 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 synthetic 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 11 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 3/14/13 that no DCP compressor stations are currently located,or will be located,within a quarter mile of the 70 Ranch compressor station. DCP also stated that no DCP compressor stations or gas plants that are greater than a quarter mile from the 70 Ranch compressor station will be wholly dependent with 70 Ranch.The closest DCP facility to the proposed 70 Ranch compressor station is the Eaton Gas Plant which is approximately 4.75 miles away. There is no dedicated relationship between the proposed 70 Ranch compressor station and the Eaton Gas Plant;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 70 Ranch 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 70 Ranch 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 70 Ranch compressor station. Therefore, we requested information from DCP to ascertain if there are any DCP facilities that would be considered adjacent to the 70 Ranch 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 70 Ranch 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 70 Ranch compressor station to be considered adjacent. For example, the closest DCP facility to the proposed 70 Ranch compressor station is the Wells Ranch Compressor Station which is approximately 5.4 miles away. There is no dedicated relationship between the proposed 70 Ranch 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 70 Ranch Compressor Station is appropriate. Accordingly, the stationary source determination of the 70 Ranch 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. 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