The URL can be used to link to this page

Browse Search

Home My WebLink About20130096.tiffSTATE OF COLORADO John W. Hickenlooper, Governor Christopher E. Urbina, MD, MPH Executive Director and Chief Medical Officer Dedicated to protecting and improving the health and environment of the people of Colorado 4300 Cherry Creek Dr, S. Denver, Colorado 80246-1530 Phone (303) 692-2000 Located in Glendale, Colorado http://www.cdphastate.co.us January 2, 2013 Mr. Steve Moreno Weld County Clerk 1402 N. 17th Ave. Greeley, CO 80631 Dear Mr. Moreno: Laboratory Services Division 8100 Lowry Blvd. Denver, Colorado 80230-6928 (303) 692-3090 Colorado Department of Public Health and Environment RECEIVED JAN p 7..2(113 WELD COUNTY COMMISSIONERS The Air Pollution Control Division will publish a public notice for DCP Midstream, LP. This public notice will be published in the Greeley Tribune on January 6, 2013. Thank you for assisting the Division by making the enclosed package (includes public notice, preliminary analysis, Air Pollutant Emission Notice(s) and draft permit(s)) available for public review and comment. It must be available for public inspection for a period of thirty (30) days from the date the public notice is published. Please forward any comment regarding this public notice to the address below. Colorado Department of Public Health and Environment APCD-SS-B 1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Attention: Ellen Evans Regards, Ellen Evans Public Notice Coordinator Stationary Sources Program Air Pollution Control Divisipn LLOCAC. QU't2td C . rl��t\L7 t9D - NCI Le STATE OF COLORADO John W. Hickenlooper, Governor Christopher E. Urbina, MD, MPH Executive Director and Chief Medical Officer Dedicated to protecting and improving the health and environment of the people of Colorado 4300 Cherry Creek Dr. S. Denver, Colorado 80246-1530 Phone (303) 692-2000 Located in Glendale, Colorado http://www.cdphe.state.co.us Laboratory Services Division 8100 Lowry Blvd. Denver, Colorado 80230-6928 (303) 692-3090 Colorado Department of Public Health and Environment Website Title: DCP Midstream, LP — Wells Ranch Compressor Station — Weld County Released to: The Greeley Tribune on January 2, 2013; published January 6, 2013 PUBLIC NOTICE OF A PROPOSED PROJECT OR ACTIVITY WARRANTING PUBLIC COMMENT The Colorado Air Pollution Control Division declares the following proposed construction activity warrants public comment. Therefore, the Air Pollution Control Division of the Colorado Department of Public Health and Environment hereby gives NOTICE, pursuant to Section 25-7- 114.5(5), C.R.S. of the Colorado Air Quality Control Act that the Division received an application for an air pollution emission permit on the following proposed project and activity: DCP Midstream, LP proposes to construct and operate a natural gas compression facility known as the Wells Ranch Compressor Station located at Section 27, Township 6N, and Range 63W in Weld County. The company has submitted an application requesting issuance of a federally enforceable synthetic minor source permit limiting the potential to emit. As a synthetic minor source the permit is subject to public comment per Regulation 3, Part B, Section 111,C.1. The Division hereby solicits and requests submission of public comment from any interested person concerning the aforesaid proposed project and activities to comply with the applicable standards and regulations of the Commission for a period of thirty (30) days from the date of this publication. Any such comment must be submitted in writing to the following addressee: Oluwaseun Ogungbenle Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South, APCD-SS-B I Denver, Colorado 80246-1530 Within thirty (30) days following the said thirty (30) -day- period for public comment, the Division shall consider comments and, pursuant to Section 25-7-1 14.5(7)(a), either grant, deny, or grant with conditions, the emission permits. Said public comment is solicited to enable consideration of approval of and objections to the proposed construction of the subject project and activity by affected persons. A copy of the applications for the emission permits, the preliminary analysis of said applications, and accompanying data concerning the proposed project and activity are available for inspection at the office of the Clerk and Recorder of Weld County during regular business hours and at the office of the Air Pollution Control Division, Colorado Department of Public Health and Environment, 4300 Cherry Creek Drive South, Denver, Colorado. A copy of the draft permit and preliminary analysis are available on the Air Pollution Control Division's website at: http://www.colorado.gov/cs/Satellite/CDPHE-AP/CBON/125 1596498449 Construction Permit Application Preliminary Analysis Summary Section 1 — Applicant Information Company Name: DCP Midstream, LP Permit Number: 12WE2039 Source Name: Wells Ranch Compressor Station Source Location: NWNW Section 27, T6N, R63W Equipment Description: Point 001 - One (1) Reciprocating Internal Combustion Engine for Natural gas compression Point 002 - One (1) Reciprocating Internal Combustion Engine for Natural gas compression Point 003 - One (1) Reciprocating Internal Combustion Engine for Natural gas compression Point 004 - One (1) Reciprocating Internal Combustion Engine for Natural gas compression Point 005 - One (1) 50 MMSCFD TEG Dehydrator Point 006 - Fugitive emissions from valves, flanges, connectors, and other components Point 007 - One (1) Reciprocating Internal Combustion Engine for Natural gas compression AIRS ID: 123/9950/001-007 Date: August 31, 2012 Review Engineer: Oluwaseun Ogungbenle 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 Information Request letter to the source? On what date was this application complete? November 16, 2012 Section 4 —Source Description AIRS Point Equipment Description Page 1 001 One (1) Waukesha, Model L7044GSI, Serial Number TBD, natural gas -fired, turbo- charged, 4SRB reciprocating internal combustion engine, site rated at 1680 horsepower at 1200 RPM. This engine shall be equipped with a non -selective catalytic reduction (NSCR) system and air -fuel ratio control (AFRO). This emission unit will be used for natural gas compression. 002 One (1) Waukesha, Model L7044GSI, Serial Number TBD, natural gas -fired, turbo- charged, 4SRB reciprocating internal combustion engine, site rated at 1680 horsepower at 1200 RPM. This engine shall be equipped with a non -selective catalytic reduction (NSCR) system and air -fuel ratio control (AFRO). This emission unit will be used for natural gas compression. 003 One (1) Waukesha, Model L7044GSI, Serial Number TBD, natural gas -fired, turbo- charged, 4SRB reciprocating internal combustion engine, site rated at 1680 horsepower at 1200 RPM. This engine shall be equipped with a non -selective catalytic reduction (NSCR) system and air -fuel ratio control (AFRO). This emission unit will be used for natural gas compression. 004 One (1) Waukesha, Model L7044GSI, Serial Number TBD, natural gas -fired, turbo- charged, 4SRB reciprocating internal combustion engine, site rated at 1680 horsepower at 1200 RPM. This engine shall be equipped with a non -selective catalytic reduction (NSCR) system and air -fuel ratio control (AFRO). This emission unit will be used for natural gas compression. 005 One (1) Triethylene glycol (TEG) natural gas dehydration unit (make, model, serial number: not submitted) with a design capacity of 50 MMscf per day. This emissions unit is equipped with two (2) electric pumps (make, model: not submitted) with a design capacity of 24 gallons per minute. One of the pumps will serve as a backup. This unit is equipped with a flash tank, reboiler and still vent. There is no stripping gas. Emissions from the still vent will be routed through a BTEX condenser to an enclosed combustor (make, model, serial no: TBD). Emissions from the flash tank will be routed to a vapor recovery unit (VRU) which then returns vapors back to the inlet of the compressor station. 006 Equipment leaks (fugitive VOC emissions) from valves, flanges, connectors, and other components. 007 One (1) Waukesha, Model L7044GSI, Serial Number TBD, natural gas -fired, turbo- charged, 4SRB reciprocating internal 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 (AFRO). This emission unit will be used for natural gas compression. This engine will function as a backup to the four main engines (points 001-004). All five engines will be permitted, but only four engines will be running at any given time. Is this a portable source? Yes X No Is this location in a non -attainment area for any criteria pollutant? X Yes No If "yes", for what pollutant? PM10 CO X Ozone Is this location in an attainment maintenance area for any criteria pollutant? Yes X No If "yes", for what pollutant? (Note: These pollutants are subject to minor source RACT per Regulation 3, Part B, Section III.D.2) PM10 CO Ozone Is this source located in the 8 -hour ozone non - attainment region? (Note: If "yes" the provisions of Regulation 7, Sections XII and XVII.C may apply) X Yes No Section 5 — Emission Estimate Information AIRS Point Emission Factor Source Page 2 001 Manufacturer's specifications/ AP -42 002 Manufacturer's specifications/ AP -42 003 Manufacturer's specifications/ AP -42 004 Manufacturer's specifications/ AP -42 005 GRI Gly-Calc v4.0 (Refer to Section 14 for calculations) 006 EPA -453/R-95-017, Table 2-4 007 Manufacturer's specifications/ AP -42 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 001-004, 007 115.9 MMscf per year; 7876 Btu/HP-hr; 1680 hp; 1000 Btu/scf (for each engine) 005 18,250 MMSCF per year, 24 gallons per minute glycol circulation rate 006 Equipment Type Gas Heavy Oil (or Heavy Liquid) Light Oil (or Light Liquid) Water/Oil Connectors 1422 ---- 217 ---- Flanges 231 ---- 89 -___ Open -Ended Lines 51 ---- 8 Pump Seals 0 ---- 2 Valves 306 ---- 72 ---- Other 31 ---- 4 --- 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 001-004, 007 115.9 MMscf per year; 7876 Btu/HP-hr; 1680 hp; 1000 Btu/scf (for each of the four main engines) 005 18,250 MMSCF per year, 24 gallons per minute glycol circulation rate 006 Equipment Type Gas Heavy Oil (or Heavy Liquid) Light Oil (or Light Liquid) Water/Oil Connectors 1422 ---- 217 ---- Flanges 231 ---- 89 ___- Open -Ended Lines 51 ---- 8 Pump Seals 0 ---- 2 ---- Valves 306 ---- 72 Other 31 ---- 4 ---- Does this source use a control device? X Yes No AIRS Point Process Control Device Description Pollutant % Reduction Granted 001- 004, 007 01 NSCR and Air -Fuel ratio controller NOx 96.2% VOC 53.3% CO 91.5% HCHO 76% Other HAPs 50% Page 3 005 01 VRU for flash tank; condenser and enclosed combustor for Still Vent VOC Benzene Toluene Ethylbenzene Xylenes n -Hexane 97.3% 94.8% 95.5% 96.7% 96.9% 97.0% 006 01 None NA Section 6 — Emission Summary (tons per year) Point TSP NO, VOC CO Single HAP Total HAP Facility PTE Before Emissions Controls/Limits: 001 4.4 850.0 97.2 759.2 3.24 (Formaldehyde) 5.8 002 003 004 007 005A --- 0.6 645.4 3.0 12 (T9o9 ene) 270.3 006B - --- 8.0 0.3 (n -Hexane) 0.3 Total° 4.6 851.2 744.7 763.3 99.12 (Toluene) 276.1 Point TSP NO, VOC CO Single HAP Total HAP Controlled point source emission rate: 001 4.4 32.4 45.6 64.8 0.8 (Formaldehyde) 2.0 002 003 004 007 005A --- 0.6 17.7 3.0 4.43 (Toluene) 11.3 0068 8.0 0.3 (n-Hexane)4.4 0.3 Totalc 4.5 34.1 65.4 71.9 (Toluene) 13.3 Total permitted plant -wide emissions : 33.0 71.3 67.8 4.4 (Toluene) 13.6 A: NOx and CO emissions are from the Internal Combustor that is used to control the Dehy unit. B: These emissions are fugitive sources so they are not included in the total for PTE. C: The total PTE values in this line also include emissions for insignificant activities. The facility's insignificant activities include one 2.86 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. D: These emissions do not include insignificant activities but do include fugitives that qualify as permitted emission sources. Page 4 Section 7 — Non -Criteria / Hazardous Air Pollutants AIRS ID Pollutant CAS # BIN Uncontrolled Emission Rate (Ib/yr) Are the emissions reportable? Controlled Emission Rate (lb/yr) Formaldehyde 5000 A 1622 Yes 389 Methanol 67561 C 355 No 177 Acetaldehyde 75070 A 323 Yes 162 001 Acrolein 107028 A 305 Yes 152 Benzene 71432 A 183 Yes 92 1,3 -Butadiene 106990 A 77 Yes 38 Toluene 108883 C 65 No 32 002 Formaldehyde 5000 A 1622 Yes 389 Methanol 67561 C 355 No 177 Acetaldehyde 75070 A 323 Yes 162 Acrolein 107028 A 305 Yes 152 Benzene 71432 A 183 Yes 92 1,3 -Butadiene 106990 A 77 Yes 38 Toluene 108883 C 65 No 32 003 Formaldehyde 5000 A 1622 Yes 389 Methanol 67561 C 355 No 177 Acetaldehyde 75070 A 323 Yes 162 Acrolein 107028 A 305 Yes 152 Benzene 71432 A 183 Yes 92 1,3 -Butadiene 106990 A 77 Yes 38 Toluene 108883 C 65 No 32 004 Formaldehyde 5000 A 1622 Yes 389 Methanol 67561 C 355 No 177 Acetaldehyde 75070 A 323 Yes 162 Acrolein 107028 A 305 Yes 152 Benzene 71432 A 183 Yes 92 1,3 -Butadiene 106990 A 77 Yes 38 Toluene 108883 C 65 No 32 005 Benzene 71432 A 158,086 Yes 8,181 Toluene 108883 C 198,245 Yes 8,863 Ethylbenzene 100414 C 8,569 Yes 276 Xylenes 1330207 C 96,868 Yes 2,977 n -Hexane 110543 C 78,800 Yes 2,374 006 Benzene 71432 A 33 No NA Toluene 108883 C 33 No NA Page 5 Xylenes 1330207 C 9 No NA n -Hexane 110543 C 568 No NA 007 HAPs n/a n/a 0 n/a 0 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 standard? X Yes No If "yes", complete the information listed below AIRS Point Process Pollutant Regulatory Basis Test Method 001-004, 007 01 NOx, CO, VOC, HAPS Regulation No. 3, Part B., Section III.G.3 Stack Test Section 9 - Source Classification Is this a new previously un-permitted source? X Yes No What is this point classification'? True Minor X Synthetic Minor Major What is this facility classification? True Minor X Synthetic Minor Major 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 Minor Major This point refers to the combination of all points covered under this permit. Actually, with the exception of point 006, each of the points covered under this permit is by itself a Synthetic Minor source. 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 and, HAP 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 Air Quality Standards (NAAQS)? If"yes", for which pollutants? Why? Yes X No Controlled NOx emissions < 40 tpy. Controlled CO emissions < 100 tpy. AIRS Point Section 12 - Regulatory Review Requlation 1 -Particulate Smoke Carbon Monoxide and Sulfur Dioxide Section II.A.1 - Except as provided in paragraphs 2 through 6 below, no owner or operator of a source shall allow or cause the emission into the atmosphere of any air pollutant which is in excess of 20% opacity. This standard is based on 24 consecutive opacity readings taken at 15 -second intervals for six minutes. The approved reference test method for visible emissions measurement is EPA Method 9 (40 CFR, Part 60, Appendix A (July, 1992)) in all subsections of Section II. A and B of this regulation. Requlation 2 — Odor Page 6 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 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, Operatin• Permits PSD Part A-APEN Requirements Applicant is required to file an APEN since emissions exceed applicable thresholds. Part B — Construction Permit Exemptions Applicant is required to obtain a permit since emissions exceed applicable thresholds. (Reg. 3, Part B, Section Il.D.2) Regulation 6 - New Source Performance Standards 001-004, 007 NSPS JJJ: All four engines are subject to this subpart; however, NSPS JJJJ is not currently adopted in Colorado regulations. Applicable NSPS JJJJ requirements are listed in the "Notes to permit holder" section of the permit. Regulation 7 — Volatile Organic Compounds 001-004, 007 Section XVI.B Applicant is located in a non -attainment area and thus required to install NSCR on rich burn engine rated greater than 500 hp. Section XVII.E. Engines are subject to emission standards unless NSPS JJJJ and MACT ZZZZ requirements ultimately are applicable. 005 Section XII.H. This source is located in a non -attainment area and uncontrolled VOC emissions are greater than the 15.0 TPY threshold. Therefore, the dehydration unit at this source is subject to requirements under Section XII.H. Section XVII.D (State only enforceable). 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. 006 Section XII.G.1. Source is located in a non -attainment area, but since it is not a gas processing facility, the requirements of this subpart are not applicable. Regulation 8 — Hazardous Air Pollutants 001-004, 007 MACT 7777: All four engines are subject to this subpart; however, MACT ZZZZ is not currently adopted in Colorado regulations. Applicable MACT ZZZZ requirements are listed in the "Notes to permit holder" section of the permit. 005 MACT HH: 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 a UA plus offset or UC boundary; it will only be required to comply with the optimal circulation rate standard in this subpart. 006 MACT HH: This facility is an area source of HAPs. No fugitive requirements for area sources. Section 13 — Aerometric Information Retrieval System Coding Information Point Process Process Description Throughput limit Emission Factor Pollutant / CAS # Fugitive (YIN) Emission Factor Source Control (°/0) *See separate table for AIRS Coding for Points 001 through 004. 005 01 Glycol Dehydrator 18,250 MMSCF per year 70.72 lbs/MMscf V0C No GLYCalc 4.0 97.3 8.66 lbs/MMscf Benzene / 71432 No GLYCalc 4.0 94.8 10.86 lbs/MMscf Toluene / 108883 No GLYCalc 4.0 95.5 0.47 lbs/MMscf Ethylbenzene / 100414 No GLYCalc 4.0 96.7 Page 7 5.31 Ibs/MMscf Xylenes / 1330207 No GLYCalc 4.0 96.9 4.32 lbs/MMscf n -Hexane / 110543 No GLYCalc 4.0 97.0 SCC 31000227: Glycol Dehydrator: reboiler still stack 006 01 Fugitive VOC Equipment Leaks NA NA VOC Yes EPA -453/R-95- 017, Table 2-4 NA Section 14 — Miscellaneous Application Notes AIRS Point 00007 4 Waukesha Engines, 1680 hp each The engine at point 007 will function as a backup to the four main engines (points 001-004). All five engines will be permitted, but only four engines will be running at any given time. Therefore, the fuel usage for this engine will be represented as 0 MMSCF/yr at 0 hr/yr and the combined total annual run time will be 35, 040 hrs/yr (4 engines x 8760 hrs/yr). These 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 ZZZZ and NSPS JJJJ requirements. Page 8 AIRS Point 005 This emission 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 50 MMscfd based on the APEN. The pump specifications are not yet known but the requested glycol recirculation rate is 24.0 gallons per minute. Prior to the correspondence I had with Wes Hill on 10/09/2012, the unit was designed such that the still vent emissions would be routed to a condenser and then to the reboiler firebox. The flash tank emissions are routed back to the plant inlet via a vapor recovery unit (VRU). The reboiler is rated at 2.86 MMBtu/hr. Following the correspondence with Wes, DCP is making a minor modification to the Dehy unit. With this modification, still vent emissions will now be routed via a condenser to an enclosed combustor. DCP considered using the enclosed combustor as a backup to the VRU that will be used to control emissions from the flash tank; however, per my discussion with Carissa, I let them know that they would not be able to achieve 100% control of their flash tank emissions with this proposed control system. Wes emailed me back saying "I just spoke with my engineers and they agree they would rather use a second VRU as a backup for recycling the TEG flash gas, so we will go with our original design using 100% control for the flash gas stream."The control efficiency achieved with the enclosed combustor will remain 95%. In order to determine emissions, the operator used GRI GLYCalc 4.0. The source assumed an inlet gas temperature of 125°F and pressure of 920 psig. The permitted glycol recirculation rate of 24.0 gallons per minute is also used in the GLYCalc report and I confirmed these values were 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. In reviewing the GLYCalc report, I noted that the "wet gas water content" was marked as sub -saturated for the simulation which is not typical. I noticed a discrepancy between the controlled emissions shown on the GLYCalc report and those reported on the APEN. I brought this to the attention of Wes Hill, and he verified that the preparers of the application had inadvertently included an old GLYCalc run with the original Wells Ranch application. He attached the correct GLYCalc run report in his clarification email. One difference between this GLYCalc run and the GLYCalc runs from other similar (almost identical) DCP compressor station permit applications is that DCP is taking credit for the condenser. This is why the VOC & HAP emissions for the Wells Ranch compressor station dehy unit are lower than other facilities'. DCP also added a 20% buffer to the controlled emissions from the GLYCalc results to allow for any potential changes to the gas analysis (see the calculation sheet provided). Emission factors listed in Section 13 of this analysis are based on the sum of flash tank and still vent emissions from the GLYCalc report. TEG Dehydrator 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 notproduction field facilities, HAP emissions from all HAP emission units shall be aggregated for a major source determination. The following definitions from 63.761 are also needed to determine major source applicability: Production field facilities means those facilities located prior to the point of custody transfer Custody transfer means the transfer of hydrocarbon liquids or natural gas: after processing and/or treatment in the producing operations, or from storage vessels or automatic transfer facilities or other such equipment, including product loading racks, to pipelines or any other forms of transportation. For the purposes of this subpart, the point at which such liquids or natural gas enters a natural gas processing plant is a point of custody transfer. Natural gas processing plant (gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, or the fractionation of mixed NGL to natural gas products, or a combination of both. Page 9 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. Based on HAP emissions reported in Section 7, this facility is an area source for MACT HH. Controlled emissions are based on 100% of flash tank emissions being recycled, 95% control of still vent emissions, and the use of a condenser. As specified in 63.760(b)(2), the only affected sources for area sources are TEG dehydrators. The source cannot meet the processing exemption limit in 63.764(e)(i) because the proposed process limit is 50 MMscfd which exceeds the exemption limit of 3.002 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 6,107 lb/yr. The source will be located outside of an "UA Plus Offset or within a UC boundary." Thus, as an area source outside of a UC boundary, it is subject to the optimal circulation rate work practice standard in 63.764(d)(2). These requirements will be listed in the permit. Regulation 7, Section XVII.D requires emission control standards for dehydrators with uncontrolled emissions of VOC greater than 15 tons per year from all the dehydrators on site. As discussed above, uncontrolled VOC emissions are 534.3 tpy. Section XVII.B.4 states that dehydrators subject to an emission control requirement in a federal MACT standard are not subject to requirements under Section XVII. This dehy is subject to a work practice standard under MACT HH, not an emission control requirement; thus, the dehy is still subject to the requirements of Section XVII.D. Further, since the source will be located in a non -attainment area, the dehy is also subject to the requirements of Regulation 7, Section XII.H. The unit is equipped with a reboiler rated at 2.86 MMBtu/hr. This reboiler burner is APEN-exempt since it has a design rate less than 5 MMBtu/hr (Regulation No. 3, Part A, II.D.1.k); the reboiler is, therefore, also exempt from construction permitting requirements (Regulation no. 3, Part B, II.D.1.a). On November 16, 2012, DCP submitted revised calculations as well as corresponding documentation for the TEG Dehydration Unit. For the initial submittal, emissions from the Dehy unit were calculated based on a maximum condenser outlet temperature of 120 °F. The Division allows operators a maximum condenser outlet temperature of 160 °F if they are claiming control efficiency for the condenser. DCP is claiming control efficiency for their condenser. Therefore, DCP elected to revise their Dehy emissions calculations by running GLYCalc at 160 °F condenser outlet temperature. The condenser outlet temperature shall not exceed 160 °F on a monthly average basis. As expected this increase in condenser outlet temperature resulted in a corresponding increase in VOC and HAP emissions. DCP also added a 20% buffer to their controlled emissions in order to account for possible changes in inlet gas composition. With this most recent submittal, DCP also submitted an APEN for the enclosed combustor that is used to control the still vent stream after the stream has passed through the condenser. NOx and CO emissions from the combustor are above APEN threshold; therefore, they will be permitted because they will be aggregated with the NOx and CO emissions from other permitted sources at the Wells Ranch Compressor Station. Emissions from the combustor will be attributed to the Dehy unit since the combustor is part of the Dehy unit, and is not a stand-alone emissions point. Page 10 AIRS Point 006 Fugitive Emissions from Equipment Leaks In her preliminary analysis of a permit application for the Bernhardt Compressor Station, a facility that is almost identical to Wells Ranch, Carissa Money notes: "In the March 2011 application, DCP stated that the Bernhardt compressor station will include a fuel gas conditioning skid that extracts natural gas liquids. DCP stated that since condensate is extracted in the fuel gas conditioning skid, the site qualifies as an onshore natural gas processing plant per 60.631 for NSPS KKK applicability. DCP provided additional information regarding the fuel gas conditioning skid in a letter dated August 5, 2011. The letter provided additional information regarding the operation of the fuel gas conditioning skid and ultimately clarified that the compressor station should not qualify as a natural gas processing plant per NSPS KKK. DCP clarified that the purpose of the fuel gas conditioning skid is to treat or condition a small volume of field gas to remove impurities and ensure proper heat content so that the field gas can be used for combustion in the compressor engines at the station. More specifically, a slip stream of the residue gas (at the outlet of the dehydrator) is routed to the fuel gas conditioning skid. The first step in the skid is a. pressure reduction station, which is followed by a coalescing filter that further collects condensed liquids and/or liquid carry-over from the TEG dehydrator system. After the residue gas passes through the coalescing filter to drop out any liquids, the next step is a permeable membrane that separates the fuel gas into a residue stream (gas that is lower thah C4) and a permeate stream (gas that is higher than C4). The permeate stream is recycled back to the plant inlet and the residue stream is directed to the compressor engines as fuel. Any liquids collected from the fuel gas conditioning skid are routed to the facility's condensate separator which separates the water and condensate. Condensate is then sent to condensate storage tanks and water is sent to a water storage tank. These tanks are used for collecting all liquids from the site and are not dedicated storage tanks for the fuel gas conditioning skid. The fuel gas conditioning skid will only process the amount of gas needed to operate the natural gas fired equipment (i.e., compressor engines) at the facility. EPA Region 8 clarified in a memo dated 4/7/2009 that certain compression facilities can qualify as natural gas processing plants per the definition in 60.631 and then are subject to NSPS KKK requirements. In the 2009 memo, EPA clarified that compression facilities that extract hydrocarbon liquids, including condensate, by force from field gas qualify as a natural gas processing plant. It is important to note that the April 2009 memo focuses on the purpose of the processing facility and is intended to address compression facilities that are implementing dew point control to achieve pipeline specifications. The Bernhardt station will compress gas, dehydrate it and then send gas on for further processing at a gas plant. While ultimately the same thermodynamic principles are being used in the fuel gas conditioning skid, the intent of the facility is not to use dew point or JT skids to remove natural gas liquids from field gas to meet pipeline specifications. The fuel gas conditioning skid simply enables the site to use a small volume of field gas for on -site compression. The gas routed through Bernhardt compressor station must still be processed at a gas processing plant before entry into a natural gas transmission line. The Division has determined that the Bernhardt compressor station does not meet the definition of natural gas processing plant per 60.631. Thus, the facility is notsubject to NSPS KKK. This facility will be subject to minor source RACT requirements per Regulation 3, Part B, Il.D.2. a. Since this facility will be located in the nonattainment area for ozone, the source is required to apply RACT for the pollutants for which the area is in nonattainment (i.e., NOx and VOC). The source did not include a RACT analysis for fugitives and, in subsequent communications, stated that the fugitives are not subject to RA CT since there are no applicable requirements under Regulation 7 for fugitives at compressor stations. The Division disagrees with this interpretation. Minor source RACT under Regulation 3 Part B does not direct a source to Regulation 7. The source must develop a RACT analysis to evaluate whether RACT has been applied to each emission unit emitting the pollutant for which the area is in nonattainment. The source provided a RACT analysis on 8/17/2011 and proposed weekly audio, visual and olfactory (AVO) inspections as RACT. To satisfy RACT, the facility must also include periodic screening using either IR camera or Method 21. I proposed this option on 8/23/2011. The source submitted a revised O&M plan on 8/29/2011 that included periodic screening using IR camera. A • condition for monitoring equipment in VOC service semi-annually using IR camera will be included in the permit." Since the Wells Ranch Compressor station is "a mirror image" of the Bernhardt compressor station, the conditions above will be applicable to it. Page 11 Insignificant Activities The source provided emission estimates for several insignificant sources at the facility. Since APENs were not submitted for these insignificant sources, emissions and regulatory applicability were not evaluated for these points/activities. Total emissions from these sources is included in the history file to understand total facility emissions but otherwise not reviewed as part of this permit action. Facility Wide Comments DCP is proposing to construct and operate a natural gas compression facility with a capacity of 50 MMscfd. This stationary source will be located in a portion of 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 the Title V Operating Permit program. DCP supplied a greenhouse gas inventory with the application and stated that the CO2e potential to emit from the Wells Ranch Compressor Station will be less than 100,000 tpy. DCP will comply with the requirements of NSPS Subpart OOOO when they become applicable. On 10/11/2012, per correspondence with Wes Hill, the equipment IDs for the engines were changed from C-1, C-2, C-3 and C-4 to C-193, C-194, C-195, and C-196, respectively. On 10/22/2012, Wes Hill, on behalf of DCP, submitted the following request: "Per our discussion, my Engineers wanted to know if we could add a fifth Waukesha 7044 as a backup engine to the draft Wells Ranch. This would require permitting all 5 engines together and only running 4 engines at any given time. We would need to combine the emission limits as one source and permit them to run a combined 35,040 hours/yr (4 engines x 8760 hrs). The APEN on the 5`" engine would be listed as a backup operating 0 hours/yr. We have permitted backup engines for other facilities like the 5 CATs at the Mewbourn Plant (see attached Permit 09WE1136, AIRS ID 123/0090, Points 113-117). This allows us the flexibility to use a backup when one of the main engines goes down. I'd appreciate it if you could check and see if this change could be done during the current draft permitting action. I discussed this request with Chris and Carissa about, and they okayed it. Subsequently, Wes submitted an APEN for this backup engine. Therefore, five engines will now be covered under this facility wide permit instead of the four for which applications were initially submitted in the original package. Thursday, October 25, 2012 was Wes Hill's last day with DCP. Brian Taylor took over from him on Monday, October 29, 2012. Brian has been the contact person for this project since he took over from Wes. Page 12 STATE OF COLORADO COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT AIR POLLUTION CONTROL DIVISION TELEPHONE: (303) 692-3150 PERMIT NO: DATE ISSUED: ISSUED TO: 12WE2039 DCP Midstream, LP CONSTRUCTION PERMIT Issuance 1 THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS: Natural gas compression facility, known as the Wells Ranch Compressor Station, located in Section 27, Township 6N, Range 63W, in Weld County, Colorado. THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING: Facility Equipment ID AIRS Point Description C-193 001 One (1) Waukesha, Model L7044GS1, Serial Number TBD, natural gas -fired, turbo -charged, 4SRB reciprocating internal 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 will be used for natural gas compression C-194 002 One (1) Waukesha, Model L7044GS1, Serial Number TBD, natural gas -fired, turbo -charged, 4SRB reciprocating internal 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 will be used for natural gas compression. C-195 003 One (1) Waukesha, Model L7044GS1, Serial Number TBD, natural gas -fired, turbo -charged, 4SRB reciprocating internal 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 will be used for natural gas compression. AIRS ID: 123/9950 Page 1 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division Facility Equipment ID AIRS Point Description C-196 004 One (1) Waukesha, Model L7044GS1, Serial Number TBD, natural gas -fired, turbo -charged, 4SRB reciprocating internal 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 will be used for natural gas compression. D-1 005 One (1) Triethylene glycol (TEG) natural gas dehydration unit (make, model, serial number: not submitted) with a design capacity of 50 MMscf per day. This emissions unit is equipped with two (2) electric pumps (make, model: not submitted) with a design capacity of 24 gallons per minute. One of the pumps will serve as a backup. This unit is equipped with a flash tank, reboiler and still vent. There is no stripping gas. Emissions from the still vent will be routed through a BTEX condenser to an enclosed combustor (make, model, serial no: TBD). Emissions from the flash tank will be routed to a vapor recovery unit (VRU) which then returns vapors back to the inlet of the compressor station. FUG 006 Equipment leaks (fugitive VOCs) from a natural gas compression facility. C-197 007 One (1) Waukesha, Model L7044GS1, Serial Number TBD, natural gas -fired, turbo -charged, 4SRB reciprocating internal 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 will be used for natural gas compression. This engine will function as a backup to the four main engines (points 001-004). All five engines will be permitted, but only four engines will be running at any given time. The engines addressed under AIRS Points 001, 002, 003, 004, and 007 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: 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 AIRS ID: 123/9950 Page 2 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 of Public Health and Environment Air Pollution Control Division APCD. The Notice of Startup (NOS) form may be downloaded online at www.cdphe.state.co.us/ap/downloadforms.html. Failure to notify the APCD of startup of the permitted source is a violation of AQCC Regulation No. 3, Part B, Section III.G.1 and can result in the revocation of the permit. 2. Within one hundred and eighty days (180) after commencement of operation, compliance with the conditions contained on this permit shall be demonstrated to the Division. It is the permittee's responsibility to self -certify compliance with the conditions. Failure to demonstrate compliance within 180 days may result in revocation of the permit. (Reference: Regulation No. 3, Part B, III.G.2). 3. This permit shall expire if the owner or operator of the source for which this permit was issued: (i) does not commence construction/modification or operation of this source within 18 months after either, the date of issuance of this construction permit or the date on which such construction or activity was scheduled to commence as set forth in the permit application associated with this permit; (ii) discontinues construction for a period of eighteen months or more; (iii) does not complete construction within a reasonable time of the estimated completion date. The Division may grant extensions of the deadline per Regulation No. 3, Part B, III.F.4.b. (Reference: Regulation No. 3, Part B, III.F.4.) 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 Equipment ID AIRS Point Pounds per Month Emission Type NO,, VOC CO C-193 001 5,512 7,720 11,024 Point C-194 002 Point C-195 003 Point C-196 004 Point C-197 007 Point D-1 005 102 3,012 510 Point FUG 006 --- 1,359 --- Fugitive AIRS ID: 123/9950 Page 3 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Monthly limits are based on a 31 -day month. or Public Health and Environment Air Pollution Control Division 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 Equipment ID AIRS Point Tons per Year Emission Type NO z VOC CO C-193 001 32.4 45.6 64.8 Point C-194 002 Point C-195 003 Point C-196 004 Point C-197 007 Point D-1 005 0.6 17.7 3.0 Point FUG 006 --- 8.0 --- Fugitive ee "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 DI.E.) Facility Equipment ID AIRS Point Control Device Pollutants Controlled C-193 001 Non -selective catalytic reduction system and air/fuel ratio controller NOX, VOC, and CO AIRS ID: 123/9950 Page 4 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 or Public Health and Environment Air Pollution Control Division C-194 002 Non -selective catalytic reduction system and air/fuel ratio controller NOR, VOC, and CO C-195 003 Non -selective catalytic reduction system and air/fuel ratio controller NOx, VOC, and CO C-196 004 Non -selective catalytic reduction system and air/fuel ratio controller NOR, VOC, and CO D-1 005 Vapor recovery unit, Condenser, and Combustion device (detailed in condition 16) VOC C-197 007 Non -selective catalytic reduction system and air/fuel ratio controller NOx, VOC, and CO PROCESS LIMITATIONS AND RECORDS 9. 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 Equipment ID AIRS Point Process Parameter Annual Limit Monthly Limit (31 days) C-193 001 Consumption of natural gas as fuel for all 5 compressor engines. Total run time shall not exceed 35, 040 compressor engine -hours per year. 463.64 MMscf/yr total 39.4 MMscf/month total C-194 002 C-195 003 C-196 004 C-197 007 D-1 005 Natural gas throughput 18,250 MMscf/yr 1,MMscf/month FUG 006 Not applicable During the first twelve (12) months of operation, compliance with both the monthly and yearly consumption limitations shall be required. After the first twelve (12) months of operation, compliance with only the yearly limitation shall be required. Compliance with the yearly consumption limits shall be determined on a rolling twelve (12) month total. By the end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate monthly consumption of natural gas and keep a compliance record on site or at a local field office with site responsibility, for Division review. STATE AND FEDERAL REGULATORY REQUIREMENTS 10. 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). 11. 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 AIRS ID: 123/9950 Page 5 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division any sixty consecutive minutes. Emission control devices subject to Regulation 7, Sections XII.C.1.d or XVII.B.1.c shall have no visible emissions. (Reference: Regulation No. 1, Section II.A.1. & 4.) 12. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable) 13. Points 001-004, 007: 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. 14. Points 001-004, 007: 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 ≥500HP July 1, 2007 2.0 4.0 1.0 July 1, 2010 1.0 2.0 0.7 Note: Per Regulation No. 7, Section XVII.B.4, internal combustion engines that are subject to an 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. 15. Point 005: Compliance with the emission limits in this permit shall be demonstrated by running the GRI GlyCalc model version 4.0 or higher on a monthly basis using the most recent 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. 16. Point 005: This unit shall be configured such that the flash tank vapors are routed to the VRU to be recycled to the compressor station inlet and still vent vapors are routed to an enclosed combustor via a condenser. The control system shall reduce uncontrolled emissions of VOC 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.) 17. Point 005: 100% of emissions that result from the flash tank associated with this dehydrator shall be recycled to the compressor station inlet and recompressed. 18. Point 005: 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 AIRS ID: 123/9950 Page 6 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division operator requests an alternate circulation rate per §63.764(d)(2)(ii), then maximum recirculation rate shall not exceed 24.0 gallons per minute. The owner or operator shall maintain monthly records of the actual lean glycol recirculation rate and make them available to the Division for inspection upon request. 19. Point 005: 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. 20. Point 005: The combustion device 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. 21. Point 005: 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. 22. Point 005: This source is subject to the requirements of 40 CFR, Part 63, Subpart HH - National Emission Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities including, but not limited to, the following: • §63.764 - General Standards o §63.764 (e)(1) -The owner or operator is exempt from the requirements of paragraph (c)(1) and (d) of this section if the criteria listed in paragraph (e)(1)(i) or (ii) of this section are met, except that the records of the determination of these criteria must be maintained as required in §63.774(d)(1). • §63.764 (e)(1)(i) — The actual annual average flowrate of natural gas to the glycol dehydration unit is less than 85 thousand standard cubic meters per day (3.0 MMSCF/day), as determined by the procedures specified in §63.772(b)(1) of this subpart; or §63.764 (e)(1)(ii) — The actual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere are less AIRS ID: 123/9950 Page 7 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division than 0.90 megagram per year, as determined by the procedures specified in §63.772(b)(2) of this subpart. • §63.772 - Test Methods, Compliance Procedures and Compliance Demonstration o §63.772(b) - Determination of glycol dehydration unit flowrate or benzene emissions. The procedures of this paragraph shall be used by an owner or operator to determine glycol dehydration unit natural gas flowrate or benzene emissions to meet the criteria for an exemption from control requirements under §63.764(e)(1). §63.772(b)(1) - The determination of actual flowrate of natural gas to a glycol dehydration unit shall be made using the procedures of either paragraph (b)(1)(i) or (b)(1)(ii) of this section. • §63.772(b)(1)(i) — The owner or operator shall install and operate a monitoring instrument that directly measures natural gas flowrate to the glycol dehydration unit with an accuracy of plus or minus 2 percent or better. The owner or operator shall convert annual natural gas flowrate to a daily average by dividing the annual flowrate by the number of days per year the glycol dehydration unit processed natural gas. • §63.772(b)(1)(ii) - The owner or operator shall document, to the Administrator's satisfaction, that the actual annual average natural gas flowrate to the glycol dehydration unit is less than 85 thousand standard cubic meters per day. §63.772(b)(2) - The determination of actual average benzene emissions from a glycol dehydration unit shall be made using the procedures of either paragraph (b)(2)(i) or (b)(2)(ii) of this section. Emissions shall be determined either uncontrolled, or with federally enforceable controls in place. • §63.772(b)(2)(i) — The owner or operator shall determine actual average benzene emissions using the model GRI- GLYCaIc TM , Version 3.0 or higher, and the procedures presented in the associated GRI-GLYCaIc TM Technical Reference Manual. Inputs to the model shall be representative of actual operating conditions of the glycol dehydration unit and may be determined using the procedures documented in the Gas Research Institute (GRI) report entitled "Atmospheric Rich/Lean Method for Determining Glycol Dehydrator Emissions" (GRI-95/0368.1); or • §63.772(b)(2)(ii) - The owner or operator shall determine an average mass rate of benzene emissions in kilograms per hour through direct measurement using the methods in §63.772(a)(1)(i) or (ii), or an alternative method according to §63.7(f). Annual emissions in kilograms per year shall be determined by multiplying the mass rate by the number of AIRS ID: 123/9950 Page 8 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 or Public Health and Environment Air Pollution Control Division hours the unit is operated per year. This result shall be converted to megagrams per year. §63.774 - Recordkeeping Requirements o §63.774 (d)(1) - An owner or operator of a glycol dehydration unit that meets the exemption criteria in §63.764(e)(1)(i) or §63.764(e)(1)(ii) shall maintain the records specified in paragraph (d)(1)(i) or paragraph (d)(1)(ii) of this section, as appropriate, for that glycol dehydration unit. • §63.774 (d)(1)(i) — The actual annual average natural gas throughput (in terms of natural gas flowrate to the glycol dehydration unit per day) as determined in accordance with §63.772(b)(1), or §63.774 (d)(1)(ii) - The actual average benzene emissions (in terms of benzene emissions per year) as determined in accordance with §63.772(b)(2). 23. Point 005: If this source is unable meet the criteria listed in paragraph (e)(1)(i) or (ii) of §63.764 as listed in Condition 22, then this source shall be subject to the TEG dehydrator area source requirements of 40 CFR, Part 63, Subpart HH - National Emission Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities including, but not limited to, the following: §63.760 — Applicability and designation of affected source o §63.760 (f) - The owner or operator of an affected major source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(1) and (f)(2) of this section. The owner or operator of an affected area source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(3) through (f)(6) of this section. §63.760 (f)(6) - The owner or operator of an affected area source that is not located in an Urban -1 county, as defined in §63.761, the construction or reconstruction of which commences on or after July 8, 2005, shall achieve compliance with the provisions of this subpart immediately upon initial startup or January 3, 2007, whichever date is later. • §63.764 - General Standards o §63.764 (d)(2) —Each owner or operator of an area source not located in a UA plus offset and UC boundary (as defined in §63.761) shall comply with the provisions specified in paragraphs (d)(2(i) through (iii) of this section. • §63.764 (d)(2)(i) — Determine the optimum glycol circulation rate using the following equation: gaITEO *'F*(I O)v Lo, =1.15*3.0 IbH2O ,24hrlday, Where: LoPT = Optimal circulation rate, gal/hr. F = Gas Flowrate (MMSCF/D) AIRS ID: 123/9950 Page 9 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division I = Inlet water content (lb/MMSCF) O = Outlet water content (lb/MMSCF) 3.0 = The industry accepted rule of thumb for a TEG-to water ratio (gal TEG/IbH2O) 1.15 = Adjustment factor included for a margin of safety. • §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 (ii) of this section and submit the information specified under §63.775(c)(7)(ii) through (v). §63.774 - Recordkeeping Requirements o §63.774 (b) - Except as specified in paragraphs (c), (d), and (f) of this section, each owner or operator of a facility subject to this subpart shall maintain the records specified in paragraphs (b)(1) through (11) of this section: • §63.774 (b)(1) - The owner or operator of an affected source subject to the provisions of this subpart shall maintain files of all information (including all reports and notifications) required by this subpart. The files shall be retained for at least 5 years following the date of each occurrence, measurement, maintenance, corrective action, report or period. • §63.774 (b)(1)(i) — All applicable records shall be maintained in such a manner that they can be readily accessed. • §63.774 (b)(1)(ii) — The most recent 12 months of records shall be retained on site or shall be accessible from a central location by computer or other means that provides access within 2 hours after a request. • §63.774 (b)(1)(iii) — The remaining 4 years of records may be retained offsite. AIRS ID: 123/9950 Page 10 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 • Public Health and Environment Air Pollution Control Division §63.774 (b)(1)(iv) — Records may be maintained in hard copy or computer -readable form including, but not limited to, on paper, microfilm, computer, floppy disk, magnetic tape, or microfiche. o §63.774 (f) - The owner or operator of an area source not located within a UA plus offset and UC boundary must keep a record of the calculation used to determine the optimum glycol circulation rate in accordance with §63.764(d)(2)(i) or §63.764(d)(2)(ii), as applicable. • §63.775 — Reporting Requirements o §63.775 (c) - Except as provided in paragraph (c)(8), each owner or operator of an area source subject to this subpart shall submit the information listed in paragraph (c)(1) of this section. If the source is located within a UA plus offset and UC boundary, the owner or operator shall also submit the information listed in paragraphs (c)(2) through (6) of this section. If the source is not located within any UA plus offset and UC boundaries, the owner or operator shall also submit the information listed within paragraph (c)(7). §63.775 (c)(1) - The initial notifications required under §63.9(b)(2) not later than January 3, 2008. In addition to submitting your initial notification to the addressees specified under §63.9(a), you must also submit a copy of the initial notification to EPA's Office of Air Quality Planning and Standards: Send your notification via e-mail to CCG— ONG@EPA.GOV or via U.S. mail or other mail delivery service to U.S. EPA, Sector Policies and Programs Division/Coatings and Chemicals Group (E143—01), Attn: Oil and Gas Project Leader, Research Triangle Park, NC 27711. §63.775 (c)(7) - The information listed in paragraphs (c)(1)(i) through (v) of this section. This information shall be submitted with the initial notification. §63.775 (c)(7)(i) - Documentation of the source's location relative to the nearest UA plus offset and UC boundaries. This information shall include the latitude and longitude of the affected source; whether the source is located in an urban cluster with 10,000 people or more; the distance in miles to the nearest urbanized area boundary if the source is not located in an urban cluster with 10,000 people or more; and the names of the nearest urban cluster with 10,000 people or more and nearest urbanized area. §63.775 (c)(7)(ii) - Calculation of the optimum glycol circulation rate determined in accordance with §63.764(d)(2)(i). §63.775 (c)(7)(iii) - If applicable, documentation of the alternate glycol circulation rate calculated using GRI- GLYCalcTM, Version 3.0 or higher and documentation stating why the TEG dehydration unit must operate using the alternate glycol circulation rate. • AIRS ID: 123/9950 Page 11 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division • §63.775 (c)(7)(iv) - The name of the manufacturer and the model number of the glycol circulation pump(s) in operation. • §63.775 (c)(7)(v) - Statement by a responsible official, with that official's name, title, and signature, certifying that the facility will always operate the glycol dehydration unit using the optimum circulation rate determined in accordance with §63.764(d)(2)(i) or §63.764(d)(2)(ii), as applicable. o §63.775 (f) - Notification of process change. Whenever a process change is made, or a change in any of the information submitted in the Notification of Compliance Status Report, the owner or operator shall submit a report within 180 days after the process change is made or as a part of the next Periodic Report as required under paragraph (e) of this section, whichever is sooner. The report shall include: • §63.775 (f)(1) - A brief description of the process change; • §63.775 (f)(2) - A description of any modification to standard procedures or quality assurance procedures §63.775 (f)(3) — Revisions to any of the information reported in the original Notification of Compliance Status Report under paragraph (d) of this section; and §63.775 (f)(4) - Information required by the Notification of Compliance Status Report under paragraph (d) of this section for changes involving the addition of processes or equipment. 24. Point 006: 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. Point 006: 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 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 26, shall satisfy the requirement to apply RACT. 26. Point 006: 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. AIRS ID: 123/9950 Page 12 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 of Public Health and Environment Air Pollution Control Division • The detection sensitivity level shall be 60 grams per hour which correlates to the least frequent monitoring schedule listed in Table 1 of 40 CFR 60 Subpart A. • The operator shall comply with the instrument specifications in 40 CFR 60.18(i)(1). • The operator shall comply with the daily instrument checks in 40 CFR 60.18(i)(2). • The operator shall perform screening in accordance with 40 CFR 60.18 (i)(3). • The operator shall tag all leaking components with date of leak detected, date of repair and date of rescreening to confirm repair. Once a leak is repaired, the leaker tag may be removed. • Component leaks detected shall be repaired as set forth below: o The leak will be repaired within 15 days. Repaired components shall be re- screened within five days of repair to determine if the leak is repaired. If the rescreening shows a leak, then the leak shall be repaired as soon as practicable, but no later than 15 days after the rescreening. Repeat the process until the rescreening shows no leak. 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 7, 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. AIRS ID: 123/9950 Page 13 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division o Records of daily instrument check including the distance and flow meter reading at which the leak was imaged. Keep a video record of the daily instrument check for each configuration of the optical gas imaging instrument used during the leak survey (for example, the daily instrument check must be conducted for each lens used). The video record must include a time and date stamp for each daily instrument check. The video record must be kept for two years. OPERATING & MAINTENANCE REQUIREMENTS 27. Points 001-005, 007: 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.) 28. Point 005: 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 29. Points 001-004, 007: A source initial compliance test shall be conducted on emissions point 001, 002, 003, 004, and 007 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) Oxides of Nitrogen Carbon Monoxide Volatile Organic Compounds Formaldehyde 30. Point 005: 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.) 31. Point 005: The owner or operator shall demonstrate compliance with Condition 11, using EPA Method 22 to measure opacity from the flare. 32. Point 006: Within one hundred and eighty days (180) after commencement of operation, the permittee shall complete the initial extended gas analysis of gas samples AIRS ID: 123/9950 Page 14 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division 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. 33. Point 006: 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 34. Points 001-004, 007: 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. 35. Point 005: 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. 36. Point 006: 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 37. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation No. 3, Part A, II.C) a. Annually whenever a significant increase in emissions occurs as follows: For any criteria pollutant: For sources emitting less than 100 tons per year, a change in actual emissions of five (5) tons per year or more, above the level reported on the last APEN; or For volatile organic compounds (VOC) and nitrogen oxides sources (NOx) 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 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 AIRS ID: 123/9950 Page 15 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division c. Whenever new control equipment is installed, or whenever a different type of control equipment replaces an existing type of control equipment; or d. Whenever a permit limitation must be modified; or e. No later than 30 days before the existing APEN expires. f. Within 14 calendar days of commencing operation of a permanent replacement engine under the alternative operating scenario outlined in this permit as Attachment A. The APEN shall include the specific manufacturer, model and serial number and horsepower of the permanent replacement engine, the appropriate APEN filing fee and a cover letter explaining that the permittee is exercising an alternative -operating scenario and is installing a permanent replacement engine. 38. 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). 39. 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) 40. MACT Subpart ZZZZ - 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 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: 41. 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. 42. 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 AIRS ID: 123/9950 Page 16 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division obtaining final authorization to operate are located in the Requirements to Self - Certify for Final Authorization section of this permit. 43. 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. 44. 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. 45. 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. 46. 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. 47. Violation of the terms of a permit or of the provisions of the Colorado Air Pollution Prevention and Control Act or the regulations of the AQCC may result in administrative, civil or criminal enforcement actions under Sections 25-7-115 (enforcement), -121 (injunctions), -122 (civil penalties), -122.1 (criminal penalties), C.R.S. • By: Oluwaseun Ogungbenle Permit Engineer Air Pollution Control Division Permit Histo Issuance Date Description Issuance 1 This Issuance Issued to DCP Midstream, LP. AIRS ID: 123/9950 Page 17 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division Notes to Permit Holder: 1) 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. 2) This source is subject to the Common Provisions Regulation Part II, Subpart E, Affirmative Defense Provision for Excess Emissions During Malfunctions. The permittee shall notify the Division of any malfunction condition which causes a violation of any emission limit or limits stated in this permit as soon as possible, but no later than noon of the next working day, followed by written notice to the Division addressing all of the criteria set forth in Part II.E.1. of the Common Provisions Regulation. See: http://www.cdphe.state.co.us/regulations/airregs/100102agcccommonprovisionsreq.pdf. 3) 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. AIRS Point Pollutant CAS # BIN Uncontrolled Emission Rate (Ib/yr) Are the emissions reportable? Controlled Emission Rate (Ib/yr) 001 Formaldehyde 5000 A 1622 Yes 389 Methanol 67561 C 355 No 177 Acetaldehyde 75070 A 323 Yes 162 Acrolein 107028 A 305 Yes 152 Benzene 71432 A 183 Yes 92 1,3 -Butadiene 106990 A 77 Yes 38 Toluene 108883 C 65 No 32 002 Formaldehyde 5000 A 1622 Yes 389 Methanol 67561 C 355 No 177 Acetaldehyde 75070 A 323 Yes 162 Acrolein 107028 A 305 Yes 152 Benzene 71432 A 183 Yes 92 1,3 -Butadiene 106990 A 77 Yes 38 Toluene 108883 C 65 No 32 003 Formaldehyde 5000 A 1622 Yes 389 Methanol 67561 C 355 No 177 Acetaldehyde 75070 A 323 Yes 162 Acrolein 107028 A 305 Yes 152 Benzene 71432 A 183 Yes 92 1,3 -Butadiene 106990 A 77 Yes 38 AIRS ID: 123/9950 Page 18 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 or Public Health and Environment Air Pollution Control Division Toluene 108883 C 65 No 32 004 Formaldehyde 5000 A 1622 Yes 389 Methanol 67561 C 355 No 177 Acetaldehyde 75070 A 323 Yes 162 Acrolein 107028 A 305 Yes 152 Benzene 71432 A 183 Yes 92 1,3 -Butadiene 106990 A 77 Yes 38 Toluene 108883 C 65 No 32 005 Benzene 71432 A 158,086 Yes 8,181 Toluene 108883 C 198,245 Yes 8,863 Ethylbenzene 100414 C 8,569 Yes 276 Xylenes 1330207 C 96,868 Yes 2,977 n -Hexane 110543 C 78,800 Yes 2,374 006 Benzene 71432 A 33 No NA Toluene 108883 C 32 No NA Xylenes 1330207 C 11 No NA n -Hexane 110543 C 566 No NA 4) The emission levels contained in this permit are based on the following emission factors: Points 001-004, 007: CAS Pollutant Emission Uncontrolled lb/MMBtu Factors - g/bhp-hr Emission Controlled lb/MMBtu Factors — 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-Spec'fic Fuel Consumption Factor of 7876 Btu/hp-hr, a site -rated horsepower value of 1680, and a fuel heat value of 1000 Btu/scf. ^CAS Pollutant Uncontrolled EF Source Controlled EF Source NOx Manufacturer's specifications Manufacturer's specifications CO Manufacturer's specifications Manufacturer's specifications VOC Manufacturer's specifications Manufacturer's specifications 5000 Formaldehyde Manufacturer's specifications Manufacturer's specifications AIRS ID: 123/9950 Page 19 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 o Public Health and Environment Air Pollution Control Division CAS Pollutant Uncontrolled EF Source Controlled. EF Source 67561 Methanol AP -42; Table 3.2-3 (7/2000); Natural Gas Manufacturer's specifications 75070 Acetaldehyde AP -42; Table 3.2-3 (7/2000); Natural Gas Manufacturer's specifications 107028 Acrolein AP -42; Table 3.2-3 (7/2000); Natural Gas Manufacturer's specifications 71432 Benzene AP -42; Table 3.2-3 (7/2000); Natural Gas Manufacturer's specifications 106990 1,3 -Butadiene AP -42; Table 3.2-3 (7/2000); Natural Gas Manufacturer's specifications 108883 Toluene AP -42; Table 3.2-3 (7/2000); Natural Gas Manufacturer's specifications Point 005: The emission levels contained in this permit are based on information provided in the application and the GRI GlyCalc 4.0 model. Controlled emissions are based on 100% recycle of the flash tank emissions and 95% control of the still vent vapors using an enclosed combustor. Additional control of still vent emissions is achieved by routing the vapors to a condenser prior to sending them to the enclosed combustor. Optimal recirculation rate per MACT HH (63.74(d)(2)(i)) is based on the following information submitted with the application: F = 50MMscfd; I = 121.8 Ib/MMscf; and O = 6.7 lb/MMscf. Point 006: Component Gas Service Heavy Oil Light Oil Water/Oil Service Connectors 1422 0 217 0 Flanges 231 0 89 0 Open-ended Lines 51 0 8 0 Pump Seals 0 0 2 0 Valves 306 0 72 0 Other* 31 0 4 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 AIRS ID: 123/9950 Page 20 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division 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. 5) In accordance with C.R.S. 25-7-114.1, each Air Pollutant Emission Notice (APEN) associated with this permit is valid for a term of five years from the date it was received by the Division. A revised APEN shall be submitted no later than 30 days before the five-year term expires. Please refer to the most recent annual fee invoice to determine the APEN expiration date for each emissions point associated with this permit. For any questions regarding a specific expiration date call the Division at (303)-692-3150. 6) 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 Reboiler TEG Dehy unit reboiler, rated at 2.86 MMBtu/hr This unit is exempt from APEN reporting requirements because the design rate is less than 5 MMBtu/hr (Regulation No. 3, Part A, II.D.1.k), and is therefore also exempt from construction permitting requirements (Regulation no. 3, Part B, II.D.1.a). Criteria pollutant emission levels for this unit are based on factors from AP -42, Chapter 1.4, Small Boilers < 100 MMBtu/hr (7/1998). 7) Points 001 through 004, 007: 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: http://www.epa.gov/ttn/atw/area/fr18ia08.pdf 8) Points 001 through 004, 007: 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: http://www.epa.gov/ttn/atw/area/fr18ia08.pdf Additional information regarding area source standards can be found on the EPA website at: http://www.epa.gov/ttn/atw/area/arearules.html 9) This facility is classified as follows: Applicable Requirement Status Operating Permit Synthetic Minor Source CO, VOC, NOx, Benzene, Toluene, Xylenes, n -Hexane, and Total HAPs PSD Synthetic Minor Source CO NANSR Synthetic Minor Source VOC, NOx MACT HH Area Source Requirements AIRS ID: 123/9950 Page 21 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Area Source Requirements o Public Health and Environment Air Pollution Control Division MACT ZZZZ 10) Full text of the Title 40, Protection of Environment Electronic Code of Federal Regulations can be found at the website listed below: http://ecfr.qpoaccess.gov/ Part 60: Standards of Performance for New Stationary Sources NSPS 60.1 -End Subpart A— Subpart KKKK NSPS Part 60, Appendixes Appendix A — Appendix I Part 63: National Emission Standards for Hazardous Air Pollutants for Source Categories MACT 63.1-63.599 Subpart A — Subpart Z MACT 63.600-63.1199 Subpart AA — Subpart DDD MACT 63.1200-63.1439 Subpart EEE — Subpart PPP MACT 63.1440-63.6175 Subpart QQQ — Subpart YYYY MACT 63.6580-63.8830 Subpart ZZZZ — Subpart MMMMM MACT 63.8980 -End Subpart NNNNN — Subpart XXXXXX 11) An Oil and Gas Industry Construction Permit Self -Certification Form is included with this permit packet. Please use this form to complete the self -certification requirements as specified in the permit conditions. Further guidance on self -certification can be found on our website at: http://www.colorado.qov/cdphe/OilandGas AIRS ID: 123/9950 Page 22 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 or Public Health and Environment Air Pollution Control Division ATTACHMENT A: ALTERNATIVE OPERATING SCENARIOS RECIPROCATING INTERNAL COMBUSTION ENGINES October 12, 2012 2. Alternative Operating Scenarios The following Alternative Operating Scenario (AOS) for the temporary and permanent replacement of natural gas fired reciprocating internal combustion engines has been reviewed in accordance with the requirements of Regulation No. 3., Part A, Section IV.A, Operational Flexibility -Alternative Operating Scenarios, Regulation No. 3, Part B, Construction Permits, and Regulation No. 3, Part D, Major Stationary Source New Source Review and Prevention of Significant Deterioration, and it has been found to meet all applicable substantive and procedural requirements. This permit incorporates and shall be considered a Construction Permit for any engine replacement performed in accordance with this AOS, and the owner or operator shall be allowed to perform such engine replacement without applying for a revision to this permit or obtaining a new Construction Permit. 2.1 Engine Replacement The following AOS is incorporated into this permit in order to deal with a compressor engine breakdown or periodic routine maintenance and repair of an existing onsite engine that requires the use of either a temporary or permanent replacement engine. "Temporary" is defined as in the same service for 90 operating days or less in any 12 month period. "Permanent" is defined as in the same service for more than 90 operating days in any 12 month period. The 90 days is the total number of days that the engine is in operation. If the engine operates only part of a day, that day shall count as a single day towards the 90 day total. The compliance demonstrations and any periodic monitoring required by this AOS are in addition to any compliance demonstrations or periodic monitoring required by this permit. All replacement engines are subject to all federally applicable and state -only requirements set forth in this permit (including monitoring and record keeping). The results of all tests and the associated calculations required by this AOS shall be submitted to the Division within 30 calendar days of the test or within 60days of the test if such testing is required to demonstrate compliance with NSPS or MACT requirements. Results of all tests shall be kept on site for five (5) years and made available to the Division upon request. The owner or operator shall maintain a log on -site and contemporaneously record the start and stop date of any engine replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number of the engine(s) that are replaced during the term of this permit, and the manufacturer, model number, horsepower, and serial number of the replacement engine. In addition to the log, the owner or operator shall maintain a copy of all Applicability Reports required under section 2.1.2 and make them available to the Division upon request. 2.1.1 The owner or operator may temporarily replace an existing compressor engine that is subject to the emission limits set forth in this permit with an engine that is of the same manufacturer, model, and horsepower or a different manufacturer, model, or horsepower as the existing engine without modifying this permit, so long as the temporary replacement engine complies with all permit limitations and other requirements applicable to the existing engine. Measurement of emissions from the temporary replacement engine shall be made as set forth in section 2.2. AIRS ID: 123/9950 Page 23 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division 2.1.2 The owner or operator may permanentlyreplace the existing compressor engine with another engine with the same manufacturer, model, and horsepower engines without modifying this permit so long as the permanent replacement engine complies with all permit limitations and other requirements applicable to the existing engine as well as any new applicable requirements for the replacement engine. Measurement of emissions from the permanent replacement engine and compliance with the applicable emission limitations shall be made as set forth in section 2.2. An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model and serial number and horsepower of the permanent replacement engine shall be filed with the Division for the permanent replacement engine within 14 calendar days of commencing operation of the replacement engine. The APEN shall be accompanied by the appropriate APEN filing fee, a cover letter explaining that the owner or operator is exercising an alternative operating scenario and is installing a permanent replacement engine, and a copy of the relevant Applicability Reports for the replacement engine. Example Applicability Reports can be found at http://www.cdphe.state.co.us/ap/oilgaspermitting.html. This submittal shall be accompanied by a certification from the Responsible Official indicating that "based on the information and belief formed after reasonable inquiry, the statements and information included in the submittal are true, accurate and complete". This AOS cannot be used for permanent engine replacement of a grandfathered or permit exempt engine or an engine that is not subject to emission limits. The owner or operator shall agree to pay fees based on the normal permit processing rate for review of information submitted to the Division in regard to any permanent engine replacement. 2.2 Portable Analyzer Testing Note: In some cases there may be conflicting and/or duplicative testing requirements due to overlapping Applicable Requirements. In those instances, please contact the Division Field Services Unit to discuss streamlining the testing requirements. Note that the testing required by this Condition may be used to satisfy the periodic testing requirements specified by the permit for the relevant time period (i.e. if the permit requires quarterly portable analyzer testing, this test conducted under the AOS will serve as the quarterly test and an additional portable analyzer test is not required for another three months). The owner or operator may conduct a reference method test, in lieu of the portable analyzer test required by this Condition, if approved in advance by the Division. The owner or operator shall measure nitrogen oxide (NOx) and carbon monoxide (CO) emissions in the exhaust from the replacement engine using a portable flue gas analyzer within seven (7) calendar days of commencing operation of the replacement engine. All portable analyzer testing required by this permit shall be conducted using the Division's Portable Analyzer Monitoring Protocol (ver March 2006 or newer) as found on the Division's web site at: http://www. co lorado. qov/cs/Satellite/C D PH E-AP/C BO N/ 1251596520270. Results of the portable analyzer tests shall be used to monitor the compliance status of this unit. For comparison with an annual (tons/year) or short term (lbs/unit of time) emission limit, the results of the tests shall be converted to a lb/hr basis and multiplied by the allowable operating hours in the month or year (whichever applies) in order to monitor compliance. If a source is not limited in its hours of operation the test results will be multiplied by the maximum number of hours in the month or year (8760), whichever applies. AIRS ID: 123/9950 Page 24 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 of Public Health and Environment Air Pollution Control Division For comparison with a short-term limit that is either input based (lb/MMBtu), output based (g/hp-hr) or concentration based (ppmvd @ 15% O2) that the existing unit is currently subject to or the replacement engine will be subject to, the results of the test shall be converted to the appropriate units as described in the above -mentioned Portable Analyzer Monitoring Protocol document. If the portable analyzer results indicate compliance with both the NOx and CO emission limitations, in the absence of credible evidence to the contrary, the source may certify that the engine is in compliance with both the NOx and CO emission limitations for the relevant time period. Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if the portable analyzer results fail to demonstrate compliance with either the NOx or CO emission limitations, the engine will be considered to be out of compliance from the date of the portable analyzer test until a portable analyzer test indicates compliance with both the NOx and CO emission limitations or until the engine is taken offline. 2.3 Applicable Regulations for Permanent Engine Replacements 2.3.1 Reasonably Available Control Technology (RACT): Reg 3, Part B § II.D.2 All permanent replacement engines that are located in an area that is classified as attainment/maintenance or nonattainment must apply Reasonably Available Control Technology (RACT) for the pollutants for which the area is attainment/maintenance or nonattainment. Note that both VOC and NOx are precursors for ozone. RACT shall be applied for any level of emissions of the pollutant for which the area is in attainment/maintenance or nonattainment, except as follows: In the Denver Metropolitan PM10 attainment/maintenance area, RACT applies to PM10 at any level of emissions and to NOx and SO2, as precursors to PM10, if the potential to emit of NOx or SO2 exceeds 40 tons/yr. For purposes of this AOS, the following shall be considered RACT for natural gas fired reciprocating internal combustion engines: VOC: The emission limitations in NSPS JJJJ CO: The emission limitations in NSPS JJJJ NOx: The emission limitations in NSPS JJJJ SO2: Use of natural gas as fuel PMio: Use of natural gas as fuel As defined in 40 CFR Part 60 Subparts GG (§ 60.331) and 40 CFR Part 72 (§ 72.2), natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. 2.3.2 Control Requirements and 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. AIRS ID: 123/9950 Page 25 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 Public Health and Environment Air Pollution Control Division Lean burn engines with a manufacturer's design rate greater than 500 hp shall use an oxidation catalyst to reduce emissions. The above emission control equipment shall be appropriately sized for the engine and shall be operated and maintained according to manufacturer specifications. The source shall submit copies of the relevant Applicability Reports required under Condition 2.1.2. Emission Standards: Section XVII.E— State -only requirements Any permanent engine that is either constructed or relocated to the state of Colorado from another state, after the date listed in the table below shall operate and maintain each engine according to the manufacturer's written instructions or procedures to the extent practicable and consistent with technological limitations and good engineering and maintenance practices over the entire life of the engine so that it achieves the emission standards required in the table below: Max Engine HP Construction or Relocation Date Emission Standards in G/hp-hr NOx CO VOC 100<Hp<500 January 1, 2008 January 1, 2011 2.0 1.0 4.0 2.0 1.0 0.7 500≤Hp July 1, 2007 July 1, 2010 2.0 1.0 4.0 2.0 1.0 0.7 The source shall submit copies of the relevant Applicability Reports required under Condition 2.1.2. 2.3.3 NSPS for stationary spark ignition internal combustion engines: 40 CFR Part 60, Subpart JJJJ A permanent replacement engine that is manufactured on or after 7/1/09 for emergency engines greater than 25 hp, 7/1/2008 for engines less than 500 hp, 7/1/2007 for engines greater than or equal to 500 hp except for lean burn engines greater than or equal to 500 hp and less than 1,350 hp, and 1/1/2008 for lean burn engines greater than or equal to 500 hp and less than 1,350 hp are subject to the requirements of 40 CFR Part 60, Subpart JJJJ. An analysis of applicable monitoring, recordkeeping, and reporting requirements for the permanent engine replacement shall be included in the Applicability Reports required under Condition 2.1.2. Any testing required by the NSPS is in addition to that required by this AOS. Note that the initial test required by NSPS Subpart JJJJ can serve as the testing required by this AOS under Condition 2.2, if approved in advance by the Division, provided that such test is conducted within the time frame specified in Condition 2.2. Note that under the provisions of Regulation No. 6. Part B, section I.B. that Relocation of a source from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of Regulation No. 6 (i.e., the date that the source is first relocated to Colorado becomes equivalent to the manufacture date for purposes of determining the applicability of NSPS JJJJ requirements). However, as of October 1, 2011 the Division has not yet adopted NSPS JJJJ. Until such time as it does, any engine subject to NSPS will be subject only under Federal law. Once the Division adopts NSPS JJJJ, there will be an additional step added to the determination of the NSPS. Under the provisions of Regulation No. 6, Part B, § 1.B (which is referenced in Part A), any engine relocated from outside of the State of Colorado into the State of Colorado 'is considered to be a new source, subject to the requirements of NSPS JJJJ. 2.3.4 Reciprocating internal combustion engine (RICE) MACT: 40 CFR Part 63, Subpart ZZZZ AIRS ID: 123/9950 Page 26 of 27 DCP Midstream, LP Permit No. 12WE2039 Issuance 1 of Public Health and Environment Air Pollution Control Division A permanent replacement engine located at either an area or major source is subject to the requirements in 40 CFR Part 63, Subpart ZZZZ. An analysis of the applicable monitoring, recordkeeping, and reporting requirements for the permanent engine replacement shall be included in the Applicability Reports required under Condition 2.1.2. Any testing required by the MACT is in addition to that required by this AOS. Note that the initial test required by the MACT can serve as the testing required by this AOS under Condition 2.2, if approved in advance by the Division, provided that such test is conducted within the time frame specified in Condition 2.2. 2.4 Additional Sources The replacement of an existing engine with a new engine is viewed by the Division as the installation of a new emissions unit, not "routine replacement" of an existing unit. The AOS is therefore essentially an advanced construction permit review. The AOS cannot be used for additional new emission points for any site; an engine that is being installed as an entirely new emission point and not as part of an AOS- approved replacement of an existing onsite engine has to go through the appropriate Construction/Operating permitting process prior to installation. AIRS ID: 123/9950 Page 27 of 27 C..%I F 0 O C3 0 4r (15— I.I '''E .1 O ffiiU - r::a a z CC u O Z L 0 TU C CVI o C V y x o H U ;- o Ca n 0 A O Cy T H EEE a N ro Ca V wa C U El C z z C ti 6- i O d ? [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] Facility Equipment ID: nested Action (check applicable request boxes) Section 02 — Re Section 01 — Administrative Information v ad t o a 0. O. V C a T n C 0 O ❑ >. u W 0 d L F N 0O O 0. F _a y •C L G L 'Br. .F aP— o Ca Gcci c E C o O U _ U ate+ y 0. C, = o o CC 3 0 0 I. E " W w Cam) O w Ca Ca .- V v pp v 'E x °m ° K ° L. C y o a O F O v E CU 0 0.O° T ) 6 o 'E ❑ El m Y C. Gm h. . t C) )-h. G y O el .0.. b y 0 hO 6, u i 0 O W aC� d ,,, F cr F • 0.� 6 C. O. ra .�' 9 U [j fn x a m 0 O C4 H a s z Ca w z O 0 00 OC E W y �'� G s ° Ca ro - > '0 .v". 0 Ca Ca Ca C) C) a a ti .v J J C C = = 0' Q' 0' z z z❑❑ z❑ ❑ z• . N ❑ ❑ ❑ ❑ ❑ ¢4z t 3 N v. Lin Q O y T GO V) 0 Ca U U U0 > Q U W z� DCP Midstream, LP Engine C -1`I3 C) Ca T co C Ca J a2 VD 0 U NWNW, Sec. 27, T6N, R63W C) V N o o G Ca 0 O ro .� 02. O 00 -o C) U CN N wdhill@dcpmidstream.com F c N 0 0 -a 0 U < G Section 03 —General Information 0 O N For new or reconstructed sources, the projected startup date is: 2 Ca co) col N 7 days/week 9 0 N G Ca Ca c 0 o o ro N Er, o o' 0 0. 0 U 'o w `o a o z 0 O GO C 03 Ca O 0. C) yc c o -a 0 L a ^ m o c c v 0 z 0 a Natural gas compression H F O 0 ctzt U U G F 0 O V ti °o E C o O 3 T C) ro o 0 m y A Date the engine was relocated into Colorado: O O o n U40 0 G 0 m '0 U a > CCa Ca CC W ro'^ Ca 0 F' h � D ro g J ch G U vi A v F O p, a) V N C > Ca 3 w Ca 0 m T - o > L. J n w o C G a O 016,) o m m y •p, O H Ca o Qp ❑ z Ca U ro G q Ca C O G G a' Q 'm Ca Ca c Ca A J CJ O 0. o' p0cc - Go P. V a Li Ca > 3 =, ine Information Section 04 — Et a Engine displacement: H F Engine date of manufacture: n a 0 N Waukesha Manufacturer: 0 0 0 0 N N - - ❑ ❑ '0 0 0 .S Ca 0 a Ca U Q F w Ca cc a G G O a U C F J J ❑Z g % X Ca n F F O_ Ca Ca U y y c a a a U U Ca w w c a a _ _ o ro Ca b O 00 N Engine Brake Specific Fuel Consumption @ 100% Load: C; U - O V C' _ ^ Cat h a a 0 0 0 0 a G E 0.0. ca ca ro -o 9 w w O 0 T T CZ 0 0 En co U V 0 0' 0' P. 0 0 0 0 _0 0 Ca Ca UU N® 0 FORM APCD-201 { n CO 0 N 114 cl W 0 Lc^ C) 0 cv -o Ca 0-0 F. ci O h P U a:II so ci U O O IU g ti © ot ❑ U y 1 O z O ci U r�r_l ^I 0 z z O b 0 O ro w 0 a) N .E O •E N I- v n C) 0 a C L U U N H z f r O I;'_ P L';1 Q u W I 0* U cn ° O y C 'Cu: 0 'Cu:en C en 'e 00 u cti o¢ w" .0 a 0 o Q C a 0 0 C a so E ❑ w � U 42 a.; ca ❑ t 0 ▪ N U N N � tj O c▪ n U b0 vroi ❑ w � O O r • ro a W Section 06 — Fuel Consumption Information Seasonal Fuel Use (% of Annual Use) 4)4t.) N 0 U Cn >� CD 5 W 4) w 0 0 00 d ci P LYi 115.91 MMSCF/yr 13,232 SCF/hr N W H R L ..) 0 ❑ z O z a) Is this engine equipped with an Air/Fuel ratio controller? Section 07 — Emissions Inventory Information & Emission Control Information Estimation Method or Emission Factor Source • N (Y(], N '0.� AP -42 C-- c al 4: c'❑-++ 0] V-. c ctl V' c N OYOI-� N p-pty N -' Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested Permitted Emissions Controlled (Tons/Year) N N N F-; N ,� ,--. oo CO ,-.,, N ti T o o0 0 7 cc= 0 N 0 Uncontrolled (Tons/Year) N .y ,., N c-i - N N — N U) Di .. N 24.33 O W GO ,-1 H oo 0 VC r4 0 In r-. 0 O\ O 0 Actual Calendar Year Emissions' Controlled (Tons/Year) Uncontrolled (Tons/Year) ..... Emission Factor Units ❑ a a y ❑ .1 5 E 0 c .. OD a OD 0 a s CCD a a s oo C 2 EE ❑ __ ❑ a Uncontrolled Basis N 444 ,ti N N - , ,0-'A�Sr en 0 N en en N an CO .y kraus yea Control Efficiency (% Reduction) a. VI 0 76 In In U-) I actor uocumentation attacueu Control Device Description Primary Secondary NSCR NSCR U U7 z NSCR NSCR NSCR NSCR PM.., p., z > U U 9 F.::¢ L Acetaldehyde ❑ O XI omplete, true and correct. .3 d A G 0 a n o i n -a ❑ co a au 7-4 0 C O A E 4 I W ci 4▪ ) a u ea Iti Ist O \ CW 1 N H 0 0 N 8 0 m 2 Z w F- 0 Z z 0 U) cn 2 w F — Z I- J J 0 a_ ce w m a w E2 w Z 0 Z 0 4(73 0 m C 3) E O U C d Q) U a 0 5 O) 9- C) cu AIRS ID Number: Permit Number: DCP Midstream, LP Company Name: a) O O O N C O 0 NWNW Section 27 Township 6N Range 63W Plant Location: Person to Contact: Fax Number: stream.co E E-mail Address: Controlled Actual Emissions (lbs/year) N co co Uncontrolled Actual Emissions (lbs/year) u7 co co ti Emission Factor Source N a a Emission Factor (Include Units) 6.63E-4 Ib/MMBtu Control Equipment / Reduction (%) Q Reporting BIN Chemical Name 1,3 -Butadiene Chemical Abstract Service (CAS) Number Q Cr) CD O r � J Calendar Year for which Actual Data Applies: Reporting Scenario (1, Senior Environmental Specialist a) 0 O O U) O a) N O .C O? a) J C O U) Q) d w Title of Person Legally Authorized to Supply Data Name of Person Legally Authorized to Supply Data (Please print) u O Emission Source AIRS ID: [Leave blank unless APCD has already assigned a permit II & AIRS ID] 3 Permit Number: t U Facility Equipment ID: nested Action (check applicable request boxes) Section 02 — Re Section 01 — Administrative Information Request for NEW permit or newly reported emission source Request PORTABLE source permit Source Name: N N o P0 ca. N N T y a O 0 O ID N N cal O G .0 F = o N o q a p y c C 0 c m a 0 a m c 3 E n d u d= v P, 0 0 N 3 O 0 N N d O ...km � d o od c o .0 Ed =o c s `c x y p N U H d 0 O E a CO _ d N d 0 .. ❑ ❑ m om' o N F u C 0 .4 r 00 N W R E F E; y G N C C Q O V] U o w q O ai o p 'E a .E z b c c 'h N N w• > m 9.vi O 'Zoo y y :-, r co N N N N L. z❑❑0 z❑ ❑ z °-'. +] o d Sec. 27, T6N, R63W N 0 00 b U G N 370 17th Street, Suite 2500 O 0 n 3 O H o c N O C O N G Section 03 — General Information re) 0 N For new or reconstructed sources, the projected startup date is: 2 For existing sources, operation began N T N 3 h N N T N a 0 .0 N 0 a 0 N N O z O N N N m O G E zW N N/ / O C N/ O F L PNp ., (� c o d COO Li W PU. > m d \ •� C - N a\ �\C W td a O O s 0 ,. go'� N W EA oO N . O N N 6~9 .0 00 U =O O Q5 o — _ O ro to �N V^ ^.n N NO w V O\ O\ f \N n rn 4 h C t 0 0. O 0 0 p _ d vv $ G 0 0 n0 N ti F j c � 3 cdjd 3 _ En q cc N O o 0 W G Q G 0 c 0 N N O O 06.1 U 0 e 0 a N .G o G N 0 od N N O N N 9 N O Nco Et, N O N O 3 3 O 0, C 0 '60 'C Eo _ _c o E F0. co ,„ C = Z 0 O O O z N N E c N No co) 0- 0' . Z_ N 'c 0 0. ra- G 9 tri o N > _ > y ' 3 , ine Information Section 04 — En U 0 N w 3 O q N _ 0 O C P 0 N N ra Waukesha Manufacturer: ❑❑ N 0, c N = 3 G 0 No on ❑ S d 0. O .O 0 O C O y G 0 a U ❑ Engine function 0.' N X N N J 0 O O 0.0 C0 0, NN 9'0 0 0 T T 0. G. 0 0 N _ d G. 0 0 0 0 0 _c 0 0 N d U U ®® ND 00 1/40 00 N G 0 rop > X N E. a F CI co o co v U N J ®❑ 0 O o. O .= a N N N 0 .- U a d N V] O F o ❑ ❑ N1 V0 N N G N a N N P N N N . 0. E N a cno N w' o H p N C C N ._ = C .o T b a z W N T 0 x C What is the maximum number of hours this engine is used for emergency back—up power? N N C\1 OO Liz ef+ ti ci FORM APCD-201 .5 Internal Combustion En Permit Number: with relevant information in the event of multiple stacks; provide datum & either Lat/Long or UTM Section 05 — Stack Information (Attach a separate she 0 m 4 O ▪ '4 U E i8 WS o la 0 W CO O O o � to r to 4, b � M an 00 CA 00 N oa 7,3 AiA- . . O Other (Describe 3 O 0 Width (inches) = Other: Length (inches) = Circular: Inner Diameter (inches) = Section 06 — Fuel Consumption Information Seasonal Fuel Use (% of Annual Use) 0 0 N t0 , N N V7 N a) Iry N U I Requested Permit Limit 115.91 MMSCF/yr 13,232 SCF/hr 0 0 s�. Natural Gas O z ❑ Is this engine equipped with an Air/Fuel ratio controller? Section 07 — Emissions Inventory Information & Emission Control Information 0 O a m w a • V 0 d 0 44 0 C W V W 7 u a 4- A A Estimation Method or Emission Factor Source N AP -42 AP -42 Manuf. 7 g 7 al Manuf. AP -42 AP -42 AP -42 • Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested Permitted Emissions I. Controlled Tons/Year N rr N .-1 N .y .+1 OD M .~-1 16.22 O' O 00 O 0.08 0.05 Uncontrolled (Tons/Year) .N -1 .N41 14.r r. .-1 212.52 M N 00 O N 00 O H O H O O O Actual Calendar Year Emissions) Controlled (Tons/Year) Uncontrolled (Tons/Year) Emission Factor Units aO.. i i g/hphr g/hphr a0+ .i O Uncontrolled Basis N ti IN H N .-1 .y LLT en N en N en -` .�1 Control Efficiency (% Reduction) 0 a en In a 76 In 50 +ten Control Device Description Primary Secondary NSCR NSCR NSCR NSCR 1 NSCR NSCR NSCR Q o 0. isn E p ° z VOC CO Formaldehyde Acetaldehyde O 0 < I Benzene 0 0 u u " 'V Q N o a u' L N a -Joy °• o_ • U o G ✓ o 71 O G 40 .0 U d m � U .22 o y�N 7AR 'o ^ O u O 1 w O u 744. a2 C7 Er Section 08 —A Senior Env. S 4) 036 RICEAPiiN.doc N W O N 6) O0 a2 AIRS ID Number: Permit Number: DCP Midstream, LP Company Name: a) Z7 O U a. N a) NWNW Section 27 Township 6N Range 63W Plant Location: Person to Contact: stream.com E V E-mail Address: Controlled Actual Emissions (lbs/year) N v co c..-) Uncontrolled Actual Emissions (lbs/year) co cD t. -- Emission Factor Source c4 v. a a Emission Factor (Include Units) 6.63E-4 lb/MMBtu Control Equipment / Reduction (%) O L Chemical Reporting Abstract Service Chemical Name BIN (CAS) Number a 1,3 -Butadiene d t cfs c:, r Calendar Year for which Actual Data Applies: Reporting Scenario (1, 2 or 3): a) d N a) C a) C O C w L O a) co cn :CS C C - C1 C Cn O a) N O 3 >+ cC CJ) C) J C O a 0 4-- O a) c C Title of Person Legally Authorized to Supply Data 4-. C O_ a) N Ca a) 0 () O Q Q O 0 a) N O 45 > CC co.) a) J O U) L a) 0 O a) CC z ti .� w C) O ri 0 Vet a V O [Leave blank unless APCD has already assigned a permit # & AIRS ID] Permit -Number: tI Facility Equipment ID: C- uested Action (check applicable request boxes) Section 02 — Re Section 01 — Administrative Information Request for NEW permit or newly reported emission source •E ❑ ❑ C u u ° v L. a 0 O R •_, h E .F w = a F' d U 0 .E H F LE a. • 6 aq X a a S u 0 O O u G 0 0 C a' CI s with a Federally enforceable limit on PTE ®❑❑ ❑ ""an .-� d N era 3 t y i 0 O ❑ U O 0 > U Q W zC/D DCP Midstream, LP Source Location: NWNW, Sec. 27, T6N, R63W O L N oCa oo O u O E m W 0 R 0 Ca D7 O U N T O a 0 C c N o O. W at C .0 d u E o a C r z II C) 0 G y ' o W ❑ o 0.5 — o U 0 u ❑ z •'"I 9 O d 9 C o ❑ -7-? .2 0 C y a E 0 Section 03 — General Information N For new or reconstructed sources, the projected startup date i tol 7 days/week v F U N O 1N •u- - 2 >. ❑ o 0J) U C1 w E w bO in -y p W d3 uV CA O V O CC CC ❑ ❑ Y x 3 a E a C C) u a a W ❑ > 3 o w o a ❑ G 9 ≥ o 0 m C ti 0 0 c 3 a 0 U 0 3 3 a. V 0. O O 5-7 -o V 3 0 truction commenced: En O ❑ U 0 0 0 q C) a a °' m w U O ro o �, Q C 0 U 4 0 E °o S q F q F 0) Section 04 — Enable Information O Engine date of manufacture: q F H a 0 N N 0 Waukesha Manufacturer: Y C) 3 0 Ca, a U C) 0 R OD a- - Y uU W w 3 E E Engine function: k a N N epower @ sea level: N N N o E O F. U o Li U 8 o ❑ ❑ C W r ❑ham ❑ 0 o O o I. pc a R P. co m a -O C w w C o R CO0 U a th o ❑ a o O o _C A UU ®® ORM APCD-201 C.) C M O 0) CU U 0 d a, (=1 O a C U o o m © m v7 N J 4M a o w U O h. > N C O s 4 .4 V a. O a a) O oci 4 z G W > Pw O V ttzl 3 U o at O c m - i.: w' o 0 W E"4 o Y a) Qj 1 ,, 1 .:i C r`'+ a i'•7 V Q u R. C 0a O u N CID � eo ti No 0 O -+ O ,o C7 o c � a O o 0 a) 7 O O Q d .c Z 01 0 0 0 = v 0 cc rn O O Q• cv4 o 't a w s CN OT o0 II Q " o o N In a H F 'y' H 0 N cc u 5 w a as N a) aH 2 ci u 0 O 3 m F U � > c' v d U N r N Section 06 — Fuel Consumption Information N U Seasonal Fuel Use (% of Annua O z ') N CA cd 'y N N N 0 O U cn 000 0 a F y o CU 0 o w U L w 0� 0 qc a U Requested Permit Limit 115.91 MMSCF/yr z z ❑ C a f. W H 0 U 0 E. to 0 0 0 a) U a+ O G1 C v .. a w w 0 C) Q q m > E K 'o 0 0 .h u W O at cn A �L ti m 0 13,232 SCF/hr Estimation Method or Emission Factor Source N p5' N cIr-, - N nc1, c I o 4' c *) c N pi., 0- N at d N 1c, Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. �I 6ocad en,ennected emissions. Requested Permitted Emissions Controlled (Tons/Year) — r N H H N H H ZI'T — 0 m r' HI N_ ti 0 0 0 CO o 0 O Uncontrolled (Tons/Year) H H CV H H el H H 212.52 24.33 Oll 0eV Oi cc H H 00 o VC H O V) H O a 0 O ,ac au,.... 1•'•6""' /' IL Actual Calendar Year Emissions' oo 0 0) o t 00 OH PM2 s 1.94E-2 Ib/MMBtu SOx NOx NSCR 96 13.1 g/hphr VOC NSCR 53 1.5 g/hphr CO NSCR 91 11.7 g/liphr Formaldehyde NSCR 76 0.05 g/hphr Acetaldehyde NSCR 50 2.79E-3 lb/MMBtu Acrolein NSCR 50 2.63E-3 Ib/MMBtu Beu ene NSCR 50 1.58E-3 lb/MMBtu Uncontrolled (Tons/Year) 1 CV 0. H Data year for Control Efficiency (% Reduction) a H c C C 0 0 0 e information supplied in se ation contained herein and information submi 7. I 0 0 W W O z z O E Uo a Z C QO U O 0 ao cm dN W� CO Q v O a w W U e Z JO f Z ixw r1 r; AIRS ID Number: Permit Number: DCP Midstream, LP Company Name: O -a O U N 5 O U NWNW Section 27 Township 6N Range 63W Plant Location: Person to Contact: 0 E-mail Address: Uncontrolled Actual Controlled Actual Emissions (lbs/year) Emissions (lbs/year) N CO M oo C0 Emission Factor 1 Emission (Include Units) Factor Source N EL Q 6.63E-4 lb/MMBtu Control Equipment / Reduction (%) O 1.0 Reporting BIN Chemical Name CD C 4) 'a CZ m M Chemical Abstract Service (CAS) Number Q a) 6 O T Calendar Year for which Actual Data Applies: Senior Environmental Specialist 2 a) C) Title of Person Legally Authorized to Supply Data C U) 0 0 CC Cu O CL ci 0 N O C) > Cu 0) C) J O U) C) 0 O C) E CB z ti U G Ey— ck 3 z 0 rif r Ca a Ca CC 0 aL a n u a 0 d b a es — r U Section 02 —Re N 0, G cd .0 9 O N T 0 3 ❑ 0 0 a a W F > o .0 ^ 0 c Py Ca 0 Y U L m F .a0+ y a. E O o ,. L 0 d 3 a E m o g P w d i 05 G 0 g a 0 w o N co, 0 L d ❑ M .d a y w OY N a V., ❑ k y . O C v U H o .00 o E C a. w_ d E Ca at.y o id at ❑ ❑ 1 , a T E 90 i • 3 d 4. al d m W A 5 E a G O c m ..Oi C- C h Y Zi Fa u-• Hd N z 9 ,E y p .P .o ; W a W o ^ n ❑41 TO' a o. .7 y o 'ate c. m 0 O t o„ a O> d z o 0 c 0 o a �� o I y a h QI ri a u 0 0. E Ld W. o c Ca Ca Ca U U v v h a C C O" C 0.1 z o g g❑❑ z ®❑❑ ED 0 W p'1 i N .-I W r an dr O i ?' ❑ _9 0 o U U U QO W ztn DCP Midstream, LP s U Y Source Location: Sec. 27, T6N, R63W N W 0 0 N N 370 17th Street, Suite 2500 U w N 8 Oaa 9 V] N 9 o E C o orft 0p �x ❑ o r O O C 303-605-1716 Phone Number: 303-605-1957 a z Ca 3 0 o U C. wdhill@dcpmidstream.com E-mail Address: N 0 0 a a y 9 ad o, 0 U 5 9 a 0 0 3 0 a 0 m T 0 3 N N 0 r m 9 0 N � ❑ ��Y -0 U h ❑ \'8, w o;a C $ °' .5 ca W w .. • a -0 00 vii ,� pWp�., a �.0 « C W a In 0 U '� a u 3 E x r u 0 ,L ti � o g 0. a❑ o a. O a a E' N y m O 2' 0 b >.o o E d`c ° .ro cu, .2. O L L N tl 0 N >w� E y�U� O U o o c g0.1 r: ,:-.E 8 o,0 .0-c10( O d N q h .C 9 .� W C LON Co 0 U o > PO. itl a o E 'o = 0 o • L E H ,K, o �¢vG L O 5I --CO m u vi V r ^. ra M N N o,Ow \0 ,•09 ,-.:a 01 M 00 c up 01 o o O O O Cch In 0-1 3 0 0 R 0 0 O 0 L :Th3 3 ❑ s m t o E W G �¢ 4 o o 0 to 0 0 V7 F 9 e construction c a O ca 0 0 h m ❑ a o a o ❑ §' o A- t0a O. O E p o '5' .5 0 a .ro a 9 F ° 5 .Q' b 0 o w y O O' 0 UO R a.0 0 'd 4 O 0 0 O c cc a C 0 0 cc,!!,_, 0 3 3 U a C N N O •G a a .G 0 y as to 3 m _ b v g 0 3 'L 0 0 3 0 .% N V.L f 0 C C N 0 cr o 0 o o m m z c7 CI Ca 3 0 z 0 v EC co N E 0 4Z 1 °o cn d 7 o c O (.j V o a ine Information Section 04 — En 0 OD O\ a PZ F'I m .0 a a t.) a a c m o e> ti 0 9 U 0 C C 0 0 w 7 N ti N CO CO Co r` b co o >o .a a o o 3 0 0 co a L 4 0 .O 0 ❑ L c c O U E E . F K ¢ 0 ; .a o a a C. in ,n 2 V X C a 0 m a U U as 0 c2 4 0 ❑ 2 a to c b `a r ll U ti V G 2 m' a 0 0 O O P. O. P. **E! 0 (Csk 9 9 00 0. 6 0 0 22 0 0 .0 .0 0 UU ®® O a 0 a m E U < A � � T a 0 O N 0 0 0 0.0 9, 3 O. /, LC- a I t bfl w • ti 0 C fV K~ x C, 3 O Internal Comb Cd .r WI it rl O 14 O rM a yap re g IS. )71 r._;- Emission Source AIRS ID: Permit Number: e sheet with relevan Section 05 - Stack Information (Attach a separ S z E- ❑ Circular: Inner Diameter (inches) = tion Information Section 06 — Fuel Consum Seasonal Fuel Use (% of Annual Use) > V7 N Mar -May I Jun -Aug 4/1 N V7 N N N N Requested Permit Limit 115.91 MMSCF/yr b 0 O co g U d 13,232 SCF/hr Estimation Method U w " O G cn N N 1 N 4) C N E I. 40 fr o 72 0 14. 0 a, Tel I.4 O u y O W d) 1.. .0.. Co U i.w ® 0 M O 1d w a. en 0 ;zl o O•• v 08 I. 0 o CC U L. Actual Calendar Year Emissions OF N ti N H N H H 00 Cl N N N v6 O\ 0O O N N N N H N N N NN O CC 0\ CC N 000 in O\ 0 O is complete, true and correct. O 4 a .4 O H 0 at a H a. R L O y' N O 'w N 04 a)'W.y r p a. o « nit, o 0 dd Q �O+ O .;' G Ca 8t to 2 a , a a) p y y 7 u )a. O 0 o ..a'a E 61 u q fu.el CC Vs O O as s O O00 p C O a Oea R tli I. 1.. Y O m G U O A co a G, 3 E a) , O Q A O y e) ;::\-.1: O0 2.!,.., A aa O .y. I O N p 0 O1 a0 40 Senior Env. S Natural Gas 'b C Emission Factor Uncontrolled Basis N N-` N N N 1.4 r, N 0 0 en 01 01 4W4 cG ab N .a Emission Factor Documentation attached en ON 0 Control Device Description O a U z a U U U z O 0 L O z U O O U Formaldehyde •o a [ a) 4 03d RICEAPEN.doc H O Z Z — E o 'ii N 27; W E QO U d D c J oD ao CC 43) "73 w CO �' a (13 O a w w I.L o 'z AIRS ID Number: Permit Number: DCP Midstream, LP Company Name: a) C U Q N -O cu c 0 U NWNW Section 27 Township 6N Range 63W Plant Location: Person to Contact: Fax Number: midstream.com U E-mail Address: Controlled Actual Emissions (lbs/year) N "Cr CO M Uncontrolled Actual Emissions (lbs/year) O co 6 N Emission Factor Source N a Q Emission Factor (Include Units) I rek CO 2 CD -13 Control Equipment / Reduction (%) C Reporting BIN Chemical Name 1,3 -Butadiene Chemical Abstract Service (CAS) Number C a on Ci1 Calendar Year for which Actual Data Applies: Reporting Scenario (1, 2 or 3): Senior Environmental Specialist Title of Person Legally Authorized to Supply Data AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — Glycol Dehydration Unit U, 0 O O co co C, M r Emission Source AIRS ID: unless APCD has already assigned a permit q & AIRS ID] Permit Number: vide Facility Equipment ID to identify how this equipment is referenced within your orga Facility Equipment ID: 13 0 9 m JN.i .0 iii F 3 o 0 R a u ❑ E .01.) v o Cl 0 0 ., ^ .=°.. t T O C 2 C , aQ C ❑ o a d E 0 E m , 0 .J .8 0 a u u y m .0 YO N 0 3W O a m A w o n 00 4 W 0 O EU H 20 F L Ln 0 Cl U a e a ❑ ❑ 3 0 w u 0 ii:. "21 m o T t 0 9 u T N a ? R0m 9 w 4"rd E « O, m z CY C 8 W O e 3 ❑ F .. ¢ q a u � o a •^ 0 N 0 vi U 0. O U w O 0 J 8 a s E. 01 E z o W y m g kg «°� z -e d 0 0 0 v ❑ 0 ❑ C EEEE Section 02 — Re Section 01 — Administrative Information Req Z ❑ ❑ ❑ DCP Midstream, LP Wells Ranch Compressor Station Sec. 27, T6N, R63W zu 2 2 z z 3 .3 N it.: 4 u Oto U CO O V N 00 0 U Mailing Address: 370 17th Street, Suite 2500 cpmidstream.com 0 m E op E-mail Address: 20% added to emissions to account for possible changes in gas composition Co ^b Section 03 — General Information en N in . _8_8 O gC O 0 ❑ ❑ ❑ ❑ z z z ❑ ❑ z T Z ®❑ 0 L T 0 m e Co 0 S U O a 0 m 0 0 0 ❑ 0 0 .S -1" M z /attainmaintain.html 0 E C U 0 L o gry0 o v O •S,' C ❑ C -8 O ❑ ❑ z pT q O 0 8. 'C 9 m -N a U a O 0 -- 3 TeS 00 e ay RW oo , Q � N a.0 _ 00 L m ❑ m ❑ 0 u..0❑ g 3 E ^ o a v to y m G p ,p.0 C 7 o G 8 ❑.9gC N C y'� U W e ❑ O S VI o ^ VI ^ r en en m N N N O '0 to 'O'o m m en en o o o oea en en E he.state.co.us/ao/ss/ss N forms: http://www.cdphe.su lication status: http://www.cdp Section 04 — Dehydration Unit Eauinment Information ❑ z N 0 h ❑ H n ti T a O a CO CO In z 0 0 0 0 ❑z h CO a o q F Z o c.3❑.a. m 1G 0. U ❑ U m' 4 0 0 0 y .0 8. ire '❑ 0 0 ft if 0 4U UN U z a a F C N .5d P w O -5 a Cr of 0 0 �✓ o ❑qJ W m 31 trg to 4 a .C 6 C > q O A e:e U vNy q w 'o a a 6' °. C4 ,yu_, m m 'C 3wd(7: Emission Source AIRS ID: AIR POLLUT Section 06 —Stack (Source, if no combustion) Location (Datum & either Lat/Long or UTM) /\ \ \ ! / \ U :f. /F ❑ Vertical with obstructing raincap )\ O° Section 08 — Emissions Inventory Information & Emission Control Information • Estimation Method 4 or Emission Fact r =. Source x' ;t R GLYCaIc `;G; 0000 i1 Please use the APCD Non -Criteria Reportable Mr Pollutant Addendum form to report pollutants not listed above. l_ /\\ Requested Permitted', Emissions Controlled 7 (Tons/Year) 0.55 17.73 u0 4.43 :j; \ ,tr. Uncontrolled (Tons/Year)+' \§f 79.04 99.12 4.28 9k /!§ ;@ Actual Calendar Year Emissions, - ,Controlled;", (Tons/Year) Uncontrolled,, (Tons/Year)' Emission Factor =&u /nU;;c); U»dy 'di `b z § § 9 /m \\[\!) % 10.86 0.47 )S } / c Control Efficiency (% Reduction) " u Sec 'o 07 Control Device Description Primary Secondary ( )/\0\\ » Ethylbenzene Xylene 03 e Dehy APEN.docx O O C N Emission Source AIRS ID: a permit # & AIRS ID] Q Permit Number: uested Action (Check applicable request boxes) Section 02 — Re Section 01— Administrative Information 0 7) aol a ❑ a E- X c m 0. a C C o 0 3 -• a m m E o a 4a a u o 0 C ^ 0a w 0 E & m ti a, ° a ioU r c Po z L a a a E. 0 0, ❑ ❑ a, a L C 7a T ii a s. .3.. N -co aCi a a P W a C o m o Z Cr w r O a 0) .3 0 F o E pWQ, .a. ea 0. w o a or ., ❑ Z 0 can m E iz--4 o F G 0 N i _ a U U a a o' C z z ❑ ❑ z ® ❑ ❑ ❑ en DCP Midstream, LP Wells Ranch Compressor Station d a o Cu z T U N a E cn U b Sec. 27, T6N, R63W z Source Location: v w N fcl CO 370 17`a Street, Suite 2500 N b 00 c Denver, CO hange to perm ❑ U ° N >, 3 O ° C ae U N❑ a d a m .� N O a m o ca i° to U a ❑ ❑ z a 3 Person To Cont Only the fuel conditioning sldd is subject to NSPS KICK Section 03 — General Information en 0 N For new or reconstructed sources, the projected startup date is: 0 ro 00 P C 0 CD 0 U En 0 Cal 0 O E u a.= E z . U E ❑ N Wo � a ai WOi. y `\ C ad' ,tea, u ,�o. « „ `` o y �n a H w z \ m ._ F c°c]]o .,nr .0 W 0.0.�� 0 a> A N N yg 0 , Q tj ❑ 'b L -< ° Le a L°. En y 2 Ce 3 �x ro n o- a u a o a o T o a as a o = a o a ° c mPc. 0 .° a -o a w 0 ,N a 3 N a > .) a3 .. o o U > a '? W e 3 Q N o Q m 3 CIn b To o f v4 o° o a) 00In. 0i 3 ° Q > 4: c E c,.� u ago C a' m R.N. w0 D C = O. a a: I... Cu) 0i O C C o 0 a °' m o m U m .� o a o y a ti 'a W u act U m ro a y o U g C �° r'' N W a a° �r O .o ti C. a F C° CUd V ^i w d vEi d 6 O3 ❑ 30 ❑ 30 ❑ ❑ ❑ O o 0 z z zZi r En 0 r r N o N m Ec 6 c N 0 ry U a 7 y ❑ p ac) O J ❑ v ❑ ca Z E T, ry :J C O 0 a ❑ a a O a P O a O V] O 0 ❑ 0 0 .� O x 0 mo t z w G 0 0 00 Q a - Q 0 N o m N E a a' 3 ° 3 En Pp 3c Information Section 04 — Re Is this equipment subject to NSPS 40 CFR Part 60, Subpart Is this equipment subject to NESHAP 40 CFR Part 63, Subpart HFI'l Subpart that applies to this equipment List any other NSPS or NES Section 05 — Stream Constituents 8 a m O O ozs F E L d° X � na 0 0 C a W 0 0 U N O U ❑ ❑ U y A a o O 0 0 0. a G o. a m c 0 0 T T a a 0 0 O 0 0 0 0 O O P .O U N U U N 0 N O O N 9 N a N X". L O 9 E .57 a fat ° 0 N U 0 En a 0 a 0 W M 'a 7 N >, N Y N a b CI) C) 00 p N N N 0 U :.o P❑ CD CO 1fl cc! I FORM APCD-203 r=i 17-1' ,;,j :1.111. J2 & Control Information Permit Number: a) ) a) U .b 0 -40 0 . LPL o 0 aa U A 0 OS d) a. oR 0 ry� U a O a O z ti z 0 9 .0 O El Et 0 g a a00 . Vl O > 0 9 > eya a. m o0 � e 0 r. O t� " io 4-4 • tab E q 0 0 o z , 01 04. ❑❑ r L R 00 C O o ta 0on o 0 Section 08 — Emission Factor Information 713 L i. 0 w C O y 5 d d 0 44 C b 0 C O U Actual Count conducted on the following date O 0 U a CO N "t Estimated Count • C 0 0 x � W e0 C O U a) 4.0 N Open -Ended Lines O cn a a O M Estimation Method 15 y po 0 p C .y C a c a R p d q rK U .. f7' a a O h .2 ecl 0 C v E 0 o. 8 10 D 0 7,1 u � F )0 _ y u j`o I h 1 0 COI }' pq C 44 0 q 0 CE' Emission Factor Documentation attached Emission Factor C Uncontrolled Basis u C a4 0 .O C x 6l C C C co C. 0 a aa 0 E 0 2 7 v C a) 'U d i i.4 L. a i i. O Q. u !Yi m U C z U 0 .0 d C d y C rs 0 0 a U O a) C a) a) N C a) a) ; aJ A 7." G O m CS .., 74 1444 O U O. C dJ � � W ai o 0 U 0 ' 2 � O _ w N a O O U a o0) u • a 0) —. 'y U g g 5 O y U m W u 8 M ,63 cs 2 22 O � N W •' R N a) U a Q.5 o0 O IA N N ^� d d 3•v v O� yd P. g. g T 0 4) of Internal Combustion En nested Action (check applicable request boxes) Section 02 — Re ® Request for NEW permit or newly reported emission source Request PORTABLE source permit a u a 4 0 0 X Ga 0 ["i X n Go O .- G = y O .0 C • U = ? "C a c 0?' v .c 8 0 a v m Al V u •0 C Co L t n C u U F a T F;] Q 0 0 a U a- z 7. 8 o w R E O m cn= C O C r0 s.0.. U U u a C ❑ ❑ C V 0. R C e u 0 c Y u V T °I!) J, CC a z w a a d ❑ ❑ ❑ ❑ con O J a UU ti z� 3 Source Location: CS IL O R 0 O 61 cn O 0 E p O r= z L N O 0 ca U 0, N 370 17u' Street, Suite 2500 Mailing Address: T 0 • T > o 0. u 6- > _ ._ C N E 5' V C, O c C c C r H V J O n s T n c v c V o Ili R 4 n o } o o o o 22 o C O J 0 R C 0 53 rr ❑ ❑ AOS permanent replacement V T a cen 0 n C 0 C 0 T. 0 V 0 C ✓ o, c V F U L N o ° u •o C cac C ca a C Y 0 .'s 0.l P. z . `b -0 V ❑ Q .5 z 303-605-1957 Fax Number wdhill@depmidstream.com Section 03 — General Information For new or reconstructed sources, the projected startup date is: U a C) 3 Y 3 i a N a T E C 0 J U COI -- E cu 0— .00 CC 0 N Z C 0,00 f? co co 0 N N C c N Go o' C co \n O y c G • 0 0 = 00 G 0 0 0 0- a fn 0 0, co - 0, w G ry tr - ❑z] G cs t 0. L. a- 4 O io. u 0 N. o s 2 = _ U U �71...4. .'J r" 0 C 'c R -74 r W u " — 0 O J > U "� L m O E Ca > en y Q 3 o H o E ov o N C E c... U w o U" v Q ` O c ,_ .c 0 vi „,..vu � - CCU co E om 74 O Q O C 00 R 0y U 6e O LL. APEN forms: http:IA Application status: h Q 07 F C F ci ti c o 0 0 E 0 U C-0 a J era o a ° V ,E. v J a U o g R O u " 9 w O 0 E O = o to 0 0 3 3 = O R 0 0 '0 o0 m OS 0in -8 0 a c o e o J —C L o0 CI 0 C U J kCI z ( 4 O C. 0 CS" C a C 00 In a8 42 zE a C C E. c U a CC O J C 0 Cr C. V Q > N 3J ine Information Section 04 —En 0 J CO Cc c C :1 F F z C U a o 0 El Manufacturer: ❑❑ O " E CO L ❑ ❑ V g d-• a 0 0 cn 00 0 0 cc 00 v, w N c 0 a 0 o 4 0 o v U g ®❑ R 04 O C 2 V 2 U U U O U 0 C u 043. h a O O a a €€ R R O w q 9 -0 -0 w W O 0 0 CI CS " CC 0 0- 0 0 0.0 0 C.0 CI UU _ Y U 0 N N 0 0 C F U ❑❑ X X iy = F 8, in in •. " N 0 = C V U 0 'Z J a C C C cC T 0 O What is the maximum number of hours this engine is used for emergency back—up power? FORM APCD-201 RICFAPFN-Wells Ranch ➢ackup.tloc N O m c. Hello