MEMORANDUM January 6, Phillip Fielder, P.E., Permits and Engineering Group Manager

DRAFT OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION MEMORANDUM January 6, 2014 TO: THROUGH: THROUGH: THROUGH: FROM: SUBJECT: Phillip Fielder, P.E., Permits and Engineering Group Manager Kendal Stegmann, Senior Environmental Manager Compliance and Enforcement Phil Martin, P.E., Engineering Manager, Existing Source Permits Section Peer Review Amalia Talty, E.I, Existing Source Permits Section Evaluation of Permit Application No. 2013-1557-TVR2 DCP Midstream, LP Okarche Natural Gas Processing Plant (SIC 1321) NE/4 of Section 31, T15N, R8W, Kingfisher County, Oklahoma Latitude: 35.734 N, Longitude: 98.086 W Directions: From W 248 th St (Oklahoma St) and US 81 (Main St) located in the center of Okarche, OK., go six (6) miles west on W 248 th St., then turn north and drive six tenths (0.6) of a mile on N2760 Rd to the Facility on the left. SECTION I. INTRODUCTION DCP Midstream, LP (DCP) has applied for a renewed Title V operating permit for their Okarche Natural Gas Processing Plant. The facility is currently operating under Permit No. 2008-178- TVR issued on April 7, 2009. There have been no major changes to the site since issuance of Permit No. 2008-178-TVR and the permit has been updated with the latest State of Oklahoma and Federal regulations. SECTION II. FACILITY DESCRIPTION The facility is a natural gas processing plant that extracts hydrocarbon liquids from raw natural gas streams. The raw natural gas streams received from surrounding booster stations are combined and processed to produce four product streams: a high methane-content residue gas stream for sale as natural gas; a natural gas liquids product stream for sale; a slop oil stream which is sold to refineries; and a wastewater stream. Upon entering the plant, entrained liquids are separated from the raw natural gas stream in the inlet separator. This results in a gas stream, a liquid hydrocarbon stream (condensate), and a wastewater stream. The gas stream is routed through a molecular sieve bed to remove water, and then cooled

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 2 using a closed loop propane refrigeration system (TURB-03). The cooled gas stream is further cooled through expansion, causing natural gas liquids to condense from the gas. Natural gas liquids are removed from the remaining high methane-content residue gas in the cold separator. The high methane-content residue gas stream is then recompressed (TURB-01, TURB-02, and ENG-01 through ENG-04) for pipeline sale. The natural gas liquids are treated to remove CO 2 and H 2 S in the amine treater. After removal of the CO 2 and H 2 S, the natural gas liquids stream is dried in the molecular sieve, transferred to pressure vessels and pumped into a pipeline for sale. The condensate stream is stabilized by distillation to remove the natural gas liquids. After the natural gas liquids have been driven off, the remaining stabilized condensate (slop oil) is stored in two 1,000-bbl tanks (TNK-01 and TNK-02) prior to sale. It is transported off-site by tank truck (LOAD-01). The stabilizer overhead vapors are condensed and combined with the natural gas liquid product. The wastewater stream may contain methanol depending on the time of year. During winter months, methanol is injected at the booster stations to prevent hydration of the raw natural gas. When present, the methanol is removed from collected wastewater in the methanol still. Recovered methanol is stored in a 300-bbl atmospheric tank (TNK-07). After methanol is removed, the water stream is further treated in an oil water separator. Oil removed in the separator is sent to the slop oil tanks (TNK-01 and TNK-02). Slop oil from booster stations is brought to Okarche and stored in two 300-bbl tanks (TNK-03 and TNK-04). This slop oil is then processed in the heater treater to remove water. The treated slop oil is temporarily stored in a 300-bbl tank (TNK-05), prior to being transferred to the two 1,000-bbl stabilized condensate (slop oil) tanks (TNK-01 and TNK-02). The molecular sieve beds when saturated are regenerated by heating a portion of the dehydrated inlet gas stream in the regeneration gas heater (HTR-01), and then routing the heated gas through the beds. The heated gas is then cooled to condense and remove the water, and recombined with the inlet gas stream. Rich amine is regenerated to remove the CO 2 and H 2 S by heating the amine using hot oil from the hot oil heater (HTR-02). The gas stream generated in this process is burned as fuel in the Hot Oil Heater or combusted in the plant flare during upset conditions. SECTION III. EQUIPMENT Emission sources have been organized into the 7 Emission Unit Groups (EUGs) identified below EUG-01: Turbine Engines EUG-02: Internal Combustion Engines EUG-03: Storage Tanks EUG-04: Heaters EUG-05: Flares EUG-06: Fugitive emissions EUG-07: Truck loading

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 3 EUG-01: Turbine Engines EU ID# Point ID# Description Serial Number Mfg. Date TURB-01 TURB-01 4,707-hp Murray Solar Turbine 3001102 2005 TURB-02 TURB-02 4,707-hp Murray Solar Turbine OHC06-C0038 2006 TURB-03 TURB-03 3,879-hp York Solar Turbine 4180C42 1999 EUG-02: Internal Combustion Engines EU ID# Point ID# Description Serial Number Mfg. Date ENG-01 ENG-01 687-hp Waukesha L-7042 w/cc 161584 1993 ENG-02 ENG-02 687-hp Waukesha L-7042 w/cc 296865 1993 ENG-03 ENG-03 687-hp Waukesha L-7042 w/cc 327586 1993 ENG-04 ENG-04 687-hp Waukesha L-7042 w/cc 366318 2004 w/cc equipped with non-selective catalytic reduction (NSCR) catalytic converter EUG-03: Storage Tanks EU ID# Point ID# Contents Capacity Barrels Gallons Mfg. Date TNK-01 TNK-01 North Condensate / Slop Oil 1000 42,000 2003 TNK-02 TNK-02 South Condensate / Slop Oil 1000 42,000 2003 TNK-03 TNK-03 Southeast Condensate / Slop Oil 1000 42,000 1981 TNK-04 TNK-04 Center Condensate/Slop Oil 300 12,600 1981 TNK-05 TNK-05 Treated Condensate & Slop Oil 300 12,600 1981 TNK-06 TNK-06 Field Wastewater 300 12,600 1981 TNK-07 TNK-07 East Methanol/Water 300 12,600 1981 TNK-08 TNK-08 West Methanol/Water 300 12,600 1981 TNK-09 TNK-09 Plant Wastewater East 300 12,600 1981 TNK-10 TNK-10 Plant Wastewater West 300 12,600 1981 TNK-11 TNK-11 Methanol 300 12,600 1981 TNK-12 TNK-12 Amine 300 12,600 1981 EUG-04a: Heaters (Considered Insignificant Activities) Badgett 31 #4H EU ID# Point ID# Description MMBTUH Mfg. Date HTR-01 HTR-01 Gas Dehy Regen Heater 7.32 1981 HTR-03 HTR-03 Slop Oil Heater Treater 0.50 1981 HTR-04 HTR-04 Product Dehy Regen Heater 4.80 1981 EUG-04b: Heaters (Requires Emission Limits) EU ID# Point ID# Description MMBTUH Mfg. Date HTR-02 HTR-02 Hot Oil Heater 20.00 1981 EUG-05: Flares EU ID# Point ID# Description MMBTUH Mfg. Date Flare-01 Flare-01 Process Flare 22.03 1981

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 4 EUG-06: Fugitive VOC Emission Sources EU ID# Point ID# Equipment Number Const. Date Valves Inlet Gas 1177 1981 Valves Liquid 1391 1981 Pressure Relieve Valves 109 1981 Pump Seals 28 1981 FUG-01 FUG-01 Compressor Seals 31 1981 Flanges/Connections Inlet Gas 2793 1981 Flanges/Connections Liquid 3628 1981 Valves Inlet Gas 1177 1981 Valves Liquid 1391 1981 EUG-07: Truck Loading EU ID# Point ID# Equipment Const. Date LOAD-01 LOAD-01 Truck Loadout 1981 Stack Parameters EU ID# Source (make/model) Height (feet) Dia. (inches) Flow (ACFM) Temp ( F) TURB-01 Murray Solar Turbine 29 3.33 60,090 241 TURB-02 Murray Solar Turbine 29 3.33 60,090 241 TURB-03 York Solar Turbine 29 3.33 47,039 340 ENG-01 Waukesha L-7042 w/cc 13 0.80 2,720 933 ENG-02 Waukesha L-7042 w/cc 13 0.80 2,720 933 ENG-03 Waukesha L-7042 w/cc 13 0.80 2,720 933 ENG-04 Waukesha L-7042 w/cc 13 0.80 2,720 933 w/cc - with catalytic converter SECTION IV. AIR EMISSIONS Emissions estimates for the Turbine and reciprocating engines are based on the emission data in the following table and continuous operation. Emission estimates for the tanks are based on EPA TANKS 3.1 and estimated throughputs. VOC emissions from TNK-1 and TNK-2 are routed to Flare-01 by a vapor recovery system. Flare emissions are estimated using AP-42 (1/95) Section, 13.5 emission factors. Heater emissions are based on AP-42, Section 1.4 (7/98). SO 2 and H 2 S emissions from HTR-02 are based on a H 2 S concentration of 4 ppmv in the inlet gas, a processing rate of 165 MMSCFD, a mass balance, and a control efficiency of 95%. Fugitive VOC emissions are based on EPA s 1995 Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-017), estimates of the number of process components, and an estimated fraction of C3+ as shown in the following table. Loadout emissions are estimated using AP-42 (1/95), Section 5.2 and an estimated raw condensate throughput of 3,150,000 gal/yr and stabilized condensate throughput of 8,400,000 gal/yr.

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 5 Engine Emission Factors NO X CO VOC EU ID # Name/Model (g/hp-hr) (g/hp-hr) (g/hp-hr) TURB-01 & -02 4,707-hp Murray Solar Turbine 2.0 0.9 0.7 TURB-03 3,879-hp York Solar Turbine 2.0 0.9 0.7 ENG 01-04 687-hp Waukesha L-7042 w/cc 2.3 3.5 1.0 w/cc with catalytic converter Fugitive VOC Emissions Component Type Count C 3+ Content Emission Factors (lbs/hr/source) Hourly Emissions (lb/hr) Annual Emissions (TPY) Valves Inlet Gas 1177 13.31 0.00992 3.76 16.47 Valves Liquid 1391 100.00 0.00550 7.55 33.09 Pressure Relieve Valves 109 13.31 0.0194 1.26 5.51 Pump Seals 28 100.00 0.02866 0.80 3.51 Compressor Seals 31 13.31 0.0194 0.14 0.62 Flanges/Connections Inlet Gas 2793 13.31 0.00086 0.69 3.00 Flanges/Connections Liquid 3628 100.00 0.00024 0.86 3.77 Total Fugitive Emissions 15.06 65.97 The primary HAP emission from this facility is formaldehyde. Emissions of formaldehyde from the engines were calculated using the 4-stroke rich-burn engine factor of 0.0205 lb/mmbtu from AP-42 (7/00), Section 3.2, for a heat input of 7.24 MMBTUH for the 687-hp Waukesha L- 7042 engines. Emissions of formaldehyde from the turbines were calculated using AP-42 (4/00), Section 3.1. Emissions of formaldehyde from the heaters were calculated using AP-42 (7/98), Section 1.4. The following table lists estimated formaldehyde emissions for the turbines, the engines, and the boilers. HAPs emissions do not exceed 10/25 TPY. The facility, therefore, is not a major source of HAPs. Hazardous Air Pollutants (HAPs) Sources Formaldehyde lbs/hr TPY TURB-01 0.03 0.13 TURB-02 0.03 0.13 TURB-03 0.03 0.11 ENG-01 0.11 0.46 ENG-02 0.11 0.46 ENG-03 0.11 0.46 ENG-04 0.11 0.46 HTR-01 0.04 0.18 HTR-02 0.11 0.48 HTR-03 0.01 0.01 HTR-04 0.03 0.12 Total 0.71 3.0

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 6 Greenhouse Gases (GHS) All CO 2e emissions from combustion of natural gas are based on the default factors for natural gas combustion from 40 CFR Part 98, Subpart C, Tables C-1 and C-2 and the related global warming potential factors from 40 CFR Part 98, Subpart A, Table A-1. Emissions for the amine unit, tanks and loading were calculated from data from the HYSYS simulation model. All other CO 2e emissions are related to CO 2 or CH 4 emissions and the related global warming potential factor. GHG Emission Source CO 2e TPY TURB-01 23,078 TURB-02 23,078 TURB-03 18,792 ENG-01 2,548 ENG-02 2,548 ENG-03 2,548 ENG-04 2,548 HTR-01 3,751 HTR-03 256 HTR-04 2,460 HTR-02 10,250 Amine Unit 4,643.28 TNK-01 22.74 TNK-02 22.74 TNK-03 3.85 TNK-04 11.43 TNK-05 0.00 TNK-06 1.56 TNK-07 1.56 TNK-08 1.56 TNK-09 1.56 TNK-10 1.56 Loading 23.71 Venting & Blowdowns 33,359.46 Fugitives 1,905.73 Total Emissions 131,858

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 7 Facility Wide Emissions EU ID# NO x CO VOC lb/hr TPY lb/hr TPY lb/hr TPY TURB-01 19.22 84.2 8.65 37.90 6.73 29.47 TURB-02 19.22 84.2 8.65 37.90 6.73 29.47 TURB-03 17.10 74.91 7.70 33.71 5.99 26.22 ENG-01 3.48 15.26 5.30 23.22 1.51 6.63 ENG-02 3.48 15.26 5.30 23.22 1.51 6.63 ENG-03 3.48 15.26 5.30 23.22 1.51 6.63 ENG-04 3.48 15.26 5.30 23.22 1.51 6.63 TNK-03 -- -- -- -- 0.85 3.8 TNK-04 -- -- -- -- 0.85 3.8 TNK-07/08 -- -- -- -- 0.03 0.1 TNK-09/10 -- -- -- -- 0.03 0.1 HTR-01 0.73 3.2 0.62 2.7 0.04 0.2 HTR-02 2.00 8.8 1.68 7.4 0.11 0.5 HTR-03 0.05 0.2 0.04 0.2 0.00 0.0 HTR-04 0.48 2.1 0.40 1.8 0.03 0.1 FLARE-01 1.57 6.86 8.52 37.32 1.45 6.35 E-FUG-1 -- -- -- -- 15.06 65.97 E-LOAD-1 -- -- -- -- -- 7.9 Total 74.29 325.51 57.46 251.81 43.94 200.50 SO EU 2 H 2 S lb/hr TPY lb/hr TPY Amine Unit to HTR-02/ FLARE-01 4.41 19.32 0.12 0.54 SECTION V. PSD REVIEW In 1981, the originally-installed equipment at this facility had emissions of 228 TPY of NO x and 84 TPY of CO which is less than the PSD threshold of 250 TPY. Each subsequent modification was evaluated for PSD applicability, beginning with the April 1992 modification that increased NO x emissions to 281 TPY and CO emissions to 163 TPY. A February 1997 modification reduced NO x emissions to 272 TPY and increased CO emissions to 164 TPY. Another modification was completed in July 1998, when NO x emissions were reduced to 224 TPY and CO emissions to 108 TPY. Most recently, modifications and changes in emission factors authorized by Construction Permit # 96-400-C (M-1) represented an increase in emissions of less than 250 TPY for each criteria pollutant and was not subject to PSD review. After that modification, the facility-wide NO x emissions are greater than 250 TPY, and the facility is classified as a major source under PSD. All future modifications to the facility will be subject to PSD review if proposed emission increases exceed the established PSD significance levels of 40 TPY NO x, 100 TPY CO, 40 TPY VOC and 75,000 TPY CO 2 e.

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 8 SECTION VI. INSIGNIFICANT ACTIVITIES The insignificant activities identified and justified on Part 1b of the Title V application forms are duplicated below. Appropriate recordkeeping of activities indicated below with * is specified in the Specific Conditions. * Space heaters, boilers, process heaters, and emergency flares less than or equal to 5 MMBTUH heat input (commercial natural gas). The slop oil heater and the dehy regen heater are rated less than 5 MMBTUH. * Emissions from crude oil and condensate storage tanks with a capacity of less than or equal to 420,000 gallons that store crude oil and condensate prior to custody transfer as defined by Subpart Kb. Condensate tanks 3, 4, and 5 store condensate prior to custody transfer and each has a capacity of less than 420,000 gallons. * Emissions from storage tanks constructed with a capacity less than 39,894 gallons which store a VOC with a vapor pressure less than 1.5 psia at maximum storage temperature. The amine and waste water tanks, have capacities less than 39,894 gallons and store products having a vapor pressure less than 1.5 psia. * Activities that have the potential to emit no more than 5 TPY (actual) of any criteria pollutant. The methanol tank has the potential to emit less than 5 TPY of any criteria pollutant and other activities may be used in the future. SECTION VII. OKLAHOMA AIR POLLUTION CONTROL RULES OAC 252:100-1 (General Provisions) Subchapter 1 includes definitions but there are no regulatory requirements. [Applicable] OAC 252:100-2 (Incorporation by Reference) [Applicable] This subchapter incorporates by reference applicable provisions of Title 40 of the Code of Federal Regulations. These requirements are addressed in the Federal Regulations section. OAC 252:100-3 (Air Quality Standards and Increments) [Applicable] Primary Standards are in Appendix E and Secondary Standards are in Appendix F of the Air Pollution Control Rules. At this time, all of Oklahoma is in attainment of these standards. OAC 252:100-5 (Registration, Emissions Inventory and Annual Operating Fees) [Applicable] Subchapter 5 requires sources of air contaminants to register with Air Quality, file emission inventories annually, and pay annual operating fees based upon total annual emissions of regulated pollutants. Emission inventories have been submitted and fees paid for the past years. OAC 252:100-8 (Permits for Part 70 Sources) [Applicable] Part 5 includes the general administrative requirements for part 70 permits. Any planned changes in the operation of the facility which result in emissions not authorized in the permit and which exceed the Insignificant Activities or Trivial Activities thresholds require prior

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 9 notification to AQD and may require a permit modification. Insignificant activities mean individual emission units that either are on the list in Appendix I (OAC 252:100) or whose actual calendar year emissions do not exceed the following limits: 5 TPY of any one criteria pollutant 2 TPY of any one hazardous air pollutant (HAP) or 5 TPY of multiple HAPs or 20% of any threshold less than 10 TPY for a HAP that the EPA may establish by rule Emissions limitations have been established based on Permit No. 2008-178-TVR and information contained in the permit application. OAC 252:100-9 (Excess Emission Reporting Requirements) [Applicable] Except as provided in OAC 252:100-9-7(a)(1), the owner or operator of a source of excess emissions shall notify the Director as soon as possible but no later than 4:30 p.m. the following working day of the first occurrence of excess emissions in each excess emission event. No later than thirty (30) calendar days after the start of any excess emission event, the owner or operator of an air contaminant source from which excess emissions have occurred shall submit a report for each excess emission event describing the extent of the event and the actions taken by the owner or operator of the facility in response to this event. Request for affirmative defense, as described in OAC 252:100-9-8, shall be included in the excess emission event report. Additional reporting may be required in the case of ongoing emission events and in the case of excess emissions reporting required by 40 CFR Parts 60, 61, or 63. OAC 252:100-13 (Open Burning) [Applicable] Open burning of refuse and other combustible material is prohibited except as authorized in the specific examples and under the conditions listed in this subchapter. OAC 252:100-19 (Particulate Matter) [Applicable] This subchapter limits particulate emissions from fuel-burning equipment with a rated heat input of 10 MMBTUH and less to 0.6 lb/mmbtu. For 2 cycle and 4 cycle engines, AP-42 (7/00), Section 3.2 lists the total PM emissions to be less than 0.05 lbs/mmbtu. AP-42 (7/98), Table 1.4-1 lists natural gas PM emissions from external combustion sources to be 7.6 lb/mmscf or about 0.0076 lb/mmbtu. The permit requires the use of natural gas for all fuel-burning equipment to ensure compliance with Subchapter 19. OAC 252:100-25 (Visible Emissions and Particulates) [Applicable] No discharge of greater than 20% opacity is allowed except for short-term occurrences which consist of not more than one six-minute period in any consecutive 60 minutes, not to exceed three such periods in any consecutive 24 hours. In no case, shall the average of any six-minute period exceed 60% opacity. When burning natural gas there is little possibility of exceeding the opacity standards. OAC 252:100-29 (Fugitive Dust) [Applicable] No person shall cause or permit the discharge of any visible fugitive dust emissions beyond the property line on which the emissions originate in such a manner as to damage or to interfere with

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 10 the use of adjacent properties, or cause air quality standards to be exceeded, or interfere with the maintenance of air quality standards. Under normal operating conditions, this facility will not cause a problem in this area, therefore it is not necessary to require specific precautions to be taken. OAC 252:100-31 (Sulfur Compounds) [Applicable] Part 2 limits the ambient air impact of sulfur dioxide (SO 2 ) emissions from any existing facility or any new petroleum and natural gas process facility subject to OAC 252:100-31-26(a)(1). This part also limits the impact of hydrogen sulfide (H 2 S) emissions from any new or existing source. Modeling was conducted prior to the issuance of Permit No. 2008-178-TVR. An analysis was performed using SCREEN3 to show the impacts of the facility on the ambient air as shown below. Ambient Impacts of SO 2 Standard Impact Averaging Time g/m 3 g/m 3 5-Minute 1,300 32.68 1-hour 1,200 19.88 3-hour 650 17.89 24-hour 130 7.95 Ambient Impacts of H 2 S Standard Impact Averaging Time g/m 3 g/m 3 24-hour 278 0.16 Part 5 limits sulfur dioxide emissions from new equipment (constructed after July 1, 1972). For gaseous fuels the limit is 0.2 lb/mmbtu heat input averaged over 3 hours. For fuel gas having a gross calorific value of 1,000 BTU/SCF, this limit corresponds to fuel sulfur content of 1,203 ppmv. Thus, a limitation of 343 ppmv sulfur in a field gas supply will be in compliance. The permit requires the use of pipeline-grade natural gas or field gas with a maximum sulfur content of 343 ppmv for all fuel-burning equipment to ensure compliance with Subchapter 31. Part 5 requires removal or oxidation of hydrogen sulfide (H 2 S) from the exhaust gas of any new petroleum or natural gas process equipment. This part allows direct oxidation of H 2 S to sulfur dioxide (SO 2 ), without sulfur recovery, when the exhaust gas will contain no more than 100 lbs/hr SO 2 (2-hour average). Compliance with the 100 lb/hr can be demonstrated by establishing that the acid gas stream contains 0.54 long tons per day (LTD) of sulfur (S) or less. Oxidation of the H 2 S must be conducted in a system that assures at least a 95% reduction of the H 2 S in the exhaust gases. These requirements do not apply if H 2 S emissions do not exceed 0.3 lb/hr. Part 5 also requires any natural gas processing facilities subject to OAC 252:100-31-26 to install, calibrate, maintain, and operate an alarm system which will signal non-combustion of the exhaust

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 11 gas from the amine unit. The HTR-02 has an alarm to signal when the pilot light is not present and the permit requires an alarm system on the HTR-02 to signal non-combustion of the exhaust gases. OAC 252:100-33 (Nitrogen Oxides) [Not Applicable] This subchapter limits new gas-fired fuel-burning equipment with rated heat input greater than or equal to 50 MMBTUH to emissions of 0.2 lb of NO x per MMBTU. There are no equipment items that exceed the 50 MMBTUH threshold. OAC 252:100-35 (Carbon Monoxide) [Not Applicable] This facility has none of the affected sources: gray iron cupola, blast furnace, basic oxygen furnace, petroleum catalytic cracking unit, or petroleum catalytic reforming unit. OAC 252:100-37 (Volatile Organic Compounds) [Applicable] Part 3 requires storage tanks constructed after December 28, 1974, with a capacity of 400 gallons or more and storing a VOC with a vapor pressure greater than 1.5 psia at maximum storage temperature to be equipped with a permanent submerged fill pipe or with an organic vapor recovery system. The condensate/slop oil and the methanol tanks are subject to this requirement. Part 3 requires VOC loading facilities with a throughput equal to or less than 40,000 gallons per day to be equipped with a system for submerged filling of tank trucks or trailers if the capacity of the vehicle is greater than 200 gallons. This facility does not have the physical equipment (loading arm and pump) to conduct this type of loading and is not subject to this requirement. Part 5 limits the VOC content of coatings used in coating lines or operations. This facility does not normally conduct coating or painting operations except for routine maintenance of the facility and equipment, which is exempt. Part 7 requires fuel-burning and refuse-burning equipment to be operated and maintained so as to minimize emissions. Temperature and available air must be sufficient to provide essentially complete combustion. All compressor engines and heaters are subject to this requirement. Part 7 requires all effluent water separator openings which receive water containing more than 200 gallons per day of any VOC, to be sealed or the separator to be equipped with an external floating roof or a fixed roof with an internal floating roof or a vapor recovery system. There is an oil water separator at the facility and it is a sealed vessel as required by this subpart. OAC 252:100-42 (Toxic Air Contaminants (TAC)) [Applicable] This subchapter regulates toxic air contaminants (TAC) that are emitted into the ambient air in areas of concern (AOC). Any work practice, material substitution, or control equipment required by the Department prior to June 11, 2004, to control a TAC, shall be retained, unless a modification is approved by the Director. Since no AOC has been designated there are no specific requirements for this facility at this time.

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 12 OAC 252:100-43 (Testing, Monitoring, and Recordkeeping) [Applicable] This subchapter provides general requirements for testing, monitoring and recordkeeping and applies to any testing, monitoring or recordkeeping activity conducted at any stationary source. To determine compliance with emissions limitations or standards, the Air Quality Director may require the owner or operator of any source in the state of Oklahoma to install, maintain and operate monitoring equipment or to conduct tests, including stack tests, of the air contaminant source. All required testing must be conducted by methods approved by the Air Quality Director and under the direction of qualified personnel. A notice-of-intent to test and a testing protocol shall be submitted to Air Quality at least 30 days prior to any EPA Reference Method stack tests. Emissions and other data required to demonstrate compliance with any federal or state emission limit or standard, or any requirement set forth in a valid permit shall be recorded, maintained, and submitted as required by this subchapter, an applicable rule, or permit requirement. Data from any required testing or monitoring not conducted in accordance with the provisions of this subchapter shall be considered invalid. Nothing shall preclude the use, including the exclusive use, of any credible evidence or information relevant to whether a source would have been in compliance with applicable requirements if the appropriate performance or compliance test or procedure had been performed. The following Oklahoma Air Pollution Control Rules are not applicable to this facility: OAC 252:100-11 Alternative Emissions Reduction not requested OAC 252:100-15 Mobile Sources not in source category OAC 252:100-23 Cotton Gins not type of emission unit OAC 252:100-24 Grain Elevators not in source category OAC 252:100-39 Nonattainment Areas not in area category OAC 252:100-47 Landfills not in source category SECTION VIII. FEDERAL REGULATIONS PSD, 40 CFR Part 52 [Applicable] The total emissions are greater than the PSD threshold level of 250 TPY of NO x and the facility is a Major Source under PSD. Any future emission increases must be evaluated for PSD if they exceed a significance level (100 TPY CO, 40 TPY NO x, 40 TPY SO 2, 40 TPY VOC, 25 TPY PM, 15 TPY PM 10, 0.6 TPY lead, 75,000 TPY CO 2 e). NSPS, 40 CFR Part 60 [Subparts Kb, GG, ZZZZ are Applicable] Subpart Dc, Industrial-Commercial-Institutional Steam Generating Units. This subpart affects industrial-commercial-institutional steam generating units with a design capacity between 10 and 100 MMBTUH heat input and which commenced construction or modification after June 9, 1989. All of the heaters were manufactured prior to June 9, 1989 and therefore are not subject to this subpart.

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 13 Subparts K, Ka, Kb, VOL Storage Vessels. All the tanks except TNK-01 and TNK-02 at the site are not subject because they were either constructed prior to the effective dates of these standards, they store natural gas condensate prior to custody transfer, or they are smaller than the de minimis size (19,813 gallons). TNK-01 and TNK-02 are subject to Subpart Kb. Subpart GG, Stationary Gas Turbines. This subpart affects combustion turbines which commenced construction, reconstruction, or modification after October 3, 1977, and which have a heat input rating of 10 MMBTUH or more. There are three gas turbines at this facility, all of which are subject to the requirements of this subpart. Monitoring of fuel nitrogen content shall not be required while natural gas is the only fuel fired in the turbines and a quarterly statement from the gas supplier reflecting the sulfur analysis or a stain tube analysis is acceptable for the monitoring and recording requirement of 60.334(b). Subpart VV, Equipment Leaks of VOC in the Synthetic Organic Chemical Manufacturing Industry. The equipment is not in a SOCMI plant. Subpart KKK, Equipment Leaks of VOC from Onshore Natural Gas Processing Plants. This subchapter sets standards for natural gas processing plants which are defined as any site engaged in the extraction of natural gas liquids from field gas, fractionation of natural gas liquids, or both. All equipment items potential subject to this subpart were manufactured prior to January 20, 1984 and are, therefore, exempt. Subpart LLL, Onshore Natural Gas Processing: SO 2 emissions. This subpart sets standards for natural gas sweetening units. The natural gas sweetening unit at this site was constructed prior to January 20, 1984, so the requirements of this subpart do not apply. Subpart IIII, Stationary Compression Ignition Internal Combustion Engines. This subpart affects stationary compression ignition (CI) internal combustion engines (ICE) based on power and displacement ratings, depending on date of construction, beginning with those constructed after July 11, 2005. There are no CI ICE engines located at this facility. Subpart JJJJ, Stationary Spark Ignition Internal Combustion Engines (SI-ICE), promulgates emission standards for all new SI engines ordered after June 12, 2006, and all SI engines modified or reconstructed after June 12, 2006, regardless of size. The specific emission standards (either in g/hp-hr or as a concentration limit) vary based on engine class, engine power rating, lean-burn or rich-burn, fuel type, duty (emergency or non-emergency), and numerous manufacture dates. Engine manufacturers are required to certify certain engines to meet the emission standards and may voluntarily certify other engines. An initial notification is required only for owners and operators of engines greater than 500 HP that are non-certified. Emergency engines will be required to be equipped with a non-resettable hour meter and are limited to 100 hours per year of operation excluding use in an emergency (the length of operation and the reason the engine was in operation must be recorded). All engines at this facility were constructed before the compliance date and are not subject to the new standards.

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 14 Subpart KKKK, Standards of Performance for Stationary Combustion Turbines, establishes emission standards and compliance schedules for the control of emissions from stationary combustion turbines with a heat input at peak load equal to or greater than 10 MMBtu, based on the higher heating value of the fuel, which commenced construction, modification, or reconstruction after February 18, 2005. Stationary combustion turbines regulated under this subpart are exempt from the requirements of Subpart GG of this part. The three (3) turbines at the facility have original manufacture dates prior to February 18, 2005 and have not been modified or reconstructed since that date. Subpart OOOO, Crude Oil and Natural Gas Production, Transmission, and Distribution. This subpart was promulgated on August 16, 2012, and per 60.5365 affects the following onshore affected facilities that commence construction, reconstruction, or modification after August 23, 2011: (a) (b) (c) (d) (e) (f) Each gas well affected facility, which is a single natural gas well. Each centrifugal compressor affected facility, which is a single centrifugal compressor using wet seals that is located between the wellhead and the point of custody transfer to the natural gas transmission and storage segment. Each reciprocating compressor affected facility, which is a single reciprocating compressor located between the wellhead and the point of custody transfer to the natural gas transmission and storage segment. Each pneumatic controller affected facility, which is: (1) For the oil production segment (between the wellhead and the point of custody transfer to an oil pipeline): a single continuous bleed natural gas-driven pneumatic controller operating at a natural gas bleed rate greater than 6 SCFH. (2) For the natural gas production segment (between the wellhead and the point of custody transfer to the natural gas transmission and storage segment and not including natural gas processing plants): a single continuous bleed natural gas-driven pneumatic controller operating at a natural gas bleed rate greater than 6 SCFH. (3) For natural gas processing plants: a single continuous bleed natural gas-driven pneumatic controller. Each storage vessel affected facility, which is a single storage vessel, located in the oil and natural gas production segment, natural gas processing segment or natural gas transmission and storage segment. On April 12, 2013, EPA proposed revisions to NSPS, Subpart OOOO revising the affected facilities to only those storage vessels that emit more than 6 TPY and revising the definition to only include those storage vessels that contain crude oil, condensate, intermediate hydrocarbon liquids, or produced water. The group of all equipment, except compressors, within a process unit is an affected facility. (1) Addition or replacement of equipment for the purpose of process improvement that is accomplished without a capital expenditure shall not by itself be considered a modification under this subpart. (2) Equipment associated with a compressor station, dehydration unit, sweetening unit, underground storage vessel, field gas gathering system, or liquefied natural gas unit is

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 15 (g) covered by 60.5400, 60.5401, 60.5402, 60.5421, and 60.5422 if it is located at an onshore natural gas processing plant. Sweetening units located at onshore natural gas processing plants that process natural gas produced from either onshore or offshore wells. (1) Each sweetening unit that processes natural gas is an affected facility; and (2) Each sweetening unit that processes natural gas followed by a sulfur recovery unit is an affected facility. (3) Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H 2 S) in the acid gas (expressed as sulfur) are required to comply with recordkeeping and reporting requirements specified in 60.5423(c) but are not required to comply with 60.5405 through 60.5407 and 60.5410(g) and 60.5415(g) of this subpart. There are no affected gas wells or centrifugal compressors located at this facility. For each new reciprocating compressor the owner/operator must replace the rod packing before 26,000 hours of operation or prior to 36 months. If utilizing the number of hours, the hours of operation must be continuously monitored. Commenced construction is based on the date of installation of the compressor (excluding relocation) at the facility. All the compressors at the facility were manufactured prior to August 23, 2011 but any new or modified compressors will have to comply with this subpart. No new continuous bleed natural gas-driven pneumatic controllers have been or will be installed. Storage vessels constructed, modified, or reconstructed after August 23, 2011, with VOC emissions equal to or greater than 6 TPY must reduce VOC emissions by 95.0 % or greater. All storage vessels are considered existing and are not subject to this subpart. The group of all equipment, except compressors, within a process unit at a natural gas processing plant must comply with the requirements of NSPS, Subpart VVa, except as provided in 60.5401. All process units are considered existing and are not subject to this subpart. A sweetening unit means a process device that removes hydrogen sulfide and/or carbon dioxide from the sour natural gas stream. A sour natural gas stream is defined as containing greater than or equal to 0.25 grains sulfur per 100 standard cubic feet or 4 ppmv. There is an amine unit at the facility but it was constructed prior to August 23, 2011 and is not subject to the standards for sweetening units. NESHAP, 40 CFR Part 61 [Not Applicable] There are no emissions of any of the pollutants subject to 40 CFR Part 61 except benzene. Subpart J affects process streams that contain more than 10% benzene by weight, while Subpart BB affects transfer and loading operations with 70% or more by weight benzene. The expected benzene concentrations are less than 0.5%, which are well below the de minimis level.

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 16 NESHAP, 40 CFR Part 63 [Not Applicable] Subpart HH, Oil and Natural Gas Production Facilities. This subpart applies to affected emission points that are located at facilities which are major sources of HAP, or to TEG dehydration units only at area sources of HAP, and that either process, upgrade, or store hydrocarbons prior to the point of custody transfer or prior to which the natural gas enters the natural gas transmission and storage source category. This facility is not a major source of HAP and does not have a TEG dehydration unit. Subpart ZZZZ, Reciprocating Internal Combustion Engines (RICE). This subpart affects any existing, new, or reconstructed stationary RICE located at a major or area source of HAP emissions. Owners and operators of the following new or reconstructed RICE must meet the requirements of Subpart ZZZZ by complying with either 40 CFR Part 60 Subpart IIII (for CI engines) or 40 CFR Part 60 Subpart JJJJ (for SI engines): 1) Stationary RICE located at an area source; 2) The following Stationary RICE located at a major source of HAP emissions: i) 2SLB and 4SRB stationary RICE with a site rating of 500 brake HP; ii) 4SLB stationary RICE with a site rating of < 250 brake HP; iii) Stationary RICE with a site rating of 500 brake HP which combust landfill or digester gas equivalent to 10% or more of the gross heat input on an annual basis; iv) Emergency or limited use stationary RICE with a site rating of 500 brake HP; and v) CI stationary RICE with a site rating of 500 brake HP. No further requirements apply for engines subject to NSPS under this part. Based on emission calculations, this facility is a minor source of HAP. A stationary RICE located at an area source of HAP emissions is new if construction commenced on or after June 12, 2006. All the engines at the facility were constructed prior to June 12, 2006, have not been reconstructed and are still considered existing engines. A summary of the requirements for the existing non-emergency SI and CI RICE located at this facility are shown below. Engine Category Remote Existing Non-Emergency, Non-Black Start, 4SRB & 4SLB HP > 500-hp Not Remote Existing Non-Emergency, Non-Black Start, 4SRB HP > 500-hp Existing Non-Emergency, Non-Black Start, 4SLB HP > 500-hp Requirements Change oil and filter every 2,160 hours of operation or annually, whichever comes first Inspect spark plugs every 2,160 hours of operation or annually, whichever comes first, and replace as necessary; and Inspect all hoses and belts every 2,160 hours of operation or annually, whichever comes first, and replace as necessary. Install NSCR to reduce HAP emissions from the stationary RICE. 270 ppmvd CO or 75% CO reduction@ 15% O 2. Install an oxidation catalyst to reduce HAP emissions. 47 ppmvd CO or 93% CO reduction @ 15% O 2.

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 17 Onshore remote stationary RICE means stationary RICE meeting any of the following criteria: 1. Stationary RICE located on a pipeline segment that meets both of the following criteria: i. A pipeline segment with 10 or fewer buildings intended for human occupancy and no buildings with four or more stories within 220 yards (200 meters) on either side of the centerline of any continuous 1-mile (1.6 kilometers) length of pipeline. Each separate dwelling unit in a multiple dwelling unit building is counted as a separate building intended for human occupancy. ii. The pipeline segment does not lie within 100 yards (91 meters) of either a building or a small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. The days and weeks need not be consecutive. The building or area is considered occupied for a full day if it is occupied for any portion of the day. 2. Stationary RICE that are not located on gas pipelines and that have 5 or fewer buildings intended for human occupancy and no buildings with four or more stories within a 0.25 mile radius around the engine. A building is intended for human occupancy if its primary use is for a purpose involving the presence of humans. This facility and engines within the facility are located on a gas pipeline and are considered remote since they are not located near 11 or more buildings intended for human occupancy or a building with four or more stories within 220 yards of the continuous 1 mile length of pipe centered on the facility or engines and they are not located within 100 yards of a well-defined out door area. There are no buildings intended for human occupancy within 1 mile of the facility. The existing 4SRB and 4SLB RICE at area sources must comply with the management practices no later than October 19, 2013. All applicable requirements have been incorporated into the permit. Existing emergency stationary CI RICE at area sources must comply with the following management practices no later than May 3, 2013: Change oil and filter every 500 hours of operation or annually, whichever comes first; Inspect air cleaner every 1,000 hours of operation or annually, whichever comes first; Inspect all hoses and belts every 500 hours of operation or annually, whichever comes first, and replace as necessary; and Minimize the engine's time spent at idle and minimize the engine's startup time at startup to a period needed for appropriate and safe loading of the engine, not to exceed 30 minutes, after which time the non-startup emission limitations apply. Sources have the option to utilize an oil analysis program as described in 63.6625(i) in order to extend the specified oil change requirement. Additionally, there are limitations on the hours that an emergency engine may operate. Total operating hours are limited to 100 hours/year for maintenance and readiness checks unless Federal, State, or local standards require maintenance and testing beyond 100 hours per year. The 100 hours/year includes up to 50 hours of nonemergency operations. The 50 hours cannot include peak shaving or other income generating power production. The 50 hours includes up to 15 hours of power generation as part of a demand

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 18 response program in the event of a potential electrical blackout situation. requirements have been incorporated into the permit. All applicable Subpart JJJJJJ, National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial and Institutional Boilers at area sources of HAPs. EPA has published various actions regarding implementation of this rule with the latest version on February 2, 2013. This facility is an area source of HAPs but all the heaters are natural gas-fired and therefore not subject to this subpart. Compliance Assurance Monitoring, 40 CFR Part 64 [Applicable] Compliance Assurance Monitoring, as published in the Federal Register on October 22, 1997, applies to any pollutant specific emission unit at a major source that is required to obtain a Title V permit, if it meets all of the following criteria: It is subject to an emission limit or standard for an applicable regulated air pollutant It uses a control device to achieve compliance with the applicable emission limit or standard It has potential emissions, prior to the control device, of the applicable regulated air pollutant greater than major source levels. CAM does not apply since pre-controlled emissions of the engines are less than 100 TPY (based on manufacture s data of 12 gm/hp-hr for NO X and CO). Chemical Accident Prevention Provisions, 40 CFR Part 68 [Not Applicable] This facility handles naturally occurring hydrocarbon mixtures at a natural gas processing plant and the Chemical Accident Prevention Provisions are applicable to this facility. The facility was required to submit the appropriate accidental release emergency response program plan prior to June 21, 1999. This facility has submitted the appropriate plan to EPA. More information on this federal program is available on the web page: www.epa.gov/ceppo. Stratospheric Ozone Protection, 40 CFR Part 82 [Subpart A and F Applicable] These standards require phase out of Class I & II substances, reductions of emissions of Class I & II substances to the lowest achievable level in all use sectors, and banning use of nonessential products containing ozone-depleting substances (Subparts A & C); control servicing of motor vehicle air conditioners (Subpart B); require Federal agencies to adopt procurement regulations which meet phase out requirements and which maximize the substitution of safe alternatives to Class I and Class II substances (Subpart D); require warning labels on products made with or containing Class I or II substances (Subpart E); maximize the use of recycling and recovery upon disposal (Subpart F); require producers to identify substitutes for ozone-depleting compounds under the Significant New Alternatives Program (Subpart G); and reduce the emissions of halons (Subpart H). Subpart A identifies ozone-depleting substances and divides them into two classes. Class I controlled substances are divided into seven groups; the chemicals typically used by the manufacturing industry include carbon tetrachloride (Class I, Group IV) and methyl chloroform (Class I, Group V). A complete phase-out of production of Class I substances is required by

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 19 January 1, 2000 (January 1, 2002, for methyl chloroform). Class II chemicals, which are hydrochlorofluorocarbons (HCFCs), are generally seen as interim substitutes for Class I CFCs. Class II substances consist of 33 HCFCs. A complete phase-out of Class II substances, scheduled in phases starting by 2002, is required by January 1, 2030. This facility does not utilize any Class I & II substances. SECTION IX. COMPLIANCE Tier Classification and Public Review This application has been determined to be a Tier II, based on the request for a permit renewal for an existing major source. The permittee has submitted an affidavit that they are not seeking a permit for land use or for any operation upon land owned by others without their knowledge. The affidavit certifies that the applicant owns the land. The applicant will publish a Notice of Filing a Tier II Application and also a Notice of Tier II Draft Permit in a local newspaper in Kingfisher County where the facility is located. The notices will state that the application and the draft permit will be available for public review at the Okarche Natural Gas Processing Plant or the DEQ office in Oklahoma City. The notices will also state that the application and the draft permit will be available for public review at a local public library in Kingfisher, Oklahoma. Information on all permit actions is available for review by the public in the Air Quality section of the DEQ Web page: www.deq.state.ok.us/. Inspection On August 28, 2012, a full compliance evaluation was conducted at this facility. The evaluation was conducted by Camus Frey, Sean Walker and Jason Ballard, Environmental Programs Specialists for the Oklahoma Department of Environmental Quality, Air Quality Division. Lonnie Covalt, Environmental Health and Safety Coordinator, Bob McEuen, Plant Operator, and Charles Bates, Plant Manager, represented the Facility. The facility was physically as described in the permit application and supplemental materials. Identification plates with the make, model, and serial number were attached to each engine. Fee Paid Part 70 renewal permit application fee of $7,500. Testing Emission testing for the engines below was provided by the facility. All results are presented on the following page and show compliance with the applicable permit conditions.

PERMIT MEMORANDUM PERMIT 2013-1557-TVR2 DRAFT 20 Point Source Permit Limitations Test Results Test NOx CO NOx CO Date lb/hr lb/hr lb/hr lb/hr ENG-01 Waukesha L-7042 11/19/13 3.48 5.30 1.74 2.01 ENG-02 Waukesha L-7042 11/19/13 3.48 5.30 1.99 2.01 ENG-03a Waukesha L-7042 11/19/13 3.48 5.30 1.31 2.18 ENG-04a Waukesha L-7042 11/19/13 3.48 5.30 1.82 0.87 TURB-01c Murray Solar Turbine 12/11/13 19.22 8.65 18.71 0.75 TURB-01b Murray Solar Turbine 10/01/13 19.22 8.65 17.26 0.88 TURB-02c Murray Solar Turbine 12/11/13 19.22 8.65 18.29 0.13 TURB-03a York Solar Turbine 12/11/13 17.10 7.70 15.77 0.59 SECTION X. SUMMARY This facility was constructed as described in the application. Ambient air quality standards are not threatened at this site. There are no active Air Quality compliance or enforcement issues which would prohibit the issuance of the permit. Issuance of the permit is recommended; contingent on public and EPA review.

PERMIT TO OPERATE AIR POLLUTION CONTROL FACILITY SPECIFIC CONDITIONS DCP Midstream, LP Okarche Gas Plant Permit No. 2013-1557-TVR2 The permittee is authorized to operate in conformity with the specifications submitted to Air Quality on October 2, 2013. The Evaluation Memorandum dated January 6, 2014 explains the derivation of applicable permit requirements and estimates of emissions; however, it does not contain operating limitations or permit requirements. Continuing operation under this permit constitutes acceptance of, and consent to, the conditions contained herein. 1. Points of emissions and emissions limitations for each point: [OAC 252:100-8-6(a)] EUG 1: Emission limitations for emission units TURB-01, TURB-02, TURB-03. NO EU ID# Description x CO VOC lb/hr TPY lb/hr lb/hr TPY lb/hr TURB-01 4,707-hp Murray Solar turbine 19.22 84.2 8.65 37.90 6.73 29.47 TURB-2 4,707-hp Murray Solar turbine 19.22 84.2 8.65 37.90 6.73 29.47 TURB-3 3,879-hp York Solar turbine 17.10 74.91 7.70 33.71 5.99 26.22 EUG 2: Emission limitations for emission units ENG-01, ENG-02, ENG-03, ENG-04. EU ID# Description NO x CO VOC lb/hr TPY lb/hr lb/hr TPY lb/hr ENG-01 687-hp Waukesha L7042 with/cc 3.48 15.26 5.30 23.22 1.51 6.63 ENG-02 687-hp Waukesha L7042 with/cc 3.48 15.26 5.30 23.22 1.51 6.63 ENG-03 687-hp Waukesha L7042 with/cc 3.48 15.26 5.30 23.22 1.51 6.63 ENG-04 687-hp Waukesha L7042 with/cc 3.48 15.26 5.30 23.22 1.51 6.63 EUG 3: Storage tank VOC emissions are estimated based on existing equipment items but do not have a specific limitation. Point Contents Barrels Gallons TNK-01 North Condensate/Slop Oil 1000 42,000 TNK-02 South Condensate/Slop Oil 1000 42,000 TNK-03 Southeast Condensate/Slop Oil 300 12,600 TNK-04 Center Condensate/Slop Oil 300 12,600 TNK-05 Treated Condensate & Slop Oil 300 12,600 TNK-06 Field Wastewater 300 12,600 TNK-07 East Methanol/Water 300 12,600 TNK-08 West Methanol/Water 300 12,600