MEMORANDUM December 14, Phillip Fielder, P.E., Permits and Engineering Group Manager. Rick Groshong, Compliance and Enforcement Manager

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1 DRAFT/PROPOSED OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION MEMORANDUM December 14, 2015 TO: THROUGH: THROUGH: THROUGH: FROM: SUBJECT: Phillip Fielder, P.E., Permits and Engineering Group Manager Rick Groshong, Compliance and Enforcement Manager Phil Martin, P.E., Manager, Existing Source Permits Section Peer Review Ryan Buntyn, Existing Source Permits Section Evaluation of Permit Application No C MarkWest Oklahoma Gas Company, L.L.C. Okarche Compressor Station (Fac ID: 14817) Latitude: o N, Longitude: o W Section 3, Township 14N, Range 7W, Canadian County, Oklahoma Directions: From Okarche, drive two (2) miles east on Oklahoma Ave., then one (1) mile south on N Shepard Ave., then drive one-half (0.5) of a mile east on 234 th St. NE to facility on north side of road. I. INTRODUCTION MarkWest Oklahoma Gas Company, L.L.C. (MarkWest) has requested a major source construction permit for their Okarche Compressor Station (SIC 1311). The facility is currently operating under Authorization to Construct (GP-OGF) Permit No NOI issued March 3, The facility provides compression of natural gas near the town of Okarche in Canadian County, Oklahoma. Currently this facility is authorized to construct five (5) 1,340-Hp Caterpillar G3516 TALE Compressor Engines with catalytic converters (ENG-1 thru ENG-5), one (1) 42 MMSCFD Glycol Dehydrator (DEHY-1) with one (1) associated 1 MMBTUH Glycol Reboiler (H-1) and one (1) associated 0.85 MMBTUH Enclosed Flare (F-1), four (4) 400-bbl Vertical Fixed Roof (VFR) Condensate Storage Tanks (TK-1 thru TK-4), one (1) 400-bbl VFR Produced Water Storage Tank (TK-5), one (1) 500-bbl VFR Gunbarrel Oil Tank (TK-6), two (2) 1.21 MMBTUH Enclosed Flares (F-2 & F-3) and various support operations. This permit will authorize the construction of seven (7) additional 1,340-Hp Caterpillar G3516 TALE Compressor Engines with catalytic converters (ENG-6 thru ENG-12), one (1) additional 42 MMSCFD Glycol Dehydrator (DEHY-2) with one (1) associated 1 MMBTUH Glycol Reboiler (H-2). DEHY-2 will also utilize F-1 to control emissions. Additionally methanol, antifreeze, and lube oil tanks may be installed on-site. The application for the construction permit requires a Tier II permitting process and is subject to public and EPA review. The facility does not trigger New Source Review since the criteria pollutant emissions do not exceed 250 TPY. Because NOx emissions are increasing by more than 100 TPY, Oklahoma BACT analysis is required. The facility is a minor source of HAP.

2 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 2 II. FACILITY DESCRIPTION Natural gas will be transported to the facility by a pipeline gathering system. Field gas enters the facility through an inlet separator, where produced water and condensate are separated from the gas stream. The gas is compressed, is then processed by glycol dehydration units, and leaves the facility by pipeline. III. EQUIPMENT EUG A Natural Gas-Fired Reciprocating Internal Combustion Engines EU ID# Point ID# EU Name/Model Construction/Modification. Date EU-ENG-1 P-ENG-1 1,340-Hp Caterpillar G3516 TALE w/ c.c. 2/12/2009 EU-ENG-2 P-ENG-2 1,340-Hp Caterpillar G3516 TALE w/ c.c. 3/18/2008 EU-ENG-3 P-ENG-3 1,340-Hp Caterpillar G3516 TALE w/ c.c. 4/14/2007 EU-ENG-4 P-ENG-4 1,340-Hp Caterpillar G3516 TALE w/ c.c. 12/17/2007 EU-ENG-5 P-ENG-5 1,340-Hp Caterpillar G3516 TALE w/ c.c. 2/15/2008 EU-ENG-6 P-ENG-6 1,340-Hp Caterpillar G3516 TALE w/ c.c. TBD EU-ENG-7 P-ENG-7 1,340-Hp Caterpillar G3516 TALE w/ c.c. TBD EU-ENG-8 P-ENG-8 1,340-Hp Caterpillar G3516 TALE w/ c.c. TBD EU-ENG-9 P-ENG-9 1,340-Hp Caterpillar G3516 TALE w/ c.c. TBD EU-ENG-10 P-ENG-10 1,340-Hp Caterpillar G3516 TALE w/ c.c. TBD EU-ENG-11 P-ENG-11 1,340-Hp Caterpillar G3516 TALE w/ c.c. TBD EU-ENG-12 P-ENG-12 1,340-Hp Caterpillar G3516 TALE w/ c.c. TBD w/ c.c. - with catalytic converter EUG B Natural Gas-Fired Heaters and Reboilers EU ID# Point ID# EU Name/Model Construction/Modification. Date EU-H-1 P-H-1 1 MMBTUH Glycol Reboiler 2015 EU-H-2 P-H-2 1 MMBTUH Glycol Reboiler 2015 EUG C Glycol Dehydration EU ID# Point ID# EU Name/Model Construction/Modification. Date EU-DEHY-1 P-DEHY-1 42 MMSCFD Glycol Dehydrator 2015 EU-DEHY-2 P-DEHY-2 42 MMSCFD Glycol Dehydrator 2015 EUG D Storage Tanks EU ID# Point ID# EU Name/Model Construction/Modification. Date EU-TK-1 P-TK bbl VFR Condensate Storage Tank 2015 EU-TK-2 P-TK bbl VFR Condensate Storage Tank 2015 EU-TK-3 P-TK bbl VFR Condensate Storage Tank 2015 EU-TK-4 P-TK bbl VFR Condensate Storage Tank 2015 EU-TK-5 P-TK bbl VFR Produced Water Storage Tank 2015 EU-TK-6 P-TK bbl VFR Gunbarrel Oil Tank 2015

3 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 3 EUG E Enclosed Flare EU ID# Point ID# EU Name/Model Construction/Modification. Date EU-F-1 P-F-1 Enclosed Flare 2015 EU-F-2 P-F-2 Enclosed Flare 2015 EU-F-3 P-F-3 Enclosed Flare 2015 EUG F Condensate Truck Loading EU ID# Point ID# EU Name/Model Construction/Modification. Date EU-LOAD-1 P-LOAD-1 Condensate Truck Loading N/A EUG G Fugitive Emissions EU ID# Point ID# EU Name/Model Construction/Modification. Date EU-FUG-1 P-FUG-1 Miscellaneous Process Piping Fugitives N/A EUG H Startup, Shutdown, and Maintenance EU ID# Point ID# EU Name/Model Construction/Modification. Date EU-MSS-1 P-MSS-1 Engine Blowdowns N/A IV. EMISSIONS Emission estimates for the engines are based on continuous operation and emission factors for NOx, CO, VOC, and formaldehyde are from manufacturer s data. All engines are equipped with catalytic converters. The reduction efficiencies from the catalytic converters are approximately 79% for CO and 80% for formaldehyde. The engines will be fueled by pipeline natural gas. 1 - Includes formaldehyde emissions. Engine Emission Factors NOx CO VOC 1 Formaldehyde EU g/hp-hr g/hp-hr g/hp-hr g/hp-hr EU-ENG-1 thru EU-ENG Emissions from the heaters are based on AP-42 (7/98), Section 1.4 and continuous operation and a burner rating of 1 MMBTUH. Potential VOC emissions (breathing/working/flashing) from the four (4) 400-bbl VFR condensate storage tanks, one (1) 400-bbl VFR produced water storage tank and one (1) 500-bbl VFR gunbarrel oil tank are based on a maximum condensate throughput of 2,299,500 gallons/yr per tank (EU-TK-1 thru EU-TK-4), produced water throughput of 2,299,500 gallons/yr for EU-TK-5 and a maximum liquid throughput of 9,198,000 gallons/yr for EU-TK-6. E&P Tanks V2.0 program was used to determine potential emissions of VOC per year from the 500-bbl VFR gunbarrel tank for combined working/breathing/flashing losses. EPA TANKS 4.0.9d program was used to determine potential emissions of VOC per year from the other storage tanks for working and breathing losses. To be conservative, breathing and working losses for produced water were calculated using crude oil, assuming 1% is emitted. The tanks will be limited to <6 TPY each in order to avoid becoming subject to NSPS Subpart OOOO.

4 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 4 Emissions from loading condensate into tank trucks (EU-LOAD-1) were estimated using AP-42 (1/95), Section 5.2, Equation 1, and a maximum throughput of 9,198,000 gallons per year. VOC and HAP emissions from the two glycol dehydrator still vents (DEHY-1 & DEHY- 2) are estimated using GRI-GLYCalc Version 4.0, extended gas analysis data, a maximum glycol recirculation rate of 7.5 gallon per minute for each unit, a natural gas throughput of 42 MMSCFD for each unit, a control efficiency of greater than 98% from the condenser/combustion device, and a 100% safety factor to allow for variability in the composition of the natural gas stream. The glycol dehydrator is equipped with a flash tank. The flash tank emissions are recycled/recompressed. The tanks emissions are routed to vapor recovery units with the enclosed flares serving as backup control. During normal operation, the capture efficiency of the VRU is 100% and control efficiency of the flare is 98% of VOC emissions. Flare emissions factors for NOx and CO are based on AP-42 Table with the burner rating listed below. Emissions factors for the pilot are based on AP-42 Table with the burner rating listed below. Point Description Flared Gas MMBTUH Pilot MMBTUH EU-F-1 Enclosed Flare for Dehys EU-F-2 Enclosed Flare VRU Back-Up EU-F-3 Enclosed Flare VRU Back-Up Emissions from fugitive equipment leaks are based on EPA s Protocol for Equipment Leak Emission Estimates (11/95, EPA-453/R ), an estimated number of components, and the VOC (C3+) content of the materials handled. Emissions Summary EU Description NO X CO VOC H 2 CO TPY TPY TPY TPY ENG Hp Cat G3516 TALE Compressor Engine ENG Hp Cat G3516 TALE Compressor Engine ENG Hp Cat G3516 TALE Compressor Engine ENG Hp Cat G3516 TALE Compressor Engine ENG Hp Cat G3516 TALE Compressor Engine ENG Hp Cat G3516 TALE Compressor Engine ENG Hp Cat G3516 TALE Compressor Engine ENG Hp Cat G3516 TALE Compressor Engine ENG Hp Cat G3516 TALE Compressor Engine ENG Hp Cat G3516 TALE Compressor Engine ENG Hp Cat G3516 TALE Compressor Engine ENG Hp Cat G3516 TALE Compressor Engine

5 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 5 EU Description NO X CO VOC H 2 CO TPY TPY TPY TPY DEHY-1 42 MMSCFD Glycol Dehydrator DEHY-2 42 MMSCFD Glycol Dehydrator H-1 1 MMBTUH Glycol Reboiler H-2 1 MMBTUH Glycol Reboiler F-1 Enclosed Flare for Dehys TK bbl VFR Condensate Storage Tank TK bbl VFR Condensate Storage Tank TK bbl VFR Condensate Storage Tank TK bbl VFR Condensate Storage Tank TK bbl VFR Produced Water Storage Tank TK bbl VFR Gunbarrel Oil Tank F-2 Enclosed Flare F-3 Enclosed Flare LOAD-1 Truck Loading FUG-1 Fugitive emissions MSS-1 Startup, Shutdown, & Maintenance Total Emissions Previously Permitted Emissions Net Change V. INSIGNIFICANT ACTIVITIES HAP Emissions EU Benzene Toluene Ethyl Benzene Xylene n-hexane lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY DEHY DEHY Total The insignificant activities identified and justified on Part 1b of the forms in the application and duplicated below. Appropriate recordkeeping is required for those activities indicated below with an asterisk. 1. Space heaters, boilers, process heaters, and emergency flares less than or equal to 5 MMBTUH heat input (commercial natural gas). The facility currently contains two (2) 1 MMBTUH glycol reboilers.

6 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 6 2. * Storage tanks with less than or equal to 10,000 gallons capacity that store volatile organic liquids with a true vapor pressure less than or equal to 1.0 psia at maximum storage temperature. Glycol and lube oil storage tanks all have capacities less than 10,000 gallons and store liquids with a vapor pressure below 1.0 psia. 3. Emissions from condensate tanks with a design capacity of 400 gallons or less in ozone attainment areas. 4. Emissions from storage tanks constructed with a capacity less than 39,894 gallons which store VOC with a vapor pressure less than 1.5 psia at maximum storage temperature. 5. Activities having the potential to emit no more than 5 TPY (actual) of any criteria pollutant. VI. OKLAHOMA BACT REVIEW A BACT analysis is required for NOx emissions because the NOx emissions will exceed the major source threshold of 100 TPY. The proposed engines will be subject to 40 CFR Part 60, NSPS, Subpart JJJJ and 40 CFR Part 63, NESHAP, Subpart ZZZZ. The maximum BACT emission rate allowed is the emission rate set under NSPS Subpart JJJJ, although lower emission rates could be proposed and accepted. BACT is analyzed using the "top-down" approach. 1. Identify All Control Technologies Using EPA s RACT/BACT/LAER Clearinghouse (RBLC) as a reference, the following air emissions controls for compressor engines are evaluated: Low emissions operation or conversions (lean-burn retrofitting) Selective catalytic reduction (SCR) Air-to-fuel ratio (AFR) controllers Based on RBLC results for Oklahoma facilities, the lowest emission rate deemed to be BACT is 2.0 g/hp-hr NOx based on a lean-burn conversion. In addition, based on past MarkWest permits, ODEQ has confirmed that 2.0 g/hp-hr NOx should be considered the maximum BACT for lean burn combustion engines manufactured before July 1, 2010 regardless of emissions control. 2. Eliminate Technologically Infeasible Options For the purposes of this evaluation, it is assumed that all control options are technically feasible. 3. Rank Remaining Technologies by Control Effectiveness The EPA Publication, Alternate Control Techniques Document NOx Emissions from Stationary Reciprocating Internal Combustion Engines (EPA-453/R , July 1993) identifies the following NOx emissions controls for lean-burn spark-ignition stationary internal combustion engines:

7 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 7 Selective catalytic reduction (90% control) Low-emissions combustion (87% control) Air-fuel ratio adjustment (5-30% control) SCR provides the highest degree of NOx emissions control. SCR reacts ammonia with NOx to form nitrogen gas and water. The reaction takes place normally on a precious metal catalyst bed. The catalyst must be operated in a narrow temperature range and is susceptible to fouling and poisoning by engine materials such as lubricating oils. Low-emission technology utilizes pre-combustion chamber (PCC) technology. The majority of the air/fuel mixture within the cylinders is too lean to be ignited by the spark plug. A relatively small chamber in the cylinder is supplied with a rich air/fuel mixture which can be ignited by the spark plug; ignition in this small chamber then ignites the lean air/fuel mixture in the rest of the cylinder. Compared to an industry average for operation at the crossover point of NOx and CO emissions (11 g/hp-hr NOx), this combustion technology gives significant emissions reductions for NOx. Air-fuel ratio adjustment ensures a higher-than-stoichiometric ratio of air to fuel. The excess air results in lower flame temperature when the combustion cycle is at maximum compression. SCR and low-emission combustion have similar reduction efficiencies, with SCR providing slightly better control than low-emission combustion. All other techniques are less effective and will not be discussed further. 4. Determine the Cost-Effective Values of the Most Efficient Controls Since the proposed engines are existing sources already owned by MarkWest, either new engines would need to be purchased or the existing engines would have to install ultra-lean burn conversion in order to achieve a 1.0 g/hp-hr NOx emission rate. The engines currently proposed for the facility have a manufacturer s guarantee of 1.5 g/hp-hr of NOx emissions. Decreasing the NOx emission rate to 1.0 g/hp-hr would result in an emissions decrease of 6.47 tpy per engine. MarkWest obtained vendor quotes for upgrading each engine to ultra-lean burn operation, which is less expensive than purchasing new engines. The anticipated cost to decrease NOx emissions down from 1.5 g/hp-hr to 1.0 g/hp-hr is approximately $100,370. Based on this cost and the related emissions decrease, the cost effectiveness of ultra-lean burn conversion is $15,513 per ton NOx controlled. Historically, ODEQ has considered anything greater than $10,000 per ton controlled to not be cost effective. Therefore, the high cost per ton NOx controlled for this conversion suggests that ultra-lean burn conversion is not a cost-effective option. Additionally, due to the operational and environmental risks associated with SCR, and due to the additional cost of this add-on control (capital cost, urea, maintenance, training, etc.), SCR is considered an even less cost-effective option than ultra-lean burn.

8 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 8 5. Select BACT Based on the evaluation above, NSPS Subpart JJJJ, and on previous ODEQ determinations, ODEQ selects no add-on controls as BACT since there are no cost-effective options available. A BACT limit of 1.5 g/hp-hr NOx for each engine manufactured before July 1, 2010 and 1.0 g/hphr NOx for each engine manufactured on or after July 1, 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] Subchapter 3 enumerates the primary and secondary ambient air quality standards and the significant deterioration increments. 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 that result in emissions not authorized in the permit and that exceed the Insignificant Activities or Trivial Activities thresholds require prior notification to AQD and may require a permit modification. Insignificant activities refer to those individual emission units either listed in Appendix I 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 HAP or 20% of any threshold less than 10 TPY for a HAP that the EPA may establish by rule Emission limitations and operational requirements necessary to assure compliance with all applicable requirements for all sources are taken from the permit applications, or developed from the applicable requirement. Because emissions of NOx are increasing by over 100 TPY, Oklahoma BACT analysis was performed. The analysis is in Section VI. OAC 252:100-9 (Excess Emissions Reporting Requirements) [Applicable] Except as provided in OAC 252: (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

9 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 9 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: , 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: (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: (Particulate Matter (PM)) [Applicable] This subchapter specifies a particulate matter (PM) emission limitation of 0.6 lb/mmbtu from fuel-burning units with a rated heat input of 10 MMBTUH or less. Section 19-4 regulates emissions of PM from fuel-burning equipment. For fuel-burning equipment greater than 10 MMBTUH, this subchapter specifies a PM emission limitation based upon the heat input of the equipment is calculated according to the following equations: E = X For Units > 10 MMBTUH but < 1,000 MMBTUH Where: E = allowable total particulate matter emissions in pounds per MMBTU and X = the maximum heat input in MMBTU per hour. EU Heat Input Capacity, MMBTUH PM Emission Limitation of OAC 252:100-19, lb/mmbtu Anticipated PM Emission Rate, lb/mmbtu EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-H EU-H

10 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 10 OAC 252: (Visible Emissions and Particulates) [Applicable] No discharge of greater than 20% opacity is allowed except for short-term occurrences that 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 very little possibility of exceeding the opacity standards, therefore no periodic observation is necessary. OAC 252: (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 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 fugitive dust problems, therefore it is not necessary to require specific precautions to be taken. OAC 252: (Sulfur Compounds) [Applicable] Part 2 limits emissions of sulfur dioxide from any one existing source or any one new petroleum and natural gas process source subject to OAC 252: (a)(1). Ambient air concentration of sulfur dioxide at any given point shall not be greater than 1300 g/m 3 in a 5-minute period of any hour, 1,200 g/m 3 for a 1-hour average, 650 g/m 3 for a 3-hour average, or 130 g/m 3 for a 24-hour average. A typical engine burning fuel gas with 343 ppm sulfur will produce ambient impacts of 22 ug/m 3 (1-hour average). Compliance with the other averaging periods is assured by the wide margin of compliance. Part 5 limits sulfur dioxide emissions from new fuel-burning 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. The permit requires the use of gaseous fuel with sulfur content less than 343 ppmv to ensure compliance with Subchapter 31. OAC 252: (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 0.20 lbs of NOx per MMBTU, three-hour average. There are no equipment items that exceed the 50 MMBTUH threshold. OAC 252: (Carbon Monoxide) [Not Applicable] None of the following affected processes are located at this facility: gray iron foundry, blast furnace, basic oxygen furnace, petroleum catalytic reforming unit, or petroleum catalytic cracking unit. OAC 252: (Volatile Organic Compounds) [Parts 3 and 7 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 to be equipped with a permanent submerged fill pipe or with an organic vapor recovery system. The condensate tanks will comply by controlling emissions through a VRU. The vapor pressure of produced water, glycol and lube oil is less than 1.5 psia, therefore, Part 3 does not apply to those tanks.

11 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 11 Part 5 limits the VOC content of coating used in coating lines or operations. This facility will not normally conduct coating or painting operations except for routine maintenance of the facility and equipment, which is exempt. Part 7 requires fuel-burning equipment to be operated and maintained so as to minimize emissions. Part 7 also regulates effluent water separators that receive water containing more than 200 gallons per day of VOC. The one (1) 500-bbl VFR gunbarrel oil tank is subject to this subpart. It will show compliance by installing a vapor recovery unit (VRU) with flare backup. OAC 252: (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 Area of Concern (AOC) has been designated anywhere in the state, there are no specific requirements for this facility at this time. OAC 252: (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: Alternative Reduction not requested OAC 252: Mobile Sources not in source category OAC 252: Incinerators not type of emission unit OAC 252: Cotton Gins not type of emission unit OAC 252: Feed & Grain Facility not in source category OAC 252: Nonattainment Areas not in area category OAC 252: Municipal Solid Waste Landfills not in source category

12 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 12 VIII. FEDERAL REGULATIONS PSD, 40 CFR Part 52 [Not Applicable] Total emissions are less than the major source threshold of 250 TPY of any single regulated pollutant and the facility is not one of the 26 specific industries with a threshold of 100 TPY. NSPS, 40 CFR Part 60 [Subpart JJJJ is Applicable] Subpart Kb, VOL Storage Vessels. This subpart regulates hydrocarbon storage tanks larger than 19,813 gallons capacity and built after July 23, The capacity of the storage tanks (TK-1 thru TK-5) is below the capacity of 19,813-gal, and thus they are exempt. The 500-bbl VFR gunbarrel oil tank is a process vessel and is not subject to this subpart. 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. The compressors at the site are powered by reciprocating engines. Subpart KKK, Equipment Leaks of VOC from Onshore Natural Gas Processing Plants. This subpart applies to natural gas processing plants constructed, reconstructed or modified after January 20, 1984 but prior to August 23, The facility does not engage in natural gas processing. Subpart LLL, Onshore Natural Gas Processing: SO 2 Emissions. This subpart affects sweetening units and sweetening units followed by sulfur recovery units. This facility does not have a sweetening unit. Subpart IIII, Stationary Compression Ignition (CI) Internal Combustion Engines (ICE). This subpart affects CI ICE manufactured after There will be no CI ICE located at this facility. Subpart JJJJ, Standards of Performance for Stationary Spark Ignition Internal Combustion Engines (SI-ICE). This subpart was published in the Federal Register on January 18, It promulgates emission standards for all new SI engines ordered after June 12, 2006, that are manufactured after certain dates, and all SI engines modified or reconstructed after June 12, 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 nonemergency), and manufacture date. Three (3) engines (ENG-1, ENG-2 and ENG-5) were constructed after January 1, 2008 and are subject to this subpart. The facility will comply with all applicable requirements. Two (2) engines (ENG-3 and ENG-4) were constructed before January 1, 2008 and are not subject to this subpart. The seven (7) proposed 1,340-hp Caterpillar G3516 LE engines (ENG-6 thru ENG-12) may be manufactured after July 1, 2010 and may be subject to the emission limitations of this subpart. The facility will comply with all applicable requirements. Subpart OOOO, Crude Oil and Natural Gas Production, Transmission, and Distribution. This affects the following onshore affected facilities that commence construction, reconstruction, or modification after August 23, 2011: (a) (b) 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.

13 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 13 (c) (d) (e) (f) (g) 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, that contains an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water and has the potential for VOC emissions equal to or greater than 6 TPY. The group of all equipment, except compressors, within a process unit located at an onshore natural gas processing plant is an affected facility. Sweetening units located at onshore natural gas processing plants that process natural gas produced from either onshore or offshore wells. For each 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 that a contract was signed for installation of the compressor (excluding relocation) at the facility. The compressors associated with the engines were constructed before August 23, 2011 and are not subject to this subpart. This facility is not a gas plant. The facility will comply with this subpart for pneumatic controllers that are constructed, modified, or reconstructed after October 23, This facility currently does not have any affected pneumatic controllers. 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 new or modified storage vessels with PTE VOC emissions equal to or greater than 6 TPY after enforceable limits will have to comply with this subpart. The facility s condensate storage tanks are classified as Group 2 Tanks being constructed after April 12, The tanks will be equipped with a process VRU and have potential emissions less than 6 TPY per tank. MarkWest requests federally enforceable limits of less than 6 TPY per tank. Therefore, the storage vessels 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 This facility is not a gas plant.

14 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 14 A sweetening unit means a process device that removes hydrogen sulfide and/or carbon dioxide from the sour natural gas stream. There are no sweetening units at this facility. NESHAP, 40 CFR Part 61 [Not Applicable] There are no emissions of any of the regulated pollutants: arsenic, asbestos, benzene, beryllium, coke oven emissions, mercury, radionuclides, or vinyl chloride except for trace amounts of benzene. Subpart J, Equipment Leaks of Benzene, concerns only process streams which contain more than 10% benzene by weight. Analysis of Oklahoma natural gas indicates a maximum benzene content of less than 1%. NESHAP, 40 CFR Part 63 [Subpart HH and ZZZZ are Applicable] Subpart HH, Oil and Natural Gas Production Facilities. This subpart applies to affected emission points that are located at facilities that are major and area sources of HAPs and 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. For purposes of this subpart natural gas enters the natural gas transmission and storage source category after the natural gas processing plant, if present. This facility is currently an area source of HAPs until the second phase of the proposed project occurs. For area sources of HAP, TEG dehydration units with an actual annual average flowrate of less than 3 MMSCFD or less than 1 TPY of benzene emissions are exempt from control standards, but are subject to recordkeeping. This facility is a minor source of HAPs and the TEG dehydration units at this facility have benzene emissions less than one (1) TPY; therefore, they will only be subject to the recordkeeping provisions of this subpart. All applicable requirements have been incorporated into the permit. Subpart ZZZZ, Reciprocating Internal Combustion Engines (RICE) affects new and existing engines at major and area sources. According to 40 CFR (c), owners and operators of new or reconstructed engines at area sources must meet the requirements of Subpart ZZZZ by complying with 40 CFR Part 60 Subpart JJJJ. All current engines at the site are either gap engines or subject to NSPS JJJJ and are therefore not subject to any requirements under this subpart. Subpart DDDDD, Industrial, Commercial and Institutional Boilers and Process Heaters. This subpart establishes national emission limitations and work practice standards for hazardous air pollutants (HAP) emitted from industrial, commercial, and institutional boilers and process heaters located at major sources of HAP. This subpart also establishes requirements to demonstrate initial and continuous compliance with the emission limitations and/or work practice standards. This facility will not be a major source of HAP and is not subject to this subpart. CAM, 40 CFR Part 64 [Not Applicable] Compliance Assurance Monitoring (CAM) 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 of at least 100% of the amount required to be defined as a major source.

15 PERMIT MEMORANDUM NO C DRAFT/PROPOSED 15 Based on the application calculations, pre-control emissions of HAP from each glycol dehydrator are above 25 TPY. CAM for the dehydration unit emission controls will be required at permit renewal. Chemical Accident Prevention Provisions, 40 CFR Part 68 [Not Applicable] The definition of a stationary source does not apply to transportation, including storage incident to transportation, of any regulated substance or any other extremely hazardous substance under the provisions of this part. The definition of a stationary source also does not include naturally occurring hydrocarbon reservoirs. Naturally occurring hydrocarbon mixtures, prior to entry into a natural gas processing plant or a petroleum refining process unit, including: condensate, crude oil, field gas, and produced water, are exempt for the purpose of determining whether more than a threshold quantity of a regulated substance is present at the stationary source. More information on this federal program is available on the web page: IX. COMPLIANCE Tier Classification and Public Review This application has been classified as Tier II based on the request for a Title V Construction Permit. The applicant published the Notice of Filing Tier II Application in the El Reno Tribune newspaper on September 13, The facility will publish the DEQ Notice of Tier II Draft Permit in the El Reno Tribune newspaper. The notice will state that the draft permit is available for public review at the El Reno Carnegie Library, located at 215 E. Wade St., El Reno, OK 73036, or at the DEQ main office in Oklahoma City. 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 has a current lease for the land. Information on all permit actions is available for review by the public in the Air Quality section of the DEQ Web Page: This facility is not located within 50 miles of any state border. The draft/proposed permit will go through a 30-day public and 45-day EPA review. Fee Paid Part 70 source construction permit application fee of $7,500 has been paid. X. SUMMARY The facility will be constructed as described in the permit application. Ambient air quality standards are not threatened at this site. There are no active Air Quality compliance or enforcement issues that would prevent issuance of the permit. Issuance of the construction permit is recommended, contingent on public and EPA review.

16 PERMIT TO CONSTRUCT AIR POLLUTION CONTROL FACILITY SPECIFIC CONDITIONS DRAFT/PROPOSED MarkWest Oklahoma Gas Company, L.L.C. Okarche Compressor Station Permit Number C The permittee is authorized to construct in conformity with the specifications submitted to the Air Quality Division (AQD) on September 3, The Evaluation Memorandum dated December 14, 2015, explains the derivation of applicable permit requirements and estimates of emissions; however, it does not contain operating limitations or permit requirements. Commencing construction under this permit constitutes acceptance of, and consent to, the conditions contained herein. 1. Points of emissions and emissions limitations and standards for each point: [OAC 252: (a)(1)] EUG A Natural Gas-Fired Reciprocating Internal Combustion Engines EU NOx CO VOC lb/hr TPY lb/hr TPY lb/hr TPY EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG EU-ENG A. The internal combustion engines shall be equipped with oxidation catalysts. B. Each engine manufactured before July 1, 2010 shall meet 1.5 g/hp-hr NOx and each engine manufactured on or after July 1, 2010 shall meet 1.0 g/hp-hr NOx. EUG B Natural Gas-Fired Heaters and Reboilers Emissions from the equipment listed following are estimated based on existing equipment items and do not have a specific limitation. EU Equipment MMBTUH EU-H-1 Dehy Reboiler 1.0 EU-H-2 Dehy Reboiler 1.0

17 SPECIFIC CONDITIONS NO C DRAFT/PROPOSED 2 EUG C Glycol Dehydration EU NOx CO VOC lb/hr TPY lb/hr TPY lb/hr TPY EU-DEHY EU-DEHY A. The glycol dehydration units shall be maintained and operated in accordance with applicable state and federal rules, including but not limited to the following requirements: 1. The glycol dehydration unit shall be equipped with a condenser. All off-gases from the dehydration unit still vent shall be routed through the condenser. 2. All off-gases from the condenser shall be routed to the enclosed flare or to an equally-effective (overall 98% or more) VOC/HAP emissions control system. 3. The glycol dehydrator shall be equipped with a flash tank on the rich glycol stream. Flash tank emissions shall be routed to the reboiler for fuel or to the station inlet, or to an equally-effective (overall 98%) VOC/HAP emissions control system. 4. The combined average natural gas throughput of the glycol dehydration units shall not exceed 84 MMSCFD, monthly average. 5. The lean glycol circulation rate shall not exceed 7.5 gallons per minute for each dehydration unit. If the manufacturer s rating is visible on the pump, or performance data for the model of pump that verifies the maximum pump rate is less than this level, monitoring of pump operating rate shall not be required. 6. Otherwise, the glycol circulation rate shall be monitored and recorded at least once every calendar month. The lean glycol circulation rate shall be recorded for each inspection as follows. Circulation rate, as found (gal/min, strokes/min) Circulation rate, as left (gal/min, strokes/min) Date of inspection Inspected by 7. Records of benzene emissions per 40 CFR Part 63, Subpart HH shall be kept. B. The permittee shall comply with all applicable requirements of the National Emissions Standards for Hazardous Air Pollutants (NESHAP) for Oil and Natural Gas Production, Subpart HH, for each affected dehydration unit including but not limited to the following: 1. Each owner or operator of a glycol dehydration unit that meets the exemption criteria in (e)(1) shall maintain the records specified in (d)(1) for that glycol dehydration unit. [40 CFR through ]

18 SPECIFIC CONDITIONS NO C DRAFT/PROPOSED 3 EUG D Storage Tanks EU NOx CO VOC lb/hr TPY lb/hr TPY lb/hr TPY EU-TK EU-TK EU-TK EU-TK EU-TK EU-TK A. The condensate tanks shall be equipped with a Vapor Recovery Unit (VRU) and back-up flare. B. Total condensate throughput shall not exceed 9,198,000 gallons/yr in any 12-month rolling period. C. EU-TK-6 is subject to OAC 252: Part 7 and must comply by installing a VRU with flare backup. EUG E Condensate Truck Loading Emissions from the equipment listed following are estimated based on existing equipment items but do not have a specific limitation. EU Description Throughput (gal/yr) EU-LOAD-1 Condensate Truck Loading 9,198, Upon issuance of an operating permit, the permittee shall be authorized to operate this facility continuously (24 hours per day, any day of the year). [OAC 252: ] 3. The fuel-burning equipment shall be fueled only with field gas with sulfur content not greater than 343 ppmv or with pipeline-grade natural gas. Compliance can be shown by the following methods: for pipeline grade natural gas, a current gas company bill; for other gaseous fuel, a current lab analysis, stain tube analysis, gas contract, tariff sheet, etc. Compliance shall be demonstrated at least once per calendar year. [OAC 252:100-31] 4. Each engine at the facility shall have a permanent identification plate attached which shows the make, model number, and serial number. [OAC 252:100-43] 5. At least once per calendar quarter, the permittee shall conduct tests of NO x and CO emissions in exhaust gases from the engines in EUG A and from each replacement engine/turbine when operating under representative conditions for that period. Testing is required for any engine/turbine that runs for more than 220 hours during that calendar quarter. Engines/turbines shall be tested no sooner than 20 calendar days after the last test. Testing shall be conducted using a portable analyzer in accordance with a protocol meeting the requirements of the AQD Portable Analyzer Guidance document or an equivalent method approved by Air Quality.

19 SPECIFIC CONDITIONS NO C DRAFT/PROPOSED 4 When four consecutive quarterly tests show the engine/turbine to be in compliance with the emissions limitations shown in the permit, then the testing frequency may be reduced to semiannual testing. Likewise, when the following two consecutive semi-annual tests show compliance, the testing frequency may be reduced to annual testing. Upon any showing of non-compliance with emissions limitations or testing that indicates that emissions are within 10% of the emission limitations, the testing frequency shall revert to quarterly. Any reduction in the testing frequency shall be noted in the next required compliance certification. Reduced testing frequency does not apply to engines with catalytic converters. [OAC 252: (a)(3)(a)] 6. When monitoring shows concentrations or emissions in excess of the limits of Specific Condition No. 1, the owner or operator shall comply with the provisions of OAC 252:100-9 for excess emissions. [OAC 252:100-9] 7. Replacement (including temporary periods of 6 months or less for maintenance purposes), of the internal combustion engines with emissions specified in this permit with engines/turbines of lesser or equal emissions of each pollutant (in lbs/hr and TPY) are authorized under the following conditions. a. The permittee shall notify AQD in writing at least 7 days in advance of start-up of the replacement engine(s)/turbine(s). Said notice shall identify the old engine/turbine and shall include the new engine/turbine make and model, horsepower rating, fuel usage, stack flow (ACFM), stack temperature ( F), stack height (feet), stack diameter (inches), and pollutant emission rates (g/hp-hr, lb/hr, and TPY) at maximum horsepower for the altitude/location. b. Quarterly emissions tests for the replacement engine(s)/turbine(s) shall be conducted to confirm continued compliance with NOx and CO emissions limitations. A copy of the first quarter testing shall be provided to AQD within 60 days of start-up of each replacement engine/turbine. The test report shall include the engine/turbine fuel usage, stack flow (ACFM), stack temperature ( o F), stack height (feet), stack diameter (inches), and pollutant emission rates (g/hp-hr, lbs/hr, and TPY) at maximum rated horsepower for the altitude/location. c. Replacement equipment and emissions are limited to equipment and emissions which are not a modification under NSPS or NESHAP, or a significant modification under PSD. For existing PSD facilities, the permittee shall calculate the PTE or the net emissions increase resulting from the replacement to document that it does not exceed significance levels and submit the results with the notice required by a. of this Specific Condition. d. Engines installed as allowed under the replacement allowances in this Specific Condition that are subject to 40 CFR Part 63, Subpart ZZZZ and/or 40 CFR Part 60, Subpart JJJJ shall comply with all applicable requirements. [OAC 252: (f)(2)] 8. The permittee shall comply with all applicable requirements of the New Source Performance Standards for Stationary Spark Ignition Internal Combustion Engines, Subpart JJJJ, for each affected engine including but not limited to the following: