OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION

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1 OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION MEMORANDUM August 10, 2015 TO: THROUGH: THROUGH: THROUGH: FROM: SUBJECT: Phillip Fielder, P.E., Permits and Engineering Group Manager Rick Groshong, Senior Environmental Manager, Compliance and Enforcement Phil Martin, P.E., Engineering Manager, Existing Source Permits Section Peer Review Mark Chen, P.E., New Source Permits Section Evaluation of Title V Operating Permit Application No TVR3 Regency Field Services, LLC Laverne Compressor Station Latitude N , Longitude W Section 17, Township 3N, Range 28E (CM) Laverne, Beaver County, Oklahoma Directions: From Downtown Laverne, go west 9.5 miles on a paved County Road (EW 21), then, turn north and drive on a paved County Road (NS 165) for 1.5 miles, then, turn west into site. SECTION I. INTRODUCTION Regency Field Services, LLC (Regency) has applied for a renewal of the Part 70 Title V operating permit for their Laverne Compressor Station (SIC Code 1311, NAIC Code ). The Laverne Compressor Station is currently an existing PSD major facility and is operating under Permit No TVR2, which was issued on December 15, The facility was originally constructed in with four engines (CG4, CG5, CG6, and CG7), which were exempted by the rules at that time. The original Title-V Permit No TV was issued on June 29, Engine CG4 was replaced in 1993 and therefore lost its grandfathered status and now CG4 has emission limitations and testing requirements. Regency acquired this facility from El Paso Field Services Company in June The Engine CG6 was removed from the station in 2009 and has not been restored yet, therefore, the CG6 is not included in this Title V permit renewal. After CG6 removal, the facility remains an existing PSD major source facility. The Title V permit renewal application was received by AQD on June 17, This renewed Title- V operating permit is also updated to reflect all current Oklahoma state rules and federal regulations. Upon applicant s request, this permit will proceed through a concurrent public and EPA review. SECTION II. FACILITY DESCRIPTION Natural gas is transported to the facility via a pipeline gathering system. The gas stream from nearby wells enters the facility through inlet separators, where free liquids (condensate and water) are removed from the inlet stream. The natural gas stream then enters the compressors at approximately psig, and leaves the compressors at an approximate gas pressure of

2 PERMIT MEMORANDUM TVR3 2 psig. The compressed gas stream is then transported either to a natural gas processing plant owned by Regency (Mocane Processing Plant) or to a natural gas processing plant owned by other companies. This facility currently contains two 1,100-hp White Superior 8GTL-825 (CG4 and CG5) and one 1,600-hp White Superior 16G-825 compressor engine (CG7). All three engines are four-stroke rich-burn engines without catalytic converters. This facility also has condensate tank, lube-oil tanks, methanol tanks, and antifreeze tank. There is no dehydration unit at the facility. Wastewater and condensate collected and stored in the condensate tank are transported off-site for disposal. The facility is presently operated at a maximum capacity of 25 MMSCF/day. SECTION III. EQUIPMENT Emission units (EUs) have been arranged into Emission Unit Groups (EUGs) in the following outline. All fuel-burning units at the facility use pipeline-quality natural gas or field gas with sulfur content less than 343 ppm. EUG 1 Internal Combustion Engines EU ID# Point ID# EU Name/Model Serial No. Const. Date CG4 EP4 1,100-hp White Superior 8GTL CG5 EP5 1,100-hp White Superior 8GTL-825* CG7 EP7 1,600-hp White Superior 16G-825* * Exempted by the rules at that time EUG 2 VOL Storage Tanks EU ID# Point ID# Contents Capacity Construction Barrels Gallons Date TK1 EP8 New Oil Tank , TK2 EP9 Used Oil 107 4, TK3 EP10 Methanol 27 1, TK4 EP11 Condensate/Slop Oil 85 3, TK5 EP12 Methanol TK6 EP13 Ambitrol 110 4, EUG 3 Fugitive VOC Emission Source EU ID# Emission Unit Number Gas Liquid FUG Compressor Seal 18 0 Pump Seal 0 6 Valve Connectors Relieve Valve 18 0 Stack Parameters Point Source Height Diameter Flow Fuel Usage Temp. ID # Make/Model Feet Inches ACFM SCFH F EP4 1,100-hp White Superior 8GTL ,700 8, EP5 1,100-hp White Superior 8GTL ,700 8, EP7 1,600-hp White Superior 16G ,700 12,400 1,330

3 PERMIT MEMORANDUM TVR3 3 SECTION IV. AIR EMISSIONS Table 1 Emissions Factors Source Qty NOx (g/hp-hr) CO (g/hp-hr) VOC (g/hp-hr) CG4 & CG5 1,100-hp White Superior 8GTL-825 without C.C CG7 1,600-hp White Superior 16G-825 without C.C Based on manufacturer s data, the emission factors for the compressor engines are presented in Table 1. The criteria pollutant emissions are estimated from the compressor engine based on 8,760 hours per year operation. Table 2 lists the engine specifications. Table 2 Engine Specifications Parameter CG4 & CG5 CG7 Manufacturer White Superior White Superior Model 8GTL G-825 Control None None Input Parameter Horsepower (max) 1,100 1,600 Fuel Consumption (BTU/hp-hr) 7,650 7,750 Fuel Usage (SCFH) 8,415 12,400 Stack Diameter (Inches) Height above Grade (Feet) Exhaust Flow (ACFM) 6,700 9,700 Exhaust Temperature ( o F) 925 1,330 Calculated Parameter Moisture Content (%) Table 3 lists the fugitive VOC emissions from the facility. Fugitive emissions are based on Table 2-4 of 1995 Protocol for Equipment Leak Emission Estimates (EPA 453/R ), Oil and Gas Production Operations Average Emission Factors. VOC content in the vapor lines is averaged at 10.00% by weight. Table 3 Fugitive VOC Emissions Emission Units Number of Units VOC (lb/hr-source) VOC Emissions Gas Liquid Gas Liquid lb/hr TPY Compressor Seals Pump Seals Valves Connectors Relief Valves Subtotal

4 PERMIT MEMORANDUM TVR3 4 The tank VOC emissions are estimated using EPA TANKS 4.0.9d program. Condensate liquids are transferred to the condensate tank TK4, where water or aqueous solution is separated from the top-layer organic condensate. VOC flash emissions due to the condensate transfer from the natural gas inlet separator to the atmospheric condensate tank, TK4, are estimated based on the Vasquez-Beggs solution gas-to-oil ratio correlation method with AQD s default parameters. VOC emissions for the condensate truck loading operation are estimated using AP-42 (1/95), Equation (1) in Section 5.2, Transportation and Marketing of Petroleum Liquids, and Tables and VOC emissions were calculated based on 20,000 gallons per year throughput, 62 molecular weight, 7.2 psia true vapor pressure, and 60 F bulk liquid temperatures. VOC emissions from two lube-oil tanks (TK1 & TK2), two methanol storage tanks (TK3 & TK5), and the antifreeze tank (TK6) are considered negligible. Table 4 presents the VOC emissions from truck loading operation. Table 5 lists the total facility-wide emissions. Table 4 VOC Emissions from Condensate Truck Loading Emission Unit Loading Rate Factor VOC Emissions barrel/yr gallon/yr lb/10 3 gallon lb/hr TPY Tank Truck Loading , Table 5 Total Facility-Wide Emissions EU ID Source NOx CO VOC No. lb/hr TPY lb/hr TPY lb/hr TPY CG4 1,100-hp White Superior 8GTL CG5 1,100-hp White Superior 8GTL CG7 1,600-hp White Superior 16G TK4 Condensate Storage Tank* * LOAD Condensate Truck Loading FUG Process Piping Fugitives Total Emissions *Combined emissions from working and breathing losses and flash emissions The primary hazardous air pollutant (HAP) emission from the engines is formaldehyde. Table 6 shows the total formaldehyde emissions from compressor engines. Table 6 Formaldehyde Emissions from Compressor Engines Actual Emissions ID # Source lb/hr TPY CG4 1,100-hp White Superior 8GTL CG5 1,100-hp White Superior 8GTL CG7 1,600-hp White Superior 16G Total Formaldehyde emissions from these engines are estimated based on formaldehyde emission factor derived from AP-42 (7/00), Section 3.2, Table 3.2-3, for uncontrolled 4-cycle rich burn natural gas-fired stationary engines, lb/mmbtu. With the uncontrolled factor and 8,760 hours per year operation, the total formaldehyde emissions from these three engines are estimated as lb/hr and TPY. The facility-wide formaldehyde emissions do not exceed the major source threshold, 10 TPY.

5 PERMIT MEMORANDUM TVR3 5 Potential Greenhouse Gas (GHG) emissions from the facility were estimated using engineering calculations and gas analysis data (mole % value of gas component) from the facility. GHG emissions are expressed as CO 2 e. All CO 2 e 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 regarding CO 2, CH 4, and N 2 O emissions (A combined CO 2 e average emission factor of 117 lb/mmbtu for engines). Table 7. Facility-Wide Greenhouse Gas Emissions Emissions Source Total CO 2 e MTPY TPY CG4, 1,100-hp White Superior 8GTL-825 3, , CG5, 1,100-hp White Superior 8GTL-825 3, , CG7, 1,600-hp White Superior 16G-825 5, , TK4, Condensate Storage Tank LOAD, Condensate Truck Loading FUG, Process Piping Fugitives Total 13, , All other CO 2 e emissions are related to CO 2 or CH 4 emissions and the related global warming potential factor. Emissions from fugitive VOC emissions, FUG, are estimated using API Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry, Section 6.0, Tables 6-12 and Emissions from tank sources are estimated using Process Simulation for the facility. Emissions from truck loading are estimated using API Compendium Sections 5.4 and 5.5, and Appendix B. Table 7 lists annual potential facility-wide Greenhouse Gas emissions. GHG emissions are estimated and presented as metric ton per year (MTPY) and ton per year (TPY). The GHG emissions do not exceed a PTE of 100,000 TPY CO 2 e. SECTION V. INSIGNIFICANT ACTIVITIES The insignificant activities identified and justified in the application are duplicated below. Appropriate record keeping of activities indicated below with *, is specified in the Specific Conditions. 1. Space heaters, boilers, and emergency flares less than or equal to 5 MMBTU/hr heat input (commercial gas). None identified but may be required in the future. 2. Emissions from condensate tanks with a design capacity of 10,000 gallons or less in ozone attainment areas. One 3,572 gallon condensate tank on site. 3. * 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. An Ambitrol, a used oil, and oil tank are located on site. 4. Emissions from crude oil or condensate storage marine and truck loading equipment operations at crude oil and natural gas production sites where the loading rate does not

6 PERMIT MEMORANDUM TVR3 6 exceed 10,000 gallons per day averaged over a 30-day period. The condensate tank is emptied a maximum of once a month, therefore, the loading rate will be much less than this limit. 5. * Welding and soldering operations utilizing less than 100 pounds of solder and 53 tons per year of electrodes. None identified but may be required in the future. 6. * Surface coating and degreasing operations which do not exceed a combined total usage of more than 60 gallons/month of coatings, thinners, clean-up solvents, and degreasing solvents at any one emission unit. One 5-gallon solvent bath on site. Usage is about 20 gallons/year or 2 gallons/month. 7. Exhaust systems for chemical, paint, and/or solvent storage rooms or cabinets, including hazardous waste satellite (accumulation) areas. None identified but may be required in the future. 8. * Activities that have the potential to emit no more than 5 TPY (actual) of any criteria pollutant. VOC tank emissions from TK3 and two methanol tanks, TK4 and TK5, have annual emissions below these limits, 5 TPY. SECTION VI. 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 establishes general administrative requirements for Part 70/Title V Permits. Any changes in the operation of the facility which could potentially result in emissions not authorized in the permit and which do not meet the definitions of Insignificant Activities or Trivial Activities may require prior notification to AQD and/or a permit modification. Insignificant Activities refer to individual emission units that either are specifically identified in Appendix I (OAC 252:100) or for which actual calendar year emissions do not exceed the following limits: 5 TPY of any one criteria pollutant;

7 PERMIT MEMORANDUM TVR3 7 2 TPY of any one HAP or 5 TPY of multiple HAPs or 20% of any threshold less than 10 TPY for single HAP that the EPA may establish by rule; Emission limits for the facility are based on the previous Title V permit, No TVR2, and the permit renewal application. 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 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) [Applicable] This subchapter specifies a particulate matter (PM) emissions limitation of 0.51 lb/mmbtu from fuel-burning equipment with a rated heat input of 20 MMBTUH or less (compressor engine CG-7 is rated at 12.4 MMBTUH). For 4-cycle rich-burn engines, AP-42 (7/00), Table lists the total PM emissions for natural gas to be 0.02 lbs/mmbtu. The permit requires the use of natural gas for all fuel-burning units to ensure compliance with Subchapter 19. This subchapter also limits emissions of PM from industrial processes. Per AP-42 factors, there are no significant PM emissions from any other industrial activities at this facility. 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 little possibility of exceeding the opacity standards. 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 a problem in this area, therefore it is not necessary to require specific precautions to be taken.

8 PERMIT MEMORANDUM TVR3 8 OAC 252: (Sulfur Compounds) [Applicable] Part 5 limits sulfur dioxide emissions from new petroleum or natural gas process 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. OAC 252: (Nitrogen Oxides) [Not Applicable] This subchapter limits NOx emissions from new fuel-burning equipment with rated heat input greater than or equal to 50 MMBTUH to emissions of 0.2 lb of NOx per MMBTU. 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 cupola, blast furnace, basic oxygen furnace, petroleum catalytic cracking unit, or petroleum catalytic reforming unit. OAC 252: (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. This applies to the condensate tank, TK-3. 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 from any coating line or other coating operation. This facility does not normally conduct coating or painting operations except for routine maintenance of the facility and equipment. No coating operation is located at this facility. Part 7 requires fuel-burning and refuse-burning equipment to be operated to minimize emissions of VOC. The equipment at this location is 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. No effluent water separators are located at this facility. 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 AOC has been designated there are no specific requirements for this facility at this time.

9 PERMIT MEMORANDUM TVR3 9 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 Emissions 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: Grain Elevators not in source category OAC 252: Nonattainment Areas not in area category OAC 252: Municipal Solid Waste Landfills not in source category SECTION VII. FEDERAL REGULATIONS PSD, 40 CFR Part 52 [Not Applicable At This Time] Final total facility emissions are greater than the PSD major source threshold of 250 TPY for regulated pollutants NOx. The facility is considered an existing major source for PSD and any future emission increases must be evaluated for PSD if they exceed a significance level (40 TPY for NOx, 100 TPY for CO, 40 TPY for VOC, 40 TPY for SO 2, 25 TPY for TSP, 15 TPY for PM 10, 10 TPY for PM 2.5, 0.6 TPY for Pb, and 10 TPY for TRS). NSPS, 40 CFR Part 60 [Not Applicable] Subparts K, Ka, Kb, VOL Storage Vessels. Subpart Kb regulates hydrocarbon storage tanks larger than 19,813 gallons capacity and built after July 23, All tanks on site are below the threshold, 19,813 gallons. This subpart is not applicable. Subpart GG, Stationary Gas Turbines. There are no turbines at this facility. The compressors here are powered by reciprocating engines. Subpart VV, Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry. This facility is not a SOCMI plant. Subpart KKK, Equipment Leaks of VOC from Onshore Natural Gas Processing Plants. This subpart applies to natural gas processing plants that commence construction, reconstruction, or

10 PERMIT MEMORANDUM TVR3 10 modification after January 20, 1984, and include the following facilities located at on-shore natural gas processing plants: a compressor station, dehydration unit, underground storage tank, field gas gathering system, or liquefied natural gas unit located at an on-shore natural gas processing plant. "Natural gas processing plant" is defined as any site engaged in the extraction of natural gas liquids from field gas, fractionation of natural gas liquids, or both; "Natural gas liquids" are further defined as hydrocarbons such as ethane, propane, butane, and pentane. This site does not engage in this type of activity. Therefore, this facility is not subject to Subpart KKK. Subpart LLL, Onshore Natural Gas Processing: SO 2 Emissions. There is no natural gas sweetening operation at this site. Subpart IIII, Stationary Compression Ignition (CI) Internal Combustion Engines (ICE). This subpart affects CI ICE manufactured after There are no CI-ICE at this facility. Subpart JJJJ, Stationary Spark Ignition Internal Combustion Engines (SI-ICE). This subpart 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 manufacture date. 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 current three existing engines were manufactured prior to June 12, 2006, and have not been reconstructed, therefore, all three engines are not subject to this subpart. 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) (c) (d) 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.

11 PERMIT MEMORANDUM TVR3 11 (e) (f) (g) 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. There are no gas wells, centrifugal compressors, or sweetening units located at this facility and this facility is not a gas plant. 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 of installation of the compressor (excluding relocation) at the facility. The compressors at the facility are considered existing and have not been modified or reconstructed. Any new or modified compressors will have to comply with this subpart in the future. Single continuous bleed natural gas driven pneumatic controllers constructed, reconstructed, or modified one year after promulgation of the rule shall not have a natural gas bleed rate greater than 6 SCFH and must be tagged. All pneumatic controllers installed one year after promulgation of this rule at this facility will have to comply with this subpart in the future. 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. The storage vessels at the facility are considered existing and have not been modified or reconstructed. All new or modified storage vessels will have to comply with 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. 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. There is no affected equipment at the time of this permit issuance; however this permit will require the facility to comply with all relevant requirements of NSPS, Subpart OOOO if they become applicable. NESHAP, 40 CFR Part 61 [Not Applicable] There are no emissions of any of the regulated pollutants: arsenic, asbestos, beryllium, benzene, coke oven emissions, mercury, radionuclides or vinyl chloride except for trace amounts of benzene. Subpart J, Equipment Leaks of Benzene, only applies to process streams which contain more than 10% benzene by weight. Analysis of Oklahoma natural gas indicates a maximum benzene content of less than 1%.

12 PERMIT MEMORANDUM TVR3 12 NESHAP, 40 CFR Part 63 [Not Applicable] Subpart HH, Oil and Natural Gas Production Facilities. The EPA promulgated the final rule for Subpart HH at area oil and gas production facilities, effective January 3, This MACT was also extended to area sources on January 3, This subpart applies to triethylene glycol (TEG) dehydration units at area sources affected emission points that are located at facilities that are major sources of HAP emissions 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 the purposes of this subpart, natural gas enters the natural gas transmission and storage source category after the natural gas processing plant, when present. If no natural gas processing plant is present, natural gas enters the natural gas transmission and storage source category after the point of custody transfer. There is no dehydration unit at the facility and the potential HAP emissions are below the 10/25 TPY threshold, so this subpart is not applicable. Subpart HHH, affects Natural Gas Transmission and Storage Facilities. Since this facility is a production facility, this subpart does not apply. Subpart YYYY, Stationary Combustion Turbines. This subpart affects stationary gas turbines located at a major source of HAP emissions. There are no combustion turbines at this facility. Subpart ZZZZ, Reciprocating Internal Combustion Engines (RICE). This subpart affects any existing, new, or reconstructed stationary RICE at a major or area source of HAP emissions, except if the stationary RICE is being tested at a stationary RICE test cell/stand. The following table differentiates existing, new, or reconstructed units based on their construction dates. Construction/Reconstruction Dates Engines >500 hp Engines 500hp Existing Unit Located at Major HAP Source Before 12/19/02 Before 6/12/06 Located at Area HAP Source Before 6/12/06 New or Reconstructed Unit Located at Major HAP Source On and After 12/19/02 On and After 6/12/06 Located at Area HAP Source On and After 6/12/06 The following table lists the status of each engine at this facility: EU ID# Make/Model Construction Date Status CG4 1,100-hp White Superior 8GTL stroke rich-burn without control 1993 Existing CG5 1,100-hp White Superior 8GTL stroke rich-burn without control 1975 Existing CG7 1,600-hp White Superior 16G stroke rich-burn without control 1976 Existing All three engines fall under existing units located at an area HAP source category and were required to comply with applicable emission limitations and operating limitations no later than October 19, Initial performance test or other initial compliance demonstration according to Tables 4 and 5 to this subpart shall be conducted within 180 days after the compliance date. Specific requirements in are listed in the following table.

13 PERMIT MEMORANDUM TVR3 13 Engine Category Existing Non-Emergency, Non-Black Start, 4SRB > 500-hp, Remote Stationary RICE Existing Non-Emergency, Non-Black Start, 4SLB > 500-hp, Remote Stationary RICE Requirements From Table 2d to Subpart ZZZZ of Part 63 Change oil and filter, inspect spark plugs, and inspect all hoses and belts every 2,160 hours of operation or annually, whichever comes first. Change oil and filter, inspect spark plugs, and inspect all hoses and belts every 2,160 hours of operation or annually, whichever comes first. 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 100 TPY The exempted units (CG5 and CG7) located at this source are not subject to an emission limit or standard for any regulated air pollutant. None of the emission units located at this source use a control device to achieve compliance with the applicable emission limits or standards for any regulated air pollutant, so this subpart is not applicable. 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. This facility does not process or store more than the threshold quantity of any regulated substance (Section 112r of the Clean Air Act 1990 Amendments). More information on this federal program is available on the web page: 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

14 PERMIT MEMORANDUM TVR3 14 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 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, Subpart F requires that any persons servicing, maintaining, or repairing appliances except for motor vehicle air conditioners; persons disposing of appliances, including motor vehicle air conditioners; refrigerant reclaimers, appliance owners, and manufacturers of appliances and recycling and recovery equipment comply with the standards for recycling and emissions reduction. The standard conditions of the permit address the requirements specified at for persons opening appliances for maintenance, service, repair, or disposal; for equipment used during the maintenance, service, repair, or disposal of appliances; for certification by an approved technician certification program of persons performing maintenance, service, repair, or disposal of appliances; for recordkeeping; for leak repair requirements; and for refrigerant purchase records for appliances normally containing 50 or more pounds of refrigerant. SECTION VIII. COMPLIANCE Tier Classification and Public Review This application has been determined to be Tier II based on the request for renewal of a Part 70 operating permit. 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, which will be used to accomplish the permitted purpose. The applicant published the Notice of Filing a Tier II Application in The Herald-Democrat, a weekly newspaper printed and published in the City of Beaver, Beaver County, on July 2, The notice stated that the permit application was available for public review at the Beaver County Pioneer Library located at 201 Douglas Ave., Beaver, Oklahoma 73932, or at the Air Quality Division s Main Office in Oklahoma City, Oklahoma. The draft permit was also available for public review on the Air Quality Section of the DEQ Web Page at This permit has been approved for concurrent public and EPA review. The EPA review will be conducted concurrently with the public review and if no comments are received from the public, then, the draft permit will be deemed the proposed permit. Public review period will be 30 days and EPA review period will be 45 days. This facility is located within 50 miles of the Oklahoma - Kansas border and the Oklahoma - Texas border. The states of Kansas and Texas have been notified of the draft permit. Information on

15 PERMIT MEMORANDUM TVR3 15 all permit actions is available for review by the public in the Air Quality Section of DEQ Web Page: Inspection On Wednesday, October 29, 2014, from 1114 to 1127 hours, an Air Quality full compliance evaluation (FCE) was conducted at the Laverne Compressor Station. The compliance evaluation was conducted by Mr. Oba Hughes, Environmental Programs Specialists for the Department of Environmental Quality, Air Quality Division. Mr. Doug Bobeck, Mocane Supervisor and Mr. Curtis Patrick, Compressor Mechanic, represented Regency. The facility was constructed and is operating as described in the permit renewal application. The engine CG6 was not located in the station. Identification plates with the make, model, and serial number were attached to the engine. Periodic engine testing records, maintenance logs, and other required records are maintained at the station office and also maintained at the Mocane Processing Plant Office located in Mocane, Beaver County. In this FCE, no compliance issues were discovered. Since there are no physical changes at the facility from October 2014 to July 2015, there is no need to inspect the facility again. Testing The CG4 engine emission testing was conducted quarterly. Some test results in 2014 and in 2015 are presented below and show compliance with the applicable permit conditions. EU CG4 Source 1,100-hp White Superior 8GTL-825 Testing Permit Limitations Test Results NOx CO NOx CO Date lb/hr lb/hr lb/hr lb/hr 3 rd Qtr/ th Qtr/ st Qtr/ nd Qtr/ Fees Paid Part 70 operating permit renewal application fee of $7,500 was received on June 17, SECTION IX. SUMMARY The facility was constructed and is operating as described in the permit application. Ambient air quality standards are not threatened at this site. There are no other active Air Quality compliance or enforcement issues concerning this facility. Issuance of the operating permit is recommended, contingent on EPA and public review.

16 PERMIT TO OPERATE AIR POLLUTION CONTROL FACILITY SPECIFIC CONDITIONS Regency Field Services, LLC Laverne Compressor Station Permit No TVR3 The permittee is authorized to operate in conformity with the specifications submitted to Air Quality on June 17, 2015, and on July 10, The Evaluation Memorandum dated August 10, 2015, explains the derivation of applicable permit requirements and estimates of emissions; however, it does not contain operating limitations or permit requirements. Continuing operations 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: (a)(1)] EUG 1: Emission units, CG5 and CG7, are exempt internal combustion engines based on DEQ regulations between 1972 and 1979 and are limited to the existing equipment as it is. EU ID# Point ID# EU Name/Model Serial No. CG5 EP5 1,100-hp White Superior 8GTL CG7 EP7 1,600-hp White Superior 16G Emission unit, CG4, is limited to the following emissions. Emission Unit Permitted Emissions EU ID # EU Name/Model NOx CO VOC CG4 1,100-hp White Superior 8GTL-825 lb/hr TPY EUG 2: Storage tank VOC emissions are estimated based on existing equipment items and categorized as insignificant activities. EU ID# Contents Capacity Barrels Gallons TK4 Condensate/Slop Oil 85 3,572 a. Condensate storage tank, TK4, shall be operated with a submerged fill pipe. [OAC 252: (b)] b. VOC emissions shall combine all emissions from working and breathing losses and flash emissions.

17 SPECIFIC CONDITIONS TVR3 2 EUG 3 Fugitive VOC emissions are estimated based on existing equipment items but do not have a specific limitation. EU ID# Emission Unit Number Gas Liquid FUG Compressor Seal 18 0 Pump Seal 0 6 Valve Connectors Relieve Valve The fuel-burning equipment shall be fired with pipeline grade natural gas or other gaseous fuel with a sulfur content less than 343 ppmv. 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, or other approved methods. Compliance shall be demonstrated at least once every calendar year. [OAC 252:100-31] 3. The permittee shall be authorized to operate this facility continuously (24 hours per day, every day of the year). [OAC 252: (a)(1)] 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 NOx and CO emissions in exhaust gases from engine CG4 and each replacement engine when operating under representative conditions for that period. Testing is required for any engine or replacement engine, which runs for more than 220 hours during that calendar quarter. Engines shall be tested no sooner than 20 days after the last test. Testing shall be conducted using a portable engine analyzer in accordance with a protocol meeting the requirements of the AQD Portable Analyzer Guidance document or an equivalent method approved by Air Quality. When four consecutive quarterly tests show an engine to be in compliance with the emissions limitations shown in the permit, then the testing frequency may be reduced to semi-annual testing. A semi-annual test may be conducted no sooner than 60 calendar days nor later than 180 calendar days after the most recent test. Likewise, when the following two consecutive semi-annual tests show compliance, the testing frequency may be reduced to annual testing. An annual test may be conducted no sooner than 120 calendar days nor later than 365 calendar days after the most recent test. Upon any showing of non-compliance with emissions limitations or testing that indicate that emissions are within 10% of the emission limitation, the testing frequency shall revert to quarterly. Reduced engine testing does not apply to engines with catalytic converters/oxidation catalysts. [OAC 252: (a)(3)(a)] 6. When periodic compliance testing shows engine exhaust emissions in excess of the lb/hr limits in Specific Condition Number 1, the permittee shall comply with the provisions of OAC 252: [OAC 252:100-9]

18 SPECIFIC CONDITIONS TVR Replacement (including temporary periods of up to six months for maintenance, etc.) of internal combustion engines shown in this permit with engines of lesser or equal emissions of each pollutant is authorized under the following conditions: [OAC 252: (f)] a. The permittee shall notify AQD in writing not later than 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. Replacement engines/turbines for Grandfathered emission units become subject to emission limitations. 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. 8. The permittee shall comply with NSPS, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transportation, and Distribution, for all affected equipment located at this facility as they become applicable. [40 CFR to ] a What is the purpose of this subpart? b Am I subject to this subpart? c When must I comply with this subpart? d What standards apply to gas well affected facilities? e What standards apply to centrifugal compressor affected facilities? f What standards apply to reciprocating compressor affected facilities? g What standards apply to pneumatic controller affected facilities? h What standards apply to storage vessel affected facilities? i What equipment leak standards apply to affected facilities at an onshore natural gas processing plant? j What are the exceptions to the equipment leak standards for affected facilities at onshore natural gas processing plants?