MEMORANDUM April 1, 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 April 1, 2016 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., Engineering Manager, Existing Source Permit Section Peer Review Jian Yue, P.E., New Source Permits Section Evaluation of Permit Application No C (M-1) BreitBurn Operating, L.P. Dry Trail Gas Plant (SIC 1321) NE/4 of Section 14, T5N, R13E, Texas County Latitude: ; Longitude: Directions: From Main Street (US Highway 64) and US Highway 54 in Guymon, OK, travel north on US Highway 64 approximately 5.2 miles to the junction of US Highway 64 and State Highway 136, then travel north on State Highway 136 approximately 7.8 miles to County Highway 7, then travel west 5 miles to County Road N0800, then travel 3 miles north to County Road E0070, then travel west approximately 2 miles to the facility. SECTION I. INTRODUCTION BreitBurn Operating, L.P. (BreitBurn) has requested a construction permit to authorize the following modifications: 1. Replace the current 2,800-hp Superior 2416G engine manufactured in 1999 with an engine with a maximum horsepower of 3,550 (Engine make and model is undecided at the moment). 2. Modify the glycol dehydration unit to allow for flared emission control. The current configuration recycles both the still vent and flash tank vapors. The new configuration would combust the streams off the condensers for both the still vent and flash tank. 3. Update the flare emission estimates based on increased throughput. 4. Update the list of insignificant tanks. The facility is currently operating as authorized by Permit No TVR2, issued on April 8, 2014.

2 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 2 SECTION II. PROCESS DESCRIPTION The facility operates as a carbon dioxide (CO 2 ) separation and natural gas processing facility. The facility consists of a gas processing plant and a DTP-MEM gas processing facility. The gas processing plant is designed to recover CO 2 and natural gas liquids from a 45.0 MMSCFD low sulfur gas stream associated with the enhanced oil recovery activities. The gas processing plant uses a proprietary process technology known as Ryan-Holmes patented by Process Systems International. The recovered CO 2 is delivered back to the production field for re-injection into the oil producing formation (reservoir). Plant residue gas is used for fuel with the remaining balance being delivered to a low-pressure pipeline system. The Ryan-Holmes process utilizes a total of six compressors, two inlet compressors and four propane compressors. There are five electric motors used for the two inlet compressors and as drivers for three of the propane compressors. The driver for the fourth propane compressor was a Superior 2416G engine and will be replaced with an engine with a maximum horsepower of 3, 550. The Katolite diesel engine powered generator set is used for standby power generation. Feed gas enters the plant through a microprocessor controlled metering facility then flows to the inlet gas filter/separator and subsequently flows to the tri-ethylene glycol (TEG) dehydration plant contactor. Lean TEG absorbs moisture from the natural gas stream. Rich, moisture laden TEG, is regenerated using heat supplied by the hot oil heater. Emissions from the dehydration unit s still vent and flash tank are routed to a process natural gas line using a vapor recovery unit (VRU) and then to the facility inlet. This modification will modify the glycol dehydration unit to allow for flared emission control. This new configuration will be an alternate operating scenario to the current configuration. Dry natural gas then flows to the inlet compressors. The hot compressed inlet gas is then routed to the discharge header and then to the inlet compressor discharge cooler. Cooled gas is then sent to the propane recovery column (PRC). The PRC marks the beginning of the Ryan-Holmes CO 2 purification unit. The Ryan-Holmes process consists of three vessels; the PRC, a de-methanizer, and the gas/gas exchanger. The PRC is a trayed column with inlet gas being introduced in the middle section of the column. The tower is provided with a partial condenser using propane refrigerant. The mixed overhead is then sent to the PRC reflux accumulator where liquids and gas are separated. The vapor from the accumulator is a crude CO 2 product that is split into two streams. One stream is compressed and combined with the liquid CO 2 product from the CO 2 pipeline pumps. The second stream is compressed by the de-methanizer. The liquid from the PRC reflux accumulator is split into two process streams. One stream is used to reflux the PRC and the other is sent to the CO 2 pipeline pumps. Fuel gas for the plant is drawn from the de-methanizer overhead. The bottom product from the PRC is a heavy product composed mostly of C 5+ components that is used as an additive for hydrocarbon removal in the process. This product is discharged from the PRC to the gas/gas exchanger. The PRC also produces natural gas liquids (NGL). The NGL are withdrawn from the middle of the PRC. The NGL are cooled to 120 F and combined with any excess additive and sent to the NGL product storage tank.

3 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 3 The propane refrigeration system provides low temperature levels necessary in the process. Propane vapor is compressed by the refrigerant compressors and combined with propane refrigerant vapors from the refrigerant economizer overhead and then sent to second stage compression and finally to the refrigerant condenser. After condensation, the propane is accumulated in the refrigerant surge tank. Liquid propane flows from the surge tank to either the PRC condenser or the gas/gas exchanger. Propane vapors from the PRC condenser or the gas/gas exchanger are sent back to the refrigeration compressors. The hot oil system for the plant is a closed loop system. Oil is drawn from the heat medium surge tank and goes to the hot oil heater and is heated to 450 ºF. It is subsequently delivered to the dehydration plant and the PRC. The flare was used to control the inlet/propane compressor, accumulator and de-methanizer blowdowns. With this modification, the flare will combust the streams off both the still vent and flash tank as well. The DTP-MEM gas processing facility has three electric compressors for inlet compression and seven electric compressors for reinjection compression. This facility receives low pressure CO 2 rich gas from the nearby Postle Field CO 2 flood. The DTP-MEM separates the CO 2 from hydrocarbon components in the gas through a series of processes that include pre-treatment, selective permeation within membrane modules, and compression, supported by various auxiliary systems. The CO 2 is returned to the Postle Field for re-injection, while the NGL s are sold through a sales pipeline, and the residue gas is either used as plant fuel gas or routed to a sales pipeline. SECTION III. EQUIPMENT EUG-1 Flare EU Point Description Flow (MMSCF/yr) Construction Date 1 1 Flare EUG-3 Hot Oil Heaters EU Point Description MMBTUH Construction Date 1 4a Hot Oil Heater Hot Oil Heater EUG-4 Emergency Generator EU Point Description Rating (KW) Construction Date 1 5 Katolight Generator w/ Detroit Diesel Engine EUG-5 Compressor Engine EU Point Description Horsepower Serial # Manufactured/ Construction Dates 6 11a To Be Determined (TBD) 3,550 TBD TBD

4 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 4 EUG-6 Fugitives EU Point Type of Equipment Type of Service Number Items 1 24 Valves Gas/Vapor 2764 Light Liquid 3563 Heavy Liquid 272 Connectors Gas/Vapor 6122 Light Liquid 5759 Heavy Liquid 278 Flanges Gas/Vapor 1051 Light Liquid 853 Heavy Liquid 72 Pump Seals Light Liquid 28 Heavy Liquid 6 Other 1 Gas/Vapor 291 Light Liquid 115 Heavy Liquid Others include compressor seals, pressure relief valves, relief valves, diaphragms, drains, dump arms, hatches, instruments, meters, polished rods, and vents. EUG-7 Storage Tanks EU Point Facility ID Description Size (Gal.) Const. Date 1 12 T-7103 Process Drain Sump Tank 1, T-7105 Diesel Tank 4, T-7101 Lube Oil Tank 8, T-7104 Ambitrol Tank 8, T-4101 TEG Tank 4, Lube Oil (Day) Tank 1, Methanol Tank Methanol Tank Methanol Tank T-7106 Ambitrol Drain Sump Tank 1, T-1011 Lube Oil (Day) Tank 470 Unknown T-4011 Lube Oil (Day) Tank 470 Unknown T-4012 Lube Oil (Day) Tank 470 Unknown T-4010 Lube Oil Aerial Comp. Tank 8, Synthetic Lube Oil Tank 4, TK-8600 Fresh Water Tank 21, T-4000 Open Drain Sump 1,986 Unknown T-4020 Open Drain Sump 1,986 Unknown Fresh Water Pass Through Tank 8, Open Drain Sump 1,986 Pre 8/23/ Lube Oil (Day) Tank 470 Pre 8/23/ Lube Oil (Day) Tank 470 Pre 8/23/ Lube Oil (Day) Tank 470 Pre 8/23/11

5 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 5 EUG-8 Facility Wide This emission unit group is facility-wide. It includes all emission units and is established to discuss the applicability of those rules or compliance demonstrations, which may affect all sources within the facility. EUG-10 Dehydration Unit EU Point Description Construction Date 1 N/A TEG Dehydration Unit Still Vent/Flash Tank / Off emissions can be either routed to a vapor recovery unit and then to the facility inlet or routed to the flare to be combusted. EUG-11 Blowdowns EU Point Description Construction Date 1 21 Inlet Compressor Blowdowns CO 2e - Recompressor Blowdowns 2006 EUG-12 Loading Emissions EU Point Description Construction Date 1 26 Condensate/Produced Water 1996 EUG-13 Condensate Tank Emissions EU Point Facility ID Description Size (Gal.) Const. Date 1 18 T-7102 Condensate Tank Emissions 19, Engine Parameters Point Source (make/model) Height (feet) Diameter (inches) Flow (ACFM) Temp. ( F) Fuel 1 (SCFH) 5 Katolight Generator , a TBD TBD TBD TBD TBD TBD Based on a fuel heat rating of 924 BTU/SCF; - gallons per hour. SECTION IV. EMISSIONS Emissions estimates for the generator are based on continuous operation and manufacturer s emission data shown below. Emissions estimates for Point 11a are based on continuous operation and the emission factors in Table 1 of NSPS JJJJ for NOx and VOCs. CO is estimated based on manufacturer emission factors for a 3,550 hp engine. Formaldehyde emission estimates for Point 11a were calculated based on the AP-42 emission factor (Manufacturer s data will be provided with the operating permit application). Engine Emission Factors Points Name/Model NO X (g/hp-hr) CO (g/hp-hr) VOC (g/hp-hr) 5 1,096-hp Katolight Generator a 3,550-hp Engine* *Actual engine will comply with NSPS JJJJ emission standard based on manufactured date.

6 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 6 Formaldehyde Emissions from the Engines Points Source MMBTUH Factor Est. Emissions lb/hr TPY 5 1,096-hp Katolight Generator lb/mmbtu 11a 3,550 hp Engine E lb/mmbtu Totals Emission estimates of NO X and CO from the hot oil heaters are based on AP-42 (7/98), Section 1.4 and the heat input rating. Emission estimates of VOC from the and 5.24 MMBTUH hot oil heaters are based on the heat input rating and manufacturers data (0.035 lb/mmbtu) and AP-42 (7/98), Section 1.4, respectively. Emissions from the emergency diesel generator are based on 960 hours of operation a year, the emission factors shown below, a fuel heat content of 137 MBTU/gal, a fuel sulfur content of 0.5% by weight, and AP-42 (9/99), Section 1.3. Emissions from the flare are based on AP-42 (1/95), Chapter 13.5 emissions factors, and combustion of MMSCFY gas stream includes pilot and purge gas, residue gas from the reflux accumulator and de-methanizer upset events, propane compressor gas from maintenance blowdown events, and dehydrator VOC waste stream, with an average heating value of 758 BTU/SCF. Flashing emissions from the condensate tanks were estimated using the Vasquez-Beggs equation, a separator pressure of 100 psig, and a condensate throughput of 5,076 barrels per year (Condensate = 30% Oil). Working and breathing emissions from the condensate tanks was based on TANKS4.0 and a throughput of 16,920 barrels per year. Emissions from the other tanks are considered insignificant and have not been quantified. Emissions from loading of condensate into tank trucks were estimated using a throughput of 16,920 barrels per year of condensate/slop oil and an emission factor of 4.96 lb/1,000 gallons. Fugitive VOC emissions are based on EPA s 1995 Protocol for Equipment Leak Emission Estimates (EPA-453/R ), estimated component counts and C 3+ contents, and an estimated control efficiency for valves in NSPS, Subpart KKK service of 75%. Emissions from the dehydrator were estimated using a mass balance approach based on a gas sample from after the VRU and 98% control efficiency of the flare. Blowdown emissions are based on venting approximately MMSCF/year from the inlet compressors and MMSCF/year from the CO 2e recompressors, a molecular weight of lb/lb-mole, and approximately 3.81% VOC for the inlet compressor stream and 0.54% VOC for the CO 2e recompressor stream.

7 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 7 Facility-Wide Criteria Pollutant Emissions EUG Point 1 NO X CO VOC SO 2 lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY EUG EUG-3 4a EUG EUG-5 11a EUG-6 24 (Fugitives) EUG-7 18 (Tank) EUG-10 Dehy EUG (Blowdowns) EUG (Loadout) Total Total before Modification Emission Changes Based on a fuel sulfur content of 343 ppmv (57 lb SO2 /MMSCF) except for the diesel engine which is based on a fuel sulfur content of 0.5 %S. SECTION V. INSIGNIFICANT ACTIVITIES The insignificant activities identified and justified in the application are duplicated below. Records are available to confirm the insignificance of the activities. Appropriate recordkeeping of activities indicated below with * is specified in the Specific Conditions. Any Activity to which a State of federal applicable requirement applies is not insignificant even if it is included on this list. 1. Space heaters, boilers, process heaters, and emergency flares less than or equal to 5 MMBTUH heat input (commercial natural gas). The glycol dehydration unit s reboiler is rated less than 5 MMBTUH. Other space heaters, boilers, process heaters, and emergency flares may be used in the future. 2. * Emissions from fuel storage/dispensing equipment operated solely for facility owned vehicles if fuel throughput is not more than 2,175 gallons/day, averaged over a 30-day period. None identified but may be used in the future. 3. Emissions from crude oil or condensate marine and truck loading equipment operations at crude oil and natural gas production sites where the loading rate does not exceed 10,000 gallons per day averaged over a 30-day period. Unloading of the condensate into tank trucks is less than 10,000 gallons/day. 4. * Emissions from crude oil and condensate storage tanks with a capacity of less than or equal to 420,000 gallons that store crude oil and condensate prior to custody transfer as defined by Subpart Kb. The condensate tank stores condensate prior to custody transfer and has a capacity less than 420,000 gallons.

8 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 8 5. * Records of tank capacity and contents for 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. The glycol, lube oil, and antifreeze tanks have capacities less than 39,894 gallons and store products having a vapor pressure less than 1.5 psia. 6. Cold degreasing operations utilizing solvents that are denser than air. A parts washer is located onsite and it uses solvents that are denser than air and others may be used in the future. 7. * Activities that have the potential to emit no more than 5 TPY (actual) of any criteria pollutant. No activities were identified at this time but may be in the future. 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 of Air Contaminant Sources) [Applicable] Subchapter 5 requires sources of air contaminants to register with Air Quality, file emission inventories annually, and pay annual operating fees based upon total annual emissions of regulated pollutants. Emission inventories have been submitted and fees paid for the past years. OAC 252:100-8 (Permits for Part 70 Sources) [Applicable] Part 5 includes the general administrative requirements for part 70 permits. Any planned changes in the operation of the facility which result in emissions not authorized in the permit and which exceed the Insignificant Activities or Trivial Activities thresholds require prior notification to AQD and may require a permit modification. Insignificant activities mean individual emission units that either are on the list in Appendix I (OAC 252:100) or whose actual calendar year emissions do not exceed the following limits: 5 TPY of any one criteria pollutant 2 TPY of any one hazardous air pollutant (HAP) or 5 TPY of multiple HAPs or 20% of any threshold less than 10 TPY for a HAP that the EPA may establish by rule Emission limits have been established based on Permit No TVR2 and information in the permit application.

9 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 9 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 0.6 lb/mmbtu from fuel-burning equipment with a rated heat input of 10 MMBTUH or less. For units with a heat input 25 MMBTUH the lowest allowable emission rate is lb/mmbtuh. For external combustion units burning natural gas, AP-42, Table (7/98), lists the total PM emissions for natural gas to be 7.6 lb/mmft 3 or about lb/mmbtu. For 4-cycle rich-burn and lean-burn engines burning natural gas, AP-42 (7/00), lists the total PM emissions as less than 0.02 lb/mmbtu. For large ( 600-hp) diesel-fired CI ICE, AP-42 (10/1996), Section 3.4, lists the total PM emissions as 0.1 lb/mmbtu. The permit requires the use of natural gas for all fuel-burning equipment, except for the diesel-fired emergency generator which is limited to low sulfur diesel, to ensure compliance with Subchapter 19. This subchapter also limits emissions of particulate matter from industrial processes and directfired fuel-burning equipment based on their process weight rates. Since there are no significant particulate emissions from the non fuel-burning processes at the facility compliance with the standard is assured without any special monitoring provisions. OAC 252: (Visible Emissions and Particulate Matter) [Applicable] No discharge of greater than 20% opacity is allowed except for short-term occurrences, which consist of not more than one six-minute period in any consecutive 60 minutes, not to exceed three such periods in any consecutive 24 hours. In no case shall the average of any six-minute period exceed 60% opacity. When burning natural gas there is little possibility of exceeding the opacity standards. OAC 252: (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

10 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 10 cause a problem in this area, therefore it is not necessary to require specific precautions to be taken. OAC 252: (Sulfur Compounds) [Applicable] 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. Part 5 requires removal or oxidation of hydrogen sulfide (H 2 S) from the exhaust gas of any new petroleum or natural gas process equipment. These requirements do not apply if H 2 S emissions do not exceed 0.3 lb/hr. There are no amine or sweetening units at the facility. OAC 252: (Nitrogen Oxides) [Not Applicable] This subchapter limits NO X emissions from new fuel-burning equipment with rated heat input greater than or equal to 50 MMBTUH. None of the engines 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 to be equipped with a permanent submerged fill pipe or with an organic vapor recovery system. The condensate tank is subject to this requirement. Part 3 requires VOC loading facilities with a throughput equal to or less than 40,000 gallons per day to be equipped with a system for submerged filling of tank trucks or trailers if the capacity of the vehicle is greater than 200 gallons. This facility will not be equipped with 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, which is exempt. Part 7 requires fuel-burning and refuse-burning equipment to be operated and maintained so as to minimize VOC emissions. Temperature and available air must be sufficient to provide essentially complete combustion. Part 7 requires all effluent water separators openings or floating roofs to be sealed or equipped with an organic vapor recovery system. There are no effluent water separators 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

11 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 11 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 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] Final 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 [Subparts A, Dc, KKK, JJJJ, and OOOO are Applicable] Subpart A, General Requirements. The flare is subject to the requirements of Subpart Dc, Industrial-Commercial-Institutional Steam Generating Units. This subpart affects industrial-commercial-institutional steam generating units with a design capacity between 10 and 100 MMBTUH heat input and which commenced construction or modification after June 9, The 25 MMBTUH hot oil heater is subject to the recordkeeping requirements of this subpart. All applicable requirements have been incorporated into the permit. Subpart K, Ka, Kb, VOL Storage Vessels. The 19,740-gallon condensate tank is not subject because it is below the threshold level of Subpart Kb of 19,813-gallons. The condensate is produced prior to processing by the plant.

12 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 12 Subpart GG, Stationary Gas Turbines. There are no turbines located at this facility. Subpart VV, Equipment Leaks of VOC in the Synthetic Organic Chemical Manufacturing Industry. The equipment is not in a SOCMI plant but the facility is applicable to Subpart KKK which references some of the standards of Subpart VV. 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 modification after January 20, The natural gas processing plant is subject to this subpart. All applicable requirements have been incorporated into the permit. Subpart LLL, Onshore Natural Gas Processing: SO 2 Emissions. This subpart affects sweetening units and sweetening units followed by a sulfur recover unit which commence construction or modification after January 20, There are no sweetening units at this facility. Subpart IIII, Stationary Compression Ignition (CI) Internal Combustion Engines (ICE). This subpart affects CI ICE manufactured after There are no CI ICE manufactured after 2007 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 numerous manufacture dates. The proposed replacement engine shall comply with all applicable requirements. Subpart OOOO, Crude Oil and Natural Gas Production, Transmission, and Distribution. This subpart was promulgated on August 16, 2012, and per affects the following onshore affected facilities that commence construction, reconstruction, or modification after August 23, 2011: 1. Each gas well affected facility, which is a single natural gas well. 2. 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. 3. 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. 4. Each pneumatic controller affected facility, which is: i. 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. ii. 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. iii. For natural gas processing plants: a single continuous bleed natural gas-driven pneumatic controller.

13 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 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, and has the potential for VOC emissions 6 TPY. Storage vessel means a tank or other vessel that contains an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water. 6. The group of all equipment, except compressors, within a process unit is an affected facility. i. Addition or replacement of equipment for the purpose of process improvement that is accomplished without a capital expenditure shall not by itself be considered a modification under this subpart. ii. Equipment associated with a compressor station, dehydration unit, sweetening unit, underground storage vessel, field gas gathering system, or liquefied natural gas unit is covered by , , , , and if it is located at an onshore natural gas processing plant. 7. Sweetening units located at onshore natural gas processing plants that process natural gas produced from either onshore or offshore wells. i. Each sweetening unit that processes natural gas is an affected facility; and ii. iii. Each sweetening unit that processes natural gas followed by a sulfur recovery unit is an affected facility. Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H 2 S) in the acid gas (expressed as sulfur) are required to comply with recordkeeping and reporting requirements specified in (c) but are not required to comply with through and (g) and (g) of this subpart. There are no affected gas wells, centrifugal compressors, or sweetening units located at this facility. For each new reciprocating compressor the owner/operator must replace the rod packing before 26,000 hours of operation or prior to 36 months. If utilizing the number of hours, the hours of operation must be continuously monitored. Commenced construction is based on the date of installation of the compressor (excluding relocation) at the facility. All compressors that commenced construction after August 23, 2011, are subject to this subpart and any other new or modified compressors will have to comply with this subpart. Continuous bleed natural gas-driven pneumatic controllers at a natural gas processing plant must have a bleed rate of zero. All pneumatic controllers are considered intermittent bleed or are air actuated and are not subject to this subpart. There are no continuous bleed natural gas-driven pneumatic controllers at this facility. Storage vessels constructed, modified, or reconstructed after August 23, 2011, with VOC emissions equal to or greater than 6 TPY must reduce VOC emissions by 95.0 % or greater. All storage vessels are considered existing and are not subject to this subpart.

14 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 14 The proposed changes to the control method for the dehydration unit triggers a modification under Subpart OOOO. Therefore, the process piping fugitive components from the dehydration unit are subject to the equipment leak provisions of this part (40 CFR ). 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 There are no new process units at this facility. All new or modified process units will have to comply with this subpart. All applicable requirements have been incorporated into the permit. 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 affects process streams that contain more than 10% benzene by weight. All process streams at this facility are below this threshold. NESHAP, 40 CFR Part 63 [Subparts 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 HAP, and either process, upgrade, or store hydrocarbon liquids prior to custody transfer or that process, upgrade, or store natural gas prior to entering the natural gas transmission and storage source category. The gas processing plant was a major source after the initial compliance date of this subpart and is subject to the requirements of this subpart. For major sources, the affected sources comprise each of the emission point listed below: 1. Each glycol dehydration unit 2. Each storage vessel with the potential for flash emissions; 3. The group of all ancillary equipment, except compressors, intended to operate in VHAP service, which are located at natural gas processing plants; and 4. Compressors intended to operate in VHAP service, which are located at natural gas processing plants. The dehydration unit is subject to this subpart and is required to comply with applicable requirements. Storage vessel with the potential for flash emissions means any storage vessel that contains a hydrocarbon liquid with a stock tank GOR equal to or greater than 0.31 cubic meters per liter (41.44 SCF/gallon) and an API gravity equal to or greater than 40 degrees and an actual annual average hydrocarbon liquid throughput equal to or greater than 79,500 liters per day (21,000 gal/day). The storage tanks at this facility do not meet the definition of storage vessel with the potential for flash emissions because the throughputs are less than 500 bbl/day and the GOR are less than 1,740 SCF/Barrel. Ancillary equipment (as defined in ) and compressors, that contain or contact a fluid (liquid or gas) that has a total VHAP concentration greater than or equal to 10 percent by weight and that operate in VHAP service 300 hours per year or more are subject to this subpart. This subpart does not apply to ancillary equipment and compressors for which the owner or operator is subject to and controlled under the requirements

15 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 15 specified in 40 CFR Part 60, subpart OOOO. All applicable requirements have been incorporated into the permit. Subpart ZZZZ, Reciprocating Internal Combustion Engines (RICE). This subpart affects any existing, new, or reconstructed stationary RICE located at a major or area source of HAP emissions. Owners and operators of the following new or reconstructed RICE must meet the requirements of Subpart ZZZZ by complying with either 40 CFR Part 60 Subpart IIII (for CI engines) or 40 CFR Part 60 Subpart JJJJ (for SI engines): 1. Stationary RICE located at an area source; 2. The following Stationary RICE located at a major source of HAP emissions: i. 2SLB and 4SRB stationary RICE with a site rating of 500 brake HP; ii. 4SLB stationary RICE with a site rating of < 250 brake HP; iii. Stationary RICE with a site rating of 500 brake HP which combust landfill or digester gas equivalent to 10% or more of the gross heat input on an annual basis; iv. Emergency or limited use stationary RICE with a site rating of 500 brake HP; and v. CI stationary RICE with a site rating of 500 brake HP. No further requirements apply for engines subject to NSPS under this part. A stationary RICE located at an area source of HAP emissions is new if construction commenced on or after June 12, The new engine will commence construction after June 12, 2006, and will comply with this subpart s requirements by complying with requirements of NSPS Subpart JJJJ as applicable. The Katolight Generator engine commenced construction prior to June 12, 2006, has not been modified or reconstructed, and is considered an existing engine. A summary of the requirements for stationary CI RICE located at area sources (e.g. the emergency generator engine located at this facility) are shown in the following table. Engine Category Normal 15% O 2 Existing Emergency CI & Black Start CI Change oil and filter every 500 hours of operation or annually, whichever one comes first; Inspect air cleaner every 1,000 hours of operation or annually, whichever one comes first; and Inspect all hoses and belts every 500 hours of operation or annually, whichever one comes first and replace as necessary. Sources have the option to utilize an oil analysis program in order to extend the specified oil change requirements of this subpart. Other applicable requirements include: 1. The owner/operator must operate and maintain the stationary RICE and after-treatment control device (if any) according to the manufacturer s emission-related written instructions or develop their own maintenance plan which must provide to the extent practicable for the maintenance and operation of the engine in a manner consistent with good air pollution control practice for minimizing emissions. 2. Existing emergency stationary RICE located at an area source of HAP emissions must install a non-resettable hour meter if one is not already installed. All applicable requirements have been incorporated into the permit.

16 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 16 Subpart DDDDD, National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial and Institutional Boilers and Process Heaters. On January 31, 2013, the EPA took final action on its reconsideration of certain issues in the emission standards for the control of HAP from industrial, commercial, and institutional boilers and process heaters at major sources of HAP. This subpart affects major sources of HAPs. This facility is a minor source of HAPs. Subpart JJJJJJ, Commercial and Institutional Boilers. This subpart affects new and existing boilers located at area sources of HAP, except for gas-fired boilers. Gas fired boilers are defined as any boiler that burns gaseous fuel not combined with any solid fuels, liquid fuel only during periods of gas curtailment, gas supply emergencies, or periodic testing on liquid fuel. The boilers at this facility meet the definition of gas fired boilers and are not subject to this subpart. Compliance Assurance Monitoring, 40 CFR Part 64 [Not Applicable] Compliance Assurance Monitoring, as published in the Federal Register on October 22, 1997, applies to any pollutant specific emission unit at a major source that is required to obtain a Title V permit, if it meets all of the following criteria: 1. It is subject to an emission limit or standard for an applicable regulated air pollutant; 2. It uses a control device to achieve compliance with the applicable emission limit or standard; and 3. It has potential emissions, prior to the control device, of the applicable regulated air pollutant greater than major source levels. The new compressor engine may be equipped with a catalyst to meet the applicable NOx and/or CO emissions limits. It is subject to NSPS Subpart JJJJ emissions limitations, thus, meeting the CAM exemption for units subject to emission limitations or standards proposed by the Administrator after November 15, 1990 pursuant to section 111 or 112 of the Act. Therefore, the engine is not subject to CAM. With the modification, the dehydration unit uses a condenser and a flare to meet the applicable emission limits. The potential pre-control device VOC emissions from the dehydration unit are greater than major source levels but the dehydration unit is subject to the small glycol dehydration unit limitations in NESHAP Subpart HH. Because the dehydration unit is subject to emission limitations or standards proposed by the Administrator after November 15, 1990 pursuant to section 111 or 112 of the Act the dehydration unit is not subject to CAM. Chemical Accident Prevention Provisions, 40 CFR Part 68 [Applicable] This facility handles naturally occurring hydrocarbon mixtures at a natural gas processing plant and the Accidental Release Prevention Provisions are applicable to this facility. The facility is required to submit the appropriate accidental release emergency response program plan prior to operation of the facility with more than the threshold quantity of a regulated substance. This facility has submitted their plan to EPA. More information on this federal program is available on the web page:

17 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 17 Stratospheric Ozone Protection, 40 CFR Part 82 [Subparts A and F are Applicable] These standards require phase out of Class I & II substances, reductions of emissions of Class I & II substances to the lowest achievable level in all use sectors, and banning use of nonessential products containing ozone-depleting substances (Subparts A & C); control servicing of motor vehicle air conditioners (Subpart B); require Federal agencies to adopt procurement regulations which meet phase out requirements and which maximize the substitution of safe alternatives to Class I and Class II substances (Subpart D); require warning labels on products made with or containing Class I or II substances (Subpart E); maximize the use of recycling and recovery upon disposal (Subpart F); require producers to identify substitutes for ozone-depleting compounds under the Significant New Alternatives Program (Subpart G); and reduce the emissions of halons (Subpart H). Subpart A identifies ozone-depleting substances and divides them into two classes. Class I controlled substances are divided into seven groups; the chemicals typically used by the manufacturing industry include carbon tetrachloride (Class I, Group IV) and methyl chloroform (Class I, Group V). A complete phase-out of production of Class I substances is required by 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 This application has been determined to be Tier II based on the request for construction permit for a Title V facility. 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.

18 PERMIT MEMORANDUM NO C (M-1) DRAFT/PROPOSED Page 18 Public Review The applicant will publish the Notice of Filing a Tier II Application and the Notice of Draft Permit in a local newspaper for 30 day public review. The draft permit is also available for public review on the Air Quality section of the DEQ web page at State Review This facility is located within 50 miles of the Texas-Oklahoma and Kansas-Oklahoma borders. The states of Texas and Kansas will be notified of the draft permit. EPA Review The permit is also forwarded to EPA for a concurrent 45-day review period. Fees Paid The applicant submitted $5,000, the application fee for a construction permit of a Title V Source. SECTION IX. SUMMARY The applicant has demonstrated the ability to achieve compliance with all applicable Air Quality Rules and Regulations. Ambient air quality standards are not threatened at this site. There is no other active Air Quality compliance or enforcement issues other than those noted above. Issuance of the operating permit is recommended, contingent on public and EPA review.

19 DRAFT/PROPOSED PERMIT TO CONSTRUCT AIR POLLUTION CONTROL FACILITY SPECIFIC CONDITIONS BreitBurn Operating, L.P. Dry Trail Gas Plant (SIC 1321) Permit Number C (M-1) The permittee is authorized to construct in conformity with the specifications submitted to Air Quality on January 27, The Evaluation Memorandum dated April 1, 2016, explains the derivation of applicable permit requirements and estimates of emissions; however, it does not contain operating limitations or permit requirements. Commencing construction and 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 Flare Emissions from EU 1 are based on an estimated combustion efficiency of 98%, AP-42 (1/95), Chapter 13.5 emissions factors, and combustion of MMSCFY gas stream includes pilot and purge gas, residue gas from the reflux accumulator and de-methanizer upset events, propane compressor gas from maintenance blowdown events, and dehydrator VOC waste stream, with an average heating value of 758 BTU/SCF. Emissions from this activity are considered insignificant. EU Point Description NOx CO VOC SO 2 TPY TPY TPY TPY 1 1 Plant Flare a. The permittee shall determine and record the amount of gas vented to the flare (monthly and 12-month rolling totals). b. The permittee shall comply with the NSPS, General Provisions, Subpart A and shall comply with all applicable requirements: [40 CFR 60.1 to 60.19] i General control device and work practice requirements. c. Records of pilot flame(s) outages shall be maintained along with the time and duration of all periods during which the pilot flame is absent. Periods of pilot flame outages shall be an excursion, except during startup, shutdown, or malfunction of the flare and when there are no gases being vented to the flare, and shall be reported in the semi-annual monitoring reports. d. The permittee shall also record and maintain the following: i. The flare design; ii. All visible emission readings, heat content determinations, flowrate measurements, and exit velocity determinations made during the compliance demonstration; and iii. All periods during the compliance determination when the pilot flame was absent.