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219-083
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N U v J v m E m E E O � m Z v m N O O J N N O Q A ¢ J v E a. O N c d U U 22�O o M c`V � 0 a � E o Q N E Q c 0 0 m z j v/ W O Z _ 0 L Q 2 E d T v U Q E o o m m i p m z v � m o m 0 m 0 m 0 m 0 m 0 m rn N m mm O OY ryZ N r O� o o 'o 0 0 o E J'-� c ❑ O D o T M W T N W C w m a y C o N = N Z aai y w m C o N Z O a' F m U p m c y C y Q o co Q o 0 C C O Vp U U U U f _ U JU m,N .yC N m OG .a 'o 2a EE nOy p p ❑ p ❑ ❑ y LL O ON O O N O w w w w w w; Z U ' v U STATE OF ALASKA JUL F aQf� ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT ANRC� OC 1a. Well Status: Oil Q Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended[_] 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development 2 Exploratory ❑ GINJ ❑ WINJ ❑ WAG[—] WDSPL ❑ No. of Completions: _ 1 Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Abend.: 7/2/2019 14. Permit to Drill Number/ Sundry: 219-083 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: June 13, 2019 15. API Number: 50-029-23636-00-00 4a. Location of Well (Governmental Section): Surface: 5037' FSL, 321' FEL, Sec 14, T13N, R9E, UM, AK Top of Productive Interval: 384' FNL, 870' FWL, Sec 13, T13N, R9E, UM, AK Total Depth: 588' FSL, 287' FWL, Sec 24, T13N, R9E, UM, AK 8. Date TO Reached: June 26, 2019 16. Well Name and Number: MPU M-20 ' 9. Ref Elevations: KB: 59.1'' GL: 24.9' BF: 24.9' ' 17. Field / Pool(s): Milne Point Field Schrader Bluff Oil Pool 10. Plug Back Depth MDTFVD: 14,825' MD / 3,622' TVD 18. Property Designation: ADL355023; ADL388235!ADL025514 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 533843 y- 6027889 - Zone- 4 TPI: x- 535035 y- 6027752 Zone- 4 Total Depth: x- 534503 y- 6018163 Zone- 4 11. Total Depth MDrI VD: r 14,830' MD / 3,623' TVD 19. DNR Approval Number: LONS 16-004 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD1TVD: 2,232' MD / 1,862' TVD 5. Directional or Inclination Survey: Yes ✓ (attached) No Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD1TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of lags to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary ROP/ABG/DGR/EWR/ADR 2"/5" MD ABG/DGR/EWR/ADR 2"/5" TVD PB1, P82 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT GRADE SETTING DEPTH MD SETTING DEPTH ND AMOUNT CEMENTING RECORD PULLED TOP BOTTOM TOP BOTTOM HOLE SIZE 20" 216# X-52 Surface 114' Surface 114' 42" *270 ft3 9-5/8" 40# L-80 Surface 5,187' Surface 3,880' 12-1/4" Stg 1 L - 350 sx / T - 400 sx Stg 2 L - 460 sx / T - 270 sx 237 bbls 7" 26# L-80 Surface 5,029' Surface 3,864' Tieback Tieback Assy. 6-5/8" 20# L-80 5,017' 14,830' 3,862' 3,623' 8-1/2" Cementless Slotted Liner 24. Open to production or injection? Yes 0 No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 6-5/8" Liner run on 6/29/19 **Please see attached schematic for Slotted/Solid Liner Details" COMPLETION D 'T 2 0 VE. IF ED 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4-1/2" 5,060' 4,770' MD / 3,793' ND 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ❑ No Q Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: 7/19/2019 Method of Operation (Flowing, gas lift, etc.): Jet Pump Date of Test: 7/21/2019 Hours Tested: 24 Production for Test Period Oil -Bbl: 1181 Gas -MCF: 572 Water -Bbl: 1954 Choke Size: N/A Gas -Oil Ratio: 484 Flow Tubing Press. 371 Casing Press: 3477 Calculated 24 -Hour Rate 0� Oil -Bbl: 1181 Gas -MCF: 572 Water -Bbl: 1954 Oil Gravity - API (corr): 16 ' Form 10-407 Revised 5/2017Jd+8g /� sat ,..�L (� COJew,EDON PAGE 2 RBDMS �jUL 2 6 2019 Submit ORIGINIAL only^ 28. CORE DATA Conventional Core(s): Yes ❑ No ❑✓ Sidewall Cores: Yes ❑ No ❑A If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 2,232' 1,862' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval SB OA 5,204' 3,881' information, including reports, per 20 AAC 25.071. SV5 1,401' 1,320' SV1 2,292' 1,904' Ugnu LA3 3,801' 3,198' SB NA 4,563' 3,706' SB OA 5,126' 3,875' Formation at total depth: SB OA 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report, OH Sidetrack Summary. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: Cdln of hIICOr .COm Authorized Contact Phone: 777-8389 Signature: Date: INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 512017 Submit ORIGINAL Only fiilwrP Alaska, LLC Ong. KB Elev.: 59.1'/ GL Elev.: 24.9' 11 7- 20r' 35'8"ES' Cenaiter @ ' 2,386' i 3 4 4 4 L'I 7' - 5 6 7 Mn ID e 2-75D 9 35/8" See "10""9 Said Liner 11 Detail 65/8 I I I I I I] ShceC� IAIA 10 SCHEMATIC TREE & WELLHEAD Milne Point Unit Well: MPU M-20 Last Completed: 7/2/19 PTD: 219-083 Tree Cameron 31/8" SM Wellhead FMC 11"5M TC-lAw/11"x31/2"TC-I1 Top and Bottom Tubing 12-1/4" 2nd stage Hanger with 3" CIW "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 42" 50 bbls(10 Yards Pilecrete dumped down backside) 12-1/4"lst stage L-350 sx/T-400 sx 12-1/4" 2nd stage L-460 sx/T-270 sx 8-1/2" Cementless Slotted Liner in 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x34" Conductor (insulated) 215.5/X-52/Weld N/A Surface 114' N/A 9-5/8" Surface 40/L-80/T%P 8.679" Surface 5,187' 0.0758 7" Tieback 26/L-80/TXP 6.151" Surface 5,029' 0.0383 6-5/8" Slotted Liner 20/L-80/HydriI 563 5.924" 5,017' 14,830' 1 0.0355 TUBING DETAIL 41/2" Tubing 12.6 / L-80 / TXP 1 3.958" 1 Surface 1 5,060' 1 0.0087 WELL INCLINATION DETAIL KOP @ 410' Max Hole Angle = 68 @ let Pump Max Hole Angle = 68 @ XN profile Max Hole Angle = 83 @ Tubing tail Max Hole Angle = 96 JEWELRY DETAIL No. Top MD Item Drift lD Btm (TVD) 4 Upper Completion 3,865' 1 29' Tubing Hanger (4-1/2" TC -ll Top & Btm) 3.970" 3 4,709' 4.5" Discharge Pressure Gauge Mandrel (Discharge Gauge) 3.874" 4 4,720' 4.5" XD Sliding Sleeve 3.813" 5 4,729' 4.5"Gauge Mandrel w/ X" Wire(intake Gauge) 3.889" 6 4,749' 4.5" X Nipple (3.813" Packing Bore) 3.813" 7 4,770' 7" x 4.5" PHL Retrievable Packer 3.890" 8 4,797' 4.5" XN Nipple RHC -P set 3.813" 9 5,060' 4.5" WLEG 3.958" Lower Completion 10 5,017' BOT SLZXP Liner Top Packer w/BD Slips 7" x 9-5/8" 6.170" 11 5,029' 7" Tieback Assy. (8.25" OD No -Go) 6.151" 12 5,038' 7" Hydril 563 L-80 x 6-5/8" HydriI 563 L-80 XO 5.924- 14 14,825' WIV(Ball On Seat) 4-1/2" SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 5,043' 3,865' 5,204' 3,881' 4 7,344' 3,860' 7,501' 3,855' 14 12,219' 3,624' 12,780' 3,658' 4 13,865' 3,628' 14,024' 3,630' 1 14,226' 3,628' 14,266' 3,627' P,, Hole .14,830' 13 TD=14,830'(MD)/TD=3,623'VVD) GENERAL WELL INFO PBTD=14,825'(MD)/TD=3,622'(ND) qP1: 50-029-23636-00-00 Drilled and Completed by Doyon 14-7-2-19 4-1/2" Slotted LINER DETAIL its (Mp) Top (TVD) Btm (MD) Btm (TVD) 53 5,204' 3,881' 7,344' 3,860' 104 7,501' 3,855' 12,219' 3,624' 27 12,780' 3,658' 13,865' 3,628' 5 14,024' 3,630' 14,226' 3,628' 13 14,266' 3,627' 14,789' 3,621' Revised By: UD 7/8/2019 H Well Name: MP M-20 Field: Milne Point Unit County/State: , Alaska (LAT/LONG): avation (RKS): API #: 50-029-23636-00-00 Spud Date: 6/13/2019 Job Name: 1912739D MPU M-20 Drilling Contractor AFE #: AFE $: Hilcorp Energy Company Composite Report ,RcNuEty, Date, _ Ops Summary _. 6/12/2019 See M-18 for details.;Move Rig off M-18, around the pad, set matting boards around well and spat & shim Rig level over Well M-20.;Skid Rig Floor into Drilling position, Spot Rockwasher, cuttings tank and fuel trailer into place - Berm Cuttings Tank. Orient surface annular and knife valve for diverter line placement. Sim ops: Prep mud pits for mud and rig up steam, air and water to the rig Floor. Move rig mats from rig move.;lnstall 16 Diverter line. N/U surface stack and install bell nipple & Hser.;Spot support buildings, install koomey lines on annular preventer and knife valve. Load 5" DP in shed. Prep TopDrive for CIO saver sub. Workind on rig acceptance checklist. 6/13/2019 Continue R/U and work on rig acceptance checklist, load and strap 171 #a 5" DP, work on drag chain, C/O saver sub, inspect backup dies, good. Energize accumulator, check for leaks, good. Loading 8.8 spud mud in pits. Rig on high line power @ 09:00. Accept rig @ 08:OO.;Continue to load, strap and tally 171 jts 5" DP, Load 17 jts 5" HWDP in shed.; Drift and P/U 5" DP using mouse, racking stands in derrick. Continue to complete items on acceptance checklist.;Perform diverter function test on 5" drill pipe. Test gas alarms and PVT sys. Test witnessed by AOGCC insp Austin McLeod. Knife valve opened in 15 seconds & annular closed in 29 seconds.;Accumulators: 3000 PSI system, 1800 PSI after closure, 35 sec. 200 PSI recharge, 162 sec. full recharge. 6 bottle average = 2016 psi.;Continue to Drift and P/U 5" DP using mouse, racking stands in derrick. 57 total stands racked back.;Drift and P/U 5" HWDP, racking stands in Derrick. Total of 6 stands HWDP, 1 stand w/ Jars.;Pre-spud meeting with Doyon, MI and Sperry. M/U new 12-1/4" Kymera bit, 8" SperryDrill motor set at 1.5", XO sub and stand of 5" HWDP. RIH at tan bottom on depth at 114'. Flood lines and pressure test to 3500 PSI - (,food test.; Drill 12-1/4" surface hole from 11 4'to 217', 103 drilled, 52'/hour AROP. 400 GPM = 480 PSI, 40 RPM = 1 K TQ, 3K WOB. PU 50K / SO 50K / ROT 50K. 8.8 ppg MW, 300+ vis.;CBU @ 400 GPM - 480 psi. Backream 1 std @ 40 RPM V 120'. Continue POOH on elevators U Motor @ 33'.;M/U Remaining Directional BHA #1 with DM Collar, DGR, EWR, PWD HCIM & TM Collar, Carry Scribe and upload MWD. P/U 3 NMFC & RIH to 191'.;Establish circulation and wash down U 217'@ 445 gpm. No fill observed. Drill 12-1/4" surface hole from 217' to 373', 448 GPM = 980 PSI, 40 RPM = 1 K TO, 5K WOB. PU 62K / SO 67K / ROT 65K. 8.9 ppg MW, 300+ vis.;Hauled 680 bbls H2O from M -Pad (Nopoint Creek) for total= 680 bbls Hauled 0 bbls heated H2O from G&I for total = 0 bbls Hauled 0 bbls cutting/liquids to MPU G&1 for total= 0 bbls 6/14/2019 Drill 12-1/4" surface hole F/ 373', T/ 933' ( 560') avg ROP 93.3 fpr, kick off @ 400' w/ 10 deg MTF 450 GPM = 1250PSI, 40 RPM = 3-5K TQ, 5K WOB. 8.9+ ppg MW, 211 vis. ECD 9.6, max gas Ou PU 85K / SO 86K I ROT 85K.;Drill 12-1/4" surface hole F/ 933', T/ 1597'(664') avg ROP 110.7 fah. 495 GPM = 1470 PSI, 40 RPM = 3-6K TQ, 7-10K WOB. 9.0 ppg MW, 165 vis. ECD 10.2, max gas 17u PU 97K / SO 85K I ROT 91 K.;Note: at 1450' resistivity quit sending signal, perform mode switch, cycle pumps 3 times, getting a good stgnal.;Orill 12-1/4" surface hole F1 1597', T/ 2432' ( 835) avg ROP 139.2 fph. 544 GPM = 1690 PSI, 80 RPM = 4-5K TO, 6-8K WOB. 9.3 ppg MW, 156 vis. ECD 10.1, max gas 303u PU 108K I SO 84K I ROT 98K.;End of build at 1832', Held tangent t/ 216T then start drop & turn. Target 24° Inc and 97° Az @ 3200'.;Drill 12-1/4" surface hole F/ 2432', 713365' (933') avg ROP 155.5 fph. 544x GPM = 1900 PSI, 80 RPM = 7K TQ, 10K WOB. 9.2 ppg MW, 189 vis. ECD 10.4, max gas 114u PU 143K / SO 100K / ROT 119K. Base of permafrost at 2232' MD / 1862' TVD. Top of Ugnu (UG4) at 2756 MD / 2267' TVD.;Pumped high vis sweep at 2801', 10% increase and back on calculated strokes.;Last survey at 3255.28' MD / 2717.8' TVD, 25.76° Inc, 106.26° u,5.9'from plan, 5.8' high and 1.0' right.;Hauled 1800 bbls H2O from M -Pad (Nopoint Creek) for total= 2480 bbls Hauled 0 bbls heated H2O from G&I for total = 0 bbls Hauled 1814 bible cutting/liquids to MPU G&I for total= 1814 bbls 6 /1 512 01 9 Drill 12-1/4" surface hole F/ 3365', T/ 4166'(801') avg ROP 133.5 fph. Final build & turn @ 45 in 532 GPM = 2160 PSI, 80 RPM = 11 K TO, 10K WOB. 9.1 ppg MW, 132 vis. ECD 10.43, max gas 114u PU 175K / SO 104K / ROT 131 K.;Continue to turn and build targeting 85 deg Inc, 183 az @ 4.25 deg/100'.;Drill 12-1/4" surface hole F/ 4166', T/ 4736'(570) avg ROP 95 fph. 550 GPM = 2280 PSI, 80 RPM = 13-15K TO, 12-15K WOB. 9.1 ppg MW, 130 vis. ECD 10.20, max gas 549u PU 185K / SO 103K / ROT 131 K.; Pump 30 bbl hi vis sweep @ 4261', back 100 stks early w/ 15% increase. Continue to turn and build targeting 85 deg inc @ 4.25 deg/100'.;Drill 12.25"" hole F/ 4736' T/ 5194' (3880' TVD) 458'@ 92 FPH average. TD Called at 5194' by onsite Geologist. 550 GPM, 2280 PSI, 80 RPM, 12-15K TQ, 18-20K WOB. 9.2ppg MW, 65 vis, 9.9 ppg ECD. Max gas 576 units. 170K PU 195K $O / 126K ROT.;Last survey at 5141.35' MD 13876.27' TVD, 85.42° inc, 183.00° mm, 4.08' from plan, 3.66' high and 1.79' right. Top of Schrader Bluff OA -1 at 5126' MD / 3875' TVD.;Circulate hi vis sweep (9.2 ppg, 300 vis) around at 550 GPM, 80 RPM while backrearring stand slowly. Sweep came back 70 bbls early with very little increase in cuttings returns. Condition mud, reduce vis to <60 Monitor the well -Static-.;Back ream out from 5194'to 3687' at 550 GPM, 1800 PSI, 80 RPM, 14K TQ, 9.75 ppg ECD. 10 min per stand, Slowing down as hole dictates.; Hauled 1815 bbls H2O from M -Pad (Nopoint Creek) for total= 4295 bbls Hauled 0 bbls heated H2O from G&I for total = 0 bbls Hauled 1897 bible cutting/liquids to MPU G&I for total= 13711 bbls 0 losses to formation recorded. 6/16/2019 Back ream out from 3687' to 2000' pumping 550 GPM, 1480 PSI, 80 RPM, 10K TO, 9.73 ppg ECD. Note: C/O belt on drag chain #2 @ 2060', 5-10 min per stand, Slowing down as hole diclates.;Continue to BROOH f/ 2000'to 744' at HWDP pumping 500 GPM, 1170 PSI, 80 RPM, 8K TO , ECD 10.36 At 1900' seen 10.7 ECD and increase in sand at shakers, slow pulling speed cleaning up same. At 1300' hole unloading, slow pulling speed and cleanup same to HW. No losses BROOH.;Flow check well, static, POOH on elevators f/ 744' U 100', rack 6 stds HW and jar std in derrick. UD 3 NMFC.;Plug in and download MWD. UD BHA & Drain motor. Break out bit. Bit grade= 2-4-BT-A-E-1-CT-TD.;Clear and Clean Rig floor. R/U to run 9-5/8" Casinq. M/U Volant tool with Cmt swivel to TD & install bail extensions. Install XO on FOSV.;PJSM with crew and casing hand. P/U 9-5/8" shoe track to 161'. Baker Loc shoe track and torque to 20,9601VIbs. Check floats. Good. Pump through with Volant & drop "Top Hat" on top of float collar.;Two 9-5/8" x12-114" Expand-o-lizers on shoe joint and 1 each on spacer and float collar joint.;Run 9-5/8" 40# L-80 TXP BTC-SR casing as per tally, filling on the fly with Volant and breaking circ every 10 joints F/ 161' T/ 1667'. Torque to 20,960 ft/lbs w/ Volant. One centralizer per joint to #22 and every other to #38. 40-60'/min running speed. 19.3 bible Iost.;Run 9-5/8" 40# L- 80 TXP BTC-SR casing as per tally, filling on the fly with Volant and breaking circ every 10 joints F/1667' T/ 2775'. Torque to 20,960 ft/lbs w/ Volant. One centralizer every other joint to #62, One every joint to #71. Place Halliburton ESC 11 between joints #66 & 67.;Baker lock above and below ESC 11. Continue to RIH with 9 5/8 Casing F/ 2775' T/ 4280'. Filling on the fly with Volant and breaking circ every 10 joints. Torque to 20,960 ft/lbs w/ Volant. Centralizer on every other joint to #101. 28.7 bbis loss for a total of 48 bbl loss during trip.;Hauled 960 bible H2O from M-Pad (Nopoint Creek) for total= 5255 bbls Hauled 280 bbls heated H2O from G&I for total = 280 bbis Hauled 1006 bible cutting/liquids to MPU G&I for total= 4717 bbis 48 bbls mud loss to formation 6/17/2019 Continue to RI with 9 5/8 Casing F/ 4280' T/ 5092' (it #122 ) Filling on the fly with Volant and breaking circ every 10 joints. Torque to 20,960 Wile; w/ Volant. Centralizer on every other joint to #121. 58.2 bbls losses running casing.;Establish circulation, wash down last 2 jts pumping 1 bpm , 200 psi to 5172', M/U 20' pup jt, wash down to set depth @ 5187'. Verify pipe count, 21 jts left out. ( 124 jts csg and 83 centralizers ran ). P/U 295K, S/O 130K.;Stage up pumps F/ 1 X _ BPM, 200 psi ICP T/ 6 BPM, 150 psi FCP while reciprocating pipe F/ 5165'T/ 5190'. Lower YP fl 21 to 19, final MW inlout 9.4 ppg. Rotate 5 RPM wl 12K torque. Circulate 1.5 bottom up. 15.6 BPH loss rate @ 6 bpm.;PJSM w/ Doyon, Halliburton, M-1 and Peak.. Shut down, blow down top drive, close upper/lower ` IBOP, rig up cement lines. Break out volant, re-dope seals, M/U same. Pump 5 bbis water, pressure test lines to 1000 psi low & 4000 psi high. Submit 24 hr test notification to AOGCC.;Crew change, PJSM. Mix & pump 60 bbis 10.0 ppg tuned Spacer w/ 4# red dye and 5# Pol-E-Flake in 1st 10 bible at 3.5 BPM, 250 psi. Drop by-pass plug. Mix &pump 146.4 bbis 12.0 ppg Lead Cement (350 sks 2.349 yield) at 4 BPM 250 ps. Mix & numn 82 4 bible 158 oon Tail Cement (400 sks, 1.157 yield).;Drop shut off plug. Pump 20 bbis of water. Displace w/ 173 bbls 9.4 ppg mud with rig pumps at 6 BPM, 180 psi ICP, 210 psi FCP. Pump 80 bbis 9.4 ppg tuned spacer w/ cementers at 3.5 BPM, 130 psi ICP, 200 psi FCP. Continue to displace 110.86 bible mud wl rig pumps at 6 BPM, 560 psi.;200 psi lift observed before pumping the 80 bbls of 9.4 ppg tuned spacer. Slow for last 10 bible to 3 BPM, 680 FCP. Plug bumped at 1119 strokes, 22 1v strokes over calculated. CIPat 15:25. Rotated 5-10 RPM w/ 15K torque and reciprocated 20' during entire cement job.; Pressure up to 1300 psi, hold for 5 min. - good. Bleed off and check floats - good. Pump at 2 bpm pressuring to 3250 psi shifting cementer tool open. 20 bbl losses pumping and displacing cement.;Circulate thru ESC @ 2386' staging pump to 6 bpm, 310 psi, at 1450 stks dump 40 bbis of tuned spacer w/ traces of cmt, at 1850 stks dump 80 bbis tuned spacer #2, 2600 stks dump 40 bbl mud interface, 3000 stks divert clean mud to pits.;Continue to circulate through cementer 6 bpm, 250 psi, shut down pumps, remove hydraulic hoses f/ knife valve, cycle bag and flush stack and lines with black water.;Continue to circulate through ESC II at 6 bpm -130 psi while prepping for second stage. Good fluid and returns throughout. Total of of 9 BU pumped. Hold PJSM with rig crew, Peak and HES.;Line up to HES Pump 5 bbl H2O, PT Lines. Pump 60 bbl 10# spacer with red dye and .5 ppb Poly flake in the firs 10 bbis. Pump 360 bbis of 10.7# lead Perm L Cmt. (460 i SX) 2-5 BPM. Got good mud push back on time. Got good cmt back on calculated strokes.;Pump 56.2 bbl of 15.8 Tail cmt. (270 SX) Drop closing plug and s chase with 20 bbl H2O From HES. Line up to rig for displacement Pump 1500 strokes at 6 BPM. Bump plug seven strokes early at 3 bpm, 1587 slks. FCP at 400 psi.;Continue to pressure to to 1500 psi, observe shift at 980 psi. Hold 1500 psi for 5 min. Bleed pressure off and observe annulus fluid level dropping and flow back from bled line. Fluid at annular preventer. Shut bleed valve and fluid level became static. ESC II did not shift closed.;Engage pumps and pressure up to 1570 psi (80 strokes) . Hold 1570 psi while discuss options with engineers. Bleed pressure off then engage pumps at 3 bpm, pressure up to 1980 psi (35 stks), with good indication of ESC shift. Hold 1980 psi for 5 min. Bleed pressure off -hole static-.;No losses on second stage. No clobbered up issues on second stage. CIP at 01:30 with 237 bbl good lead cmt back at surface.;Flush all surface equipment with black water. Drain stack, N/D diverter line and lift 20" diverter equipment. Install casing slips as per wellhead rep. with 120K on slips. Rough cut casing.;N/D surface diverter stack. Clean and clear rig floor of casing tools and equipment. Dress cut on 9-5/8" casing (18.25' total cut) and prep to install Well head & tubing spool. 6/18/2019 N/D surface diverter stack. Clean and clear rig floor of casing tools and equipment. Dress cut on 9-5/8" casing (18.25' total cut) and prep to install Well head & tubing spool.;Install 9-5/8" slip lock head, casing spool and tubing spool. Test well head void to 500 PSI for 5 min. and 2500 PSI for 15 minute. Torque casing spool and tubing spool bolts. Install tubing spool wing valve and blind flange.:N/U and align BOP stack & kill line, Install MPD riser, install double valves on CARA valves, install both mouse holes. Sim-ops: clean mud pits, prep rig floor for testing.;Install test plug, R/U BOP test equipment, flood stack and lines with water. Perform BOP body test 250 PSI low/ 3000 PSI high - good. "' Notified AOGCC of initial BOP test on 6-17-2019 at 12:29 "'.;Test BOP equipment as ty0 x, per PTD & AOGCC requirements. AOGCC rep Adam Earl waived witness for BOP test @ 11:34, 6/18/2019. All tests performed w/ fresh water against test v �y plug. All tests performed to 250 PSI low 13000 PSI high. All tests held for 5 min. each.;#1: Top 4.5" x7" VBR on 5" test joint, choke valves 1,12,13,14, 3" kill Demco #2: Choke valves 9,11, Manual kill & Upper IBOP. #3: Choke valves 5,8,10, Lower IBOP. - Changed out Whitey valve on Choke manifold and re- tested. #4: Choke valves 4,6,7 & 5" Dart valve.;#5: Lower 2-7/8"x5" VBR on 5" test joint, 5" TIW #1 #6: Annular on 4.5" test joint, Choke valve #2 & 5" TIW #2. #7: Top 4.5"x7" VBR on 4.5" test joint & HCR choke. #8: Lower 2-7/8"x5" VBR on 4.5" test joint. #9: Top 4.5"x7" VBR on 7" test joint, manual choke & 3.5" Dart valve.;#10: Blind rams, choke valve 3 & 3.5" TIW. #11: Hyd choke A #12: Man choke B. Accumulator test: 3000 PSI system pressure, 1800 PSI after closure. 43 sec for 200 PSI recharge, 185 sec for full PSI recharge. 2040 PSI six nitrogen bottle average.;HCR Kill Valve Failed. Accumulator pump packing leaking, tighten packing - good.;Blow down kill line and change out HCR kill valve. Replacement HCR Kill valve not functioning open/close Sim Ops: Tighten pump packing on Accumulator electric pump.;UD 4.5" test joint, M/U float sub to bottom of flex collars and rack in Derrick. M/U Smith Milltooth bit to Mud Motor and lay down to pipe shed. Sim Ops: Continue troubleshooting HCR valve, blow down kill Iine.;Remove Kill line & HCR. Swap fittings to a new valve and prep to install while continuing troubleshooting HCR issue.;Hauled 210 bbis H2O from M-Pad (Nopoint Creek) for total= 5945 bbis Hauled 0 bbis heated H2O from G&I for total = 885 bbls Hauled 1484 bbis cutting/liquids to MPU G&I for total= 7175 bbis , 6/19/2019 Continue troubleshoot and repair HCR kill. Install new HCR valve and tighten hydraulic fittings on hose from accumulator.;Test Kill line OTECO Clamp & HCR Kill Valve to 250/3000 psi for 5 min each. -Good Test- #13: Kill line OTECO Clamp 914: HCR KIII;R/D test equip, blow down choke manifold, choke and kill lines. Pull test plug and install wear bushing.;Make 8-1/2" clean-out BHA. New 8-1/2" Smith XR+ bit, 7"" mud motor, float sub and 3 NM flex collars to 122'. TIH with 5"" HWDP & jars f/ 122' t/ 676'.;Single in the hole w/ 5" drill pipe from the pipe shed f/ 676' U 2358'.;W ash down f/ 2358' t/ 2374' & tag cement w/ 4K. Drill cement f/ 2374' to 2385'w/ 450 GPM, 1150 PSI, 40 RPM, 2-6K TQ. Drill ES cementer f/ 2386' tl 2389'& continue down to 2404'. Ream 2x times, then pull up & down to 2421' with no pumps. Blow down top drive. 112K PU / 80K SO / 90K ROT.;Blow down TopDrive, Cut & Slip 68' drilling line. Calibrate block height.;Continue to P/U 5" drill pipe from the pipe shed f/ 2421' t/ 4993'.;Break Circulation, wash and ream down F/ 4993' T/ 5009' Tag up w/ Sir WOB. Continue wash and ream stringers 1/5049'. 400 GPM, 1130 psi. 8k WOB 40 RPM, 12k Tq. 225K PU / 90K SO / 125K ROT.;UD single. Blow down Topdrive, R/U & Test casing to 2500 psi for 30 min. Good. Bleed down and blow down surface equipment.;Wash & Ream F/ 5049'T/ 5064'. Tag bfl adaptor on depth. Drill Baffle adaptor, Float Collar & shoe on depth. Good cmt. Drill rat hole out T/ 5194'. Drill 20 New hole F/ 5194' T/ 5214'. 40 RPM, 16K TQ, 450 GPM, 1500 PSi.;Ream through shoe & FE several times. No excess drag with pumps oft. Pull in to shoe, Work pipe 60' Circulating bottoms up. Good 9.3 in and out. at 1.5x bottoms up.;Obtain SPR. Perform kick while tripping drill. Well secure in 1 min. 40 sec. & all hands responded in 2 min. 50 sec. Simulate Well Kill , circulating through choke.-Parform FIT to 12 PPQ FMW_ 545 PSI. Good test. Held for 10 min. Bled down 48 psi. Good test. Blow down surface equipment. MW 9.30 EMW 12 545 PSI TVD 3879'.;POOH F/ 5141'T/ 4667'. Observed high drag causing surface vibration while tripping. Slow pulling speed until vibration diminished. 6/20/2019 Continue to POOH F/ 4667' T/ 739'. Monitor the well for 5 min - static -.;POOH laying down 15 its HWDP to shed. Rack back one stand HWDP w/ jars and NMDC. Bit Graded: 1-1-WT-A-E-IN-NO-BHA.;Clear and clean rig floor. Build 5 stands 5" drill pipe via mousehole and rack in Derrick. Sim Ops: Test MPD lines t/ 200 psi - 5 min, 1500 psi - 10 min.;M/U 8-1/2" production drilling BHA to 85': 8.5" NOV PDC bit, NRP sleeve, Geo -Pilot, MWD (ADR/DGR/PWD/DM/TM).; No comms during initial download. Break TM collar off and change out SIM adapter tip, clean and fix connections. Confidence test and make back up.;lnitialize tools MWD tools and download. M/U 2 float subs then TIH 3 NM flex collars, HWDP & jars to 274'.;RIH with drilling assembly, picking up singles 5" drill pipe singles f/ 274' 1:1590'. Pressure test Geo -Skid V 3000 psi and perform MWD shallow pulse test.;Single in the hole with 5" drill pipe from the pipe shed f/ 590' tt 5033'. Fill pipe every 20 stands.;PJSM. Remove trip nipple and install MPD RCD.;M/U stand of drill pipe and RIH to 5185'. Displace wellbore from 9.3 ppg spud mud to 8.8 ppg Flo -Pro NT at 8.5 BPM, 760 PSI, 60 RPM, 13K TO. Reciprocate pipe 57' from 5185' to 5128'.;Drill 8-1/2" production hole f/ 5214' tt 5694' (3897' TVD),480' drilled, 967hr AROP. 550 GPM, 1560 PSI, 120 RPM, 13K TQ, 10-14K WOB. 185K PU / 77K SO / 114K ROT. 8.95 MW, 44 vis, 10.27 ppg ECD, 170u max gas. Entered OA -2 @ 5298'.;MPD chokes full open while drilling, closed on connections with no pressure observed. Last survey @ 5535' MD / 3894' TVD, 88.84° inc, 183.93° azm, 21.39' from plan, 20.13' high & 7.25' right.;Losses today to hole= 0 bbls. Total losses for interval= 0 Hauled 210 blots H2O from M -Pad (Nopoint Creek) for total= 6225 bbls Hauled 0 bbls healed H2O from G&I for total = 885 bbls Hauled 229 bbls cuttin /Ii uids to MPU G&I for total= 7516 bbl 6/21/2019 Drill 8-1/2" production hole f/ 5694' U 6270' (3883' TVD), 576' drilled, 967hr AROP. 550 GPM, 1560 PSI, 120 RPM, 14K TO. 14K WOB. 195K PU / 70K SO I 115K ROT. 8.8 MW, 45 vis, 10.3 ppg ECD, 51 u max gas.;Drill 8-1/2" production hole f/ 6270't/ 7033' (3858' TVD), 763' drilled, 1277hr AROP. 550 GPM, 1700 PSI, 120 RPM, 15K TO, 12K WOB. 210K PU / 50K SO 1110K ROT. 8.8 MW, 44 vis, 10.5 ppg ECD, 123u max gas.;Drill 8-1/2" production hole 117033' t/ 7602' (3843' TVD), 569 drilled, 957hr AROP. 530 GPM, 1780 PSI, 120 RPM, 15K TO, 15-17K WOB. 215K PU / OK SOI 109K ROT. 8.95 MW, 46 vis, 11.02 ppg ECD, 157u max gas.;No SO wt @ 7128' Pumped hi vis sweep @ 7128', 50% increase back on calculated strokes. Pumped hi vis sweep @ 7509', 25% increase back on calculated strokes. MPD chokes full open while drilling, closed on connections w/ no pressure observed.;Crossed fault #1 (28' DTN) @ 7331'. Out of OA -1 to shale below OA -4. Built to 94° inc. Base of OA -4 @ 7487'. Drilled below OA sands f/ 156'.;Drill 8-1/2" production hole f/ 7602' U 8213' (3822' TVD), 611' drilled, 1027hr AROP. 540 GPM, 1810 PSI, 140 RPM, 15-16K TO, 9-12K WOB. 169K PU / 73K SOW / 109K ROT. 8.95 MW, 43 vis, 10.72 ppg ECD, 135u max gas. Pumped hi vis sweep @ 8094', 30% increase back on calculated strokes.;Tq increasing to 20k at 7864', added 0.5% TO-Torq lubes and had 69k SO wt. Tq dropped f/20k t/ 15k. MBT climb t/ 7.1 at 7882'. Dump and diluted 290 bbls at 8094' MPD chokes full open while drilling, closed on connections w/ 52 psi observed starting @ 7880'. Start holding 50 psi during connections.;Base of OA -3 @ 7670'. Drilled 20 concretions for a total thickness of 125' (4.3% of the lateral). Last survey @ 8105.75' MD / 3828.4' TVD, 92.67 inc, 179.22° azm, 14.07' from plan, 12.87' high & 5.68' right. Losses today (midnight) to hole= 0 blots. Total losses for interval= 0.; Hauled 200 bbis H2O from A -Pad Reserve Pit for total = 200 bbls Hauled 610 blots H2O from M -Pad (Nopoint Creek) for total= 6835 bbls Hauled 0 bbls heated H2O from G&I for total = 885 bbls Hauled 1089 bbls cutting/liquids to MPU G&I for total= 8605 bbls 6/22/2019 Drill 8-1/2" production hole F/ 8213' T1 8842' ,627' drilled, 1037hr AROP. 540 GPM, 1810 PSI, 140 RPM, 15-16K TO. 9-12K WOB. 173K PU / 60K SOW / 109K ROT, 8.95 MW, 43 vis, 11.04 ppg ECD, 135u max gas. Pumped hi vis sweep @ 8567', 25% increase back 100 strokes Iate.;Drill 8-1/2" production hole F/ 8842'T/ 9606', 764' drilled, 1277hr AROP. 550 GPM, 2070 PSI, 140 RPM, 17K TO, 8-9K WOB. 190K PU / 40K SOW / 105K ROT. 8.9 MW, 44 vis, 11.33 ppg ECD, 104u max gas. Pumped hi vis sweep @ 9128', 30% increase back on calculated strokes.;Drill 8-1/2" production hole F/ 9606' T/ 10175', 569' drilled, 95/hr AROP. 535 GPM, 1930 PSI, 145 RPM, 19-20K TQ, 11-12K WOB, 200K PU / 40k SO / 105K ROT. 9.0 MW, 47 vis, 11.49 ppg ECD, 96u max gas. Begin adding background LCM due to loss rate 6-30bph- SC 10, 20, 40, 750 @ 5ppb total.;Pumped hi vis sweep @ 9796', 20% increase back on calculated strokes. Perform 290 bbl whole mud dilution @ 8114' due U high MBTs & ECDs MPD chokes full open while drilling, holding 130 psi during connections. Drilled above OA -1 U 9904' U 10043'. Formation dip dropped f/ 94.7° t/ 92.2°.;Drill 8-1/2" production hole F/ 10175' T/ 10859', (3685' TVD) 684' drilled, 1147hr AROP. 517 GPM, 1970 PSI, 140 RPM, 18K TO. 5-10K WOB. 200K PU / 40K SO / 104K ROT. 9.0 MW, 43 vis, 11.53 ppg ECD, 104u max gas. Pumped hi vis sweep @ 10480', 40% increase back on calculated strokes.;Start taking 45' surveys @ 10252' due to AC CF <2 (M-01).Drilled 26 concretions for a total of 152' (2.8% of the lateral) Last svy @ 10771' MD / 3683.68' ND, 89.33 inc, 184.95° azm, 28.77' from plan, 28.77 high & 0.51' left Losses today (midnight) = 116 blots. Total losses for interval=116 bbls.;Hauled 400 blots H2O from A -Pad Reserve Pk for total = 600 bbls Hauled 375 bbls H2O from M -Pad (Nopoint Creek) for total= 7210 bbls Hauled 0 bbls heated H2O from G&I for total = 885 bbls Hauled 1322 bbls cutting/liquids to MPU G&I for total= 9927 bbls 6/23/2019 Drill 8-112" production hole F/ 10859'T/ 11410' (3657' TVD), 551' drilled, 92/hr AROP. 530 GPM, 2110 PSI, 140 RPM, 17K TQ, 8-10K WOB. 185K PU / Ok SO/ 101K ROT. 8.95 MW, 43 vis, 11.44 ppg ECD, 163u max gas.;Pumped hi vis sweep @ 10940', 50% increase back on calculated strokes. Loss rate continues at 10-20 BPH. MPD chokes full open while drilling, holding 130 psi during connections.; Drill 8-1/2" production hole F/ 11410' T/ 11891'(3631' TVD), 481' drilled, 80/hr AROP. 520 GPM, 2080 PSI, 145 RPM, 18K TQ, 8-91K WOB. 190K PU / Ok SO / 101K ROT. 8.9 MW, 42 vis, 11.34 ppg ECD, 170u max gas.;Pumped hi vis sweep @ 11504', 30% increase back on calculated strokes. Loss rate continues at 10-20 BPH. MPD chokes full open while drilling, holding 130 psi during connections.; Drill 8-1/2" production hole F/ 11891'T/ 12457' (3622' TVD), 566' drilled,94/hr AROP. 530 GPM, 2090 PSI, 140 RPM, 20K TO, 13 15K WOB. 185K PU / Ok SO / 101K ROT. 9.0 MW, 58 vis, 11.50 ppg ECD, 149u max gas. Increase Lo-Torq to 1 %.;MPD chokes full open while drilling, holding 130 psi during connections. Pumped hi vis sweep @ 12075', 50% increase back on calculated strokes. Crossed fault 92 at 12221' . 82 throw DTS. Drop inclination to 85", to get back into the OA sand package. Loss rate continues at 10-20 BPH.;Drill 8-1/2" production hole F/ 12457' T/ 13029' (3671' TVD), 572' drilled, 95/hr AROP. 450 GPM, 1770 PSI, 140 RPM, 18K TQ, 8-18K WOB. 185K PU / Ok SO / 101K ROT. 9.0 MW, 42 vis, 11.50 ppg ECD, 177u max gas. Adjust flow and ROP as ECD's dictate. MPD full open while ddg, holding 130 psi on Conn.; Pumped hi vis sweep @ 12552', 20%, 200 strokes late. Pumped hi vis sweep @ 12904', (still in hole @ 06:00) Drilled 44 concretions for a total of 256' (3.3% of the lateral) Losses today (midnight) = 263 bels. Total losses for interval=379 bbl.;Maintaining background LCM - SC 10, 20, 40, 750 @ 5ppb total. Last svy @ 12959.79' MD / 3667' TVD, 87.24 Inc, 182.90° azm, 46.58' from plan, 46.53' low & 2.OT Right.;Hauled 740 bbls H2O from M -Pad (Nopoint Creek) for total= 7950 bbls Hauled 0 bbls heated H2O from G&I for total = 885 bbls Hauled 1272 bbls cutting/liquids to MPU G&I for total= 11199 bbls Hauled 200 bels Pit Water from A -Pad for total = 800 bbls 6/24/2019 Drill 8-112" production hole F/ 13029'. T/ 13188'. Attempting to build angle . Hard building hitting concretions & getting housing role. Slow GPM to 385. Built to 90 deg. Went out the btm of the 01 Decide to POOH & side track at 12179.;Take Survey and Back rem working up GPM to 550 as ECDs came down. ECD after back reaming out at 11.2. at 550 gpm. Started at 11.5 at 450 GPM.;Start troughing at 12170' T/ 12190'. Troughed 3x at 60 FPH & started at 12190' at 5 FPH down U 12195'. Pulled back and time drilled F/ 12190'-12218'. Got good separation and start increasing ROP to 20 FPH. GPM at 550 & ECDs down to 11.08. 120 RPM. Drilled through the fault 92 @ 12218' DTS throw.; Drill 8-112" production hole F/ 12218' T/ 12777' (3656' TVD), 559' drilled, 93/hr AROP. 475 GPM, 1970 PSI, 140 RPM, 17K TQ, 12-14K WOB. 180K PU / Ok SO /105K ROT. 8.9 MW, 48 vis, 11.73 ppg ECD, 98u max gas. MPD full open while drlg, holding 150 psi on Conn.;Drill 8-1/2" production hole F/ 1277T T/ 13109' (3647' TVD), 332' drilled, 55'/hr AROP. 520 GPM, 2090 PSI, 125 RPM, 21 K TQ, 15-18K WOB. 201 K PU / Ok SO / 101 K ROT. 8.8 MW, 43 vis, 11.30 ppg ECD, 192u max gas. Top of OA -1 @ 12780'. Out of zone total of 562' from fault.;Pumped tandem to vis/hi vis sweep @ 12841', 80% increase in cuttings Pumped tandem to vis/hi vis sweep @ 12933', >10% increase in cuttings, followed sweeps with 290 bbl full mud dump & dilution. Drilled 48 concretions for a total of 289' (3.7% of the lateral).; Losses today (midnight) = 209 bbls. Total losses for interva1=588 bbl Maintaining background LCM - SC 10, 20, 40, 750 @ 5ppb total. Last svy @ 12958.76' MD / 3655.69' TVD, 91.68 Inc, 182.24° azm, 46.3' from plan, 35low & 30.3' Right.;Hauled 410 bbls H2O from M -Pad (Nopoint Creek) for total= 8360 bbls Hauled 0 bbls heated H2O from G&I for total = 885 bbls Hauled 907 bels cutting/liquids to MPU G&I for total= 12106 bbls Hauled 200 bels Pit Water from A -Pad for total = 1000 bbls 6/25/2019 Drill 8-1/2" production hole F/ 13109' T/ 13559' (3637' TVD), 450' drilled, 757hr AROP. 523 GPM, 2100 PSI, 150 RPM, 20K TO, 5-10K WOB. 190K PU / Ok SO / 107K ROT. 9 ppg MW, 45 vis, 11.41 ppg ECD, 111 u max gas. MPD full open while drag, holding 170 psi on Conn.;Undulate from OA -1 to OA -3, OA -2 top @ 13,105', OA -3 top @ 13,300', Drilling in the OA -3. 7 BPH loss average.;Drill 8-1/2" production hole F/ 13559'T/ 13926' (3626' TVD), 36-P drilled, 91.757hr AROP. 518 GPM, 2110 PSI, 135 RPM, 20K TQ, 11-12K WOB. 185K PU / Ok SO 1 102K ROT. 8.9 ppg MW, 41 vis, 11.01 ppg ECD, 123u max gas. MPD full open while drlg, holding 170 psi on Conn.;Pump tandem sweep @ 13659, sweep back 500 sties late w/ 20% increase mostly sand. Drilling in the OA -3. Formation dip is 93-93.5 deg. Encountered fault #3 @ 13850' w/ 41' DTS, placing wellbore in shale above OA sands. 14 BPH loss average.;Consult with town, decision made to perform a sidetrack. BROOH f/ 13926't/ 13810', 520 GPM, 2210 PSI, 120 PSI, 19K TO. 7 BPH loss average.;Attempt to perform an openhole sidetrack - unsuccessful. Trough f/ 13810' to 13830', 550 GPM, 2360 PSI, 120.150 RPM, 19-20K TO. 100 fph list pass, ABI dropped from 93.57° to 92.96'. 75 fph 2nd pass, 20 fph 3rd pass, 5 fph 4th pass with no drop in ABI. 8 BPH loss average.;Rack back stand & PIU single of drill pipe. Trough f/ 13760' to 13780', 550 GPM, 2280 PSI, 120-135 RPM, 18-19K TO. 100 fph 1st pass, ABI dropped from 92.87° to 92.169. 30 fph 2nd pass, ABI dropped to 91.90°.;Drill f/ 13780' U 13785' @ 30 fph. Slow to 15 fph to 13800' due to hard formation. WOB increased from 5K to 14K. Drill f/ 13800 if 13820' at 30 fph increasing to 100 fph. ABI was 90.49° vs, original wellbore of 93.57°.;In OA3 to 13852', faulted into shale above OA and re-entered 01 at 14035', 183' out of zone. 10 BPH loss average.; P/U above sidetrack point of 13760'. Work past sidetrack point with 50 RPM with no issues. UD single of drill pipe and work through sidetrack point again with no issues.;Drill 8-1/2" production hole F/ 13820' T/ 14360' (3616 TVD), 54U drilled, 907hr AROP. 542 GPM, 2400 PSI, 120 RPM, 19K TO, 12- 18K WOB. 208K PU / Ok SO / 100K ROT. 8.85 ppg MW, 39 vis, 11.41 ppg ECD, 128u max gas. MPD full open while drlg, holding 150 psi on connections.;Crossed fault #4 at 14278' with 9' DTN throw. placing wellbore at base of OA -1. Will target 93.5' inclination to move up in section. 12 BPH loss average. Losses today (midnight) = 183.5 bbls. Total losses for interval=771.5 bbl.;Maintaining background LCM - SC 10, 20, 40, 750 @ 5ppb total. Last svy @ 14291.19' MD / 3626.56" TVD, 90.99° ins, 185.38° um, 26.54' from plan, 25.56' low & 7.14' Right Drilled 49 concretions for a total thickness of 309' (3.4% of the lateral).;Hauled 695 bbls H2O from M -Pad (Nopoint Creek) for total= 9055 bbls Hauled 0 bels heated H2O from G&I for total = 885 bels Hauled 1520 bbls cutting/liquids to MPU G&I for total= 13626 bbls Hauled 500 bbls Pit Water from A -Pad for total = 1500 bbls 6/26/2019 Drill 8-1/2" production hole F/ 14360'T/ 14830' (3624' TVD). 470' drilled, 727hr AROP. 519 GPM, 2320 PSI, 120 RPM, 20K TO, 8-10K WOB. 211 K PU / Ok SO / 101 K ROT. 8.9 ppg MW, 43 vis, 11.52 ppg ECD, 109u max gas. MPD full open while drlg, holding 150 psi on connections.;Tandem sweep pumped @ 14286' back 500 sties late w/ 10% increase. Drilling in OAi, encountered fault #5 @ 14449'w/ 13' DTN throw moving the wellbore to OA -3. TD in OA -3. Obtain final survey : 14830 MD 87.42 Inc 180.73 Az 3622.83 TVD 54.88' distance to plan (drilled past plan).26.5' low , 2.47' right;49 concretions were drilled in the lateral, for a total thickness of 309' (3.2%). Rig off high line power at 11:00 due to high pressure in transformer. Analyzing transformer oil, will stay on generators until results are known.;Obtain SPRs, Pump tandem low vis / high vis sweep. 500 GPM, 2210 PSI, 120 RPM, 20K TO. reciprocate pipe, slow pump to 400 gpm on down stroke. Sweeps back 800 strokes late w/ no increase. Circulate a total of 4x bottoms up, racking back a stand every BU to 14457'.; Loss rate slowed H 15 bph to none. PJSM for displacing to brine. Wash back to bottom prior to pumping SAPP pill treatment, 440 GPM, 1700 PSI, 60 RPM, 17K TQ.;Pump SAPP pill treatment as per M-1 procedure, 4.5 BPM, 550 PSI, 100 RPM, 18-22K TO. 30 bbl hi -vis spacer, 50 bbls seawater, 30 bbls SAPP pill #1, 50 bbls seawater, 30 bels SAPP pill #2, 50 bbls seawater, 30 bels SAPP pill #3, 30 bbls hi -vis spacer then 210 bbls seawater.;Displace well to 8.5 ppg 4% lube brine, 4.5 - 7.5 bpm, 550 - 840 PSI, 100 RPM, 13-22K TO. Final parameters: 7.5 bpm, 840 PSI, 100 RPM, 13K TQ. PU/SO/ROT in mud 21 lk/none/102k. PU/SO/ROT in brine 185k/none/110k.;Shut down pumps with MPD chokes open. bleed MPD pressure to 18 PSI, shut choke and pressure built to 93 PSI in 11 min. 93 PSI @ 3894' TVD with 8.5 ppg mud = 9.0 ppg EMW. Service top drive while cleaning pit #3. Fill pit #3 & #4 with lubricated viscosifed brine. Obtain slow pump rates.;BROOH f1 14830't/ 11863'. Begin w/ 500 GPM, 1420 PSI, 120 RPM, 19K TO, 10.4 ECD at 10 min/std. Shakers began to unload @ 14245. Slow flow rate to 460 GPM, 1300 PSI & pulling speed to 15 min/std. Shakers running over, install 200 mesh screens on back two panels.;Retum to 500 GPM and 10 mini at 14066'. Increase to 5 min/std at 13874'. Chokes full open w/ 50 PSI line pressure & shut in 195 PSI on connections (9.5 ppg EMW). 15.4 bbls lost on trip for 30 stands out, 2.6 BPH loss average.;Hauled 580 bbls H2O from M -Pad (Nopoint Creek) for total= 9635 bels Hauled 0 bbis heated H2O from G&I for total = 885 bbls Hauled 2269 bbis cutting/liquids to MPU G&I for total= 15895 bbls Hauled 200 bbls Pit Water from A -Pad for total = 1700 bbls.;Losses today (midnight) = 171.5 bels. Total losses for interval = 943. 6/2712019 BROOH f/ 11863't/ 9032' pumping 550 GPM, 1240-1540 PSI, 120 RPM, 7-19K TO, 10.16 ECD at 7-10 min/std. Chokes full open w/ 50160 PSI line pressure & shut in 180 PSI on connections (9.5 ppg EMW). Loss rate 4.5 bph.;BROOH f/ 9032't/ 5124' pumping 550 GPM, 1240 PSI, 120 RPM, 7K TQ, 10.16 ECD at 5 min/std. Chokes full open w/ 50/60 PSI line pressure & shut in 180 PSI on connections (9.5 ppg EMM. 34.5 bbls total lost while BROOH.;Pump 30 bbl high viscosity sweep at 500 GPM, 1120 PSI, 100 RPM, 5K torque, reciprocating f/ 5124' U 5033'. Sweep back on strokes with 15% increase observed. Continue to circulate 2.5 bottoms up with minimal cuttings observed at shakers. Lost 5 bbls while circulating.;Open MPD choke and bled off pressure to 18 PSI, close choke and pressure built to 98 PSI in 10 min. Open MPD choke and bled off pressure again to 18 PSI, close choke and pressure built to 91 PSI in 10 min. Weight up brine in pits to 9.1 ppg.;Weight up to 9.1 ppg from 5124'. 6 BPM, 305 PSI, 100 RPM, 8K TO. Circulate surface to surface + pit volume, 5268 strokes. Good 9.1 ppg brine in and out.;Shut down pumping with open choke. Flow decreased to zero in 5 min. Shut choke, pressure built to 39 PSI in 5 min. Open choke, no flow. Open 2" bleed valve and monitor for flow. Flow diminished from 0.78 BPH to static in 30 min. Sim-ops: Service top drive.;PJSM w/ Beyond and Doyon. Remove RCD bearing and install trip nipple. Check for leaks - good. Monitor well - static.;lnstall FOSV. Slip and out 105' of drilling line. Service crown. 0.5 BPH Iosses.;Hauled 500 bbls H2O from M-Pad (Nopoint Creek) for total= 10135 bbls Hauled 0 bbls heated H2O from G&I for total = 885 bbls Hauled 834 bbls cutting/liquids to MPU G&I for total= 16729 bbls Hauled 0 bbls Pit Water from A-Pad for total = 1700 bbls;Losses today (midnight) = 83 bbls. Total losses for interval = 1026 bbls. 6/28/2019 TOOH f/ 5124' to 4750' UD 5" DP, pump dry job, continue UD DP to 274' at HWDP, ( 153 jts). 7 bbl losses on TOOH IF/ shoe.;Monitor well for 15 min, static. UD 2 joints HWDP, jars, 3 NM drill collars, 2 float subs to 83'. Read MWD tools, UD remaining BHA. Bit grade= 1-2-WT-S-X-1-NO-TD. Note: ILS had wear on upper part of blades f/ back reaming.;Monitor well, .1 /2 bph static loss rate. Clear and clean rig floor. R/U to UD DP.;UD 8 stands 124 joints of 5" drill pipe from the derrick.;Shut down power on the rig. Change out breaker on SCR #3. Re-energize the rig and verify SCR #3 breaker functioning properly. Loss rate 2 BPH.;UD 44 stands 1132 joints of 5" drill pipe from the derrick. Loss rate 2.5 BPH.;Clear pipe shed and load 5" HWDP in the pipe shed. Loss rate 2 BPH.;P/U 60 joints of 5" HWDP in the mousehole and rack back 20 stands in the derrick. Loss rate 2 BPH.;Mobilize & R/U 6-5/8" casing equipment. M/U 6-5/8" H563 pin x 4-112" IF box XO, 5" drill pipe joint, 4-1/2" FOSV, 4-1/2" IF pin x 6-5/8" H563 box XO and 6-518" H563 pup joint. Conduct PJSM for running 6-5/8" liner. Loss rate 2.5 BPH.; Hauled 25 bbls H2O from M-Pad (Nopoint Creek) for total= 10160 bbls Hauled 0 bbls heated H2O from G&I for total = 885 bbls Hauled 356 bbls cutting/liquids to MPU G&I for total= 17085 bbls Hauled 0 bbls Pit Water from A-Pad for total = 1700 bbls;Daily losses (to midnight) = 33 bbls. Cumulative losses = 1059 bbls. 6/29/2019 P/U 41/2"shoe joint w/ XO, P/U and RIH w/ 6-518", 20#, L-80, Hydril 563, Slotted liner as per tally 1:14719. Install Centralizer every joint. M/U Tq = 7100 ft/lbs. Loss rate running liner 2.5 bph.;P/U and RIH w/ 6-5/8", 209, L-80, Hydril 563, Slotted liner as per tally f/ 4710' to 7172'w/ 10k set down, P/U and work through w/ no issues, continue running liner to 9786'. PU/SO before exiting shoe @ 5155'= 120k/90k. PU/SO 150k / 70k.;Verify pipe count, 215 jts slotted liner, 27 jts solid liner and 240 centralizers ran, (2 centralizers over stop rings on shoe jt). Loss rate running liner 2.5 bph, 31 bbls total. 31 bbl losses running Iiner.;M/U Baker 7"x9-5/8" liner top packer f/ 9786't/ 9826' as per Baker rep. RIH w/ 2 joints of 5" HWDP to 9888'. Circulate 10 bbls at 4 BPM, 220 PSI to verify clear flow path. Obtain parameters: 20 RPM, 10K with pipe moving. 155K PU / 70K SO.;Run 6-518" slotted liner on 5" HWDP f/ the pipe shed f/ 9826' ri 12913'.Assembly took 33K weight @ 10508' (OA-2), work past wl rotation. TIH w/ 5" HWDP f/ the derrick f/ 12913'to 14768'. Tag bottom w/ a stand of drill pipe @ 14830'. 22 bbls lost running liner on HWDP. 53 bbls total for liner run.;Pump drill pipe volume at 4 BPM, 530 PSI. Drop 29/32" activation ball. Pump down at 4 BPM, 530 PSI. Slow to 1.5 BPM, 240 PSI for last 10 bbls. Ball on seat at 350 strokes. Pressure up and set packer at 2530 PSI. Slack off from 273K to 100K. Pressure up to 2700 to 3500 PSI in 200 PSI increments.;Pressure up & neutralize pusher tool @ 4100 PSI w/ test pump. Pressure up to 5000 PSI, shear ball seat or rupture disk. Break over w/ 233K PU. Close upper pipe rams & lest annulus to 7"x9-5/8" packer to 1600 PSI for 10 min. - good test. P/U 14776' & verify release. TOL @ 5017'.;Rig down test equipment. Blow down top drive & choke lines. Clear rig floor of casing equipment. Mobilize 5" thread protectors to the rig floor. 2 BPH loss rate.;Rack back stand of drill pipe and POOH laying down 5" HWDP H 4983' U 2233'. 2.8 BPH loss rate.;Hauled 50 bbls H2O from M-Pad (Nopoint Creek) for total= 10210 bbls Hauled 0 bbls heated H2O from G&I for total = 885 bbls Hauled 61 bbls cutting/liquids to MPU G&I for total= 17146 bbls Hauled 0 bbls Pit Water from A-Pad for total = 1700 bbls;Daily losses (midnight)= 83 bbls. Cumulative losses = 1142. HHilcorp Energy Company Composite Report Well Name: MP M-20 Field: Milne Point Unit County/State: , Alaska (LAT/LONG): ovation (RKB): API #: 50-029-23636-00-00 Spud Date: 6/13/2019 Job Name: 1912739C MPU M-20 Completion Contractor Doyon 14 AFE #: APE $: Activity Date Ops Summary 6/30/2019 TOOH LID 5" H W DP f/ 2233' to surface, L/D and inspect running tool. 20.4 bbl losses on TOOH.,Break down liner safety joint. Drain stack and pull wear bushing. Perform dummy run with 7" hanger on landing joint with well head rep. Re -install wear bushing. Remove split master bushing and install MB.,M/U 3- 1/2" perforated orange peeled joint with 8.31" no-go and XO to 15.84'. TIH with 52 stds 5" stands DP to 4956, M/U TD, pump 2 bpm, 170 psi, tag top of liner with no-go on depth at 5017' putting flush tool @ 5031' 4 bbl losses on TIH.,Flush seal bore assy 7 bpm, 300 psi PIU slowly to above TL @ 5014', pump 30 bbl hi vis sweep, 450 gem, 450 psi, 30 rpm, 3k tq. Sweep back on time 100% increase mostly sand. Pump 30 bbl spacer, Displace w/ clean 9.1 ppg brine, 430 bbls total. 20 bbis losses while circulating.,Shut down pumps, monitor well it 30 min, slight flow and not slowing.,Weight up brine in pit #4 f/ 9.1 to 9.2 ppg, pump 8 bpm, 190 psi until good 9.2 intout. Perform 15 min. flow check - static. Obtain new slow pump rates. Blow down top drive.,POOH from 5014' laying down 159 joints of 5" drill pipe, no-go and 3-1/2" wash tool. 6 blas lost on TOOH (1.3 BPH)., LID no-go & 3-1/2" wash tool. Clear ng floor. Mobilize casing equipment to the rig floor. R/U to run 7" liner tie -back. WU XO to FOSV. 1.5 BPH Iosses.,P/U Baker Bullet Seal assembly with 8.24" locator sub to 15'. Run 7" 26# L-80 TXP BTC -SR liner from 15' to 3503'. M/U to 14,750 ft/lbs torque w/ Doyon double stack tongs. Kick drill: well secure 1 min. 40 sec., total response time 3 min. 30 sec. 4.4 bbis lost while running liner., Hauled 25 blas H2O from M -Pad (Nopoint Creek) for total= 10235 bbas Hauled 0 bbis heated H2O from G&I for total = 885 bbas Hauled 796 bbis cutting/liquids to MPU G&1 for total= 17942 bbis Hauled 0 bbls Pit Water from A -Pad for total = 1700 bbls,49 bbis daily losses (midnight). 1191 bbis cumulative losses for interval. 7/1/2019 Run T' 26# L-80 TXP BTC -SR liner from 3503' to 5016' at jt # 125' just at TOL. M/U to 14,750 ft/fibs torque w/ Doyon double stack tongs. WU jt 126, ease into TOL tagging no go on depth @ 5017' putting mule shoe @ 5031' set down 5k, close bag, pressure to 250 psi to verify seals landed, good. Bleed off and open bag. Losses running liner 7 bbis. PU/SO 150K / 112K.,Space out liner. UD joints #126, 125 and 124. M/U 14.88' pup joint then joint #131. M/U 7" hanger and landing joint. Land liner on hanger at 5029.06' (1.93' off no-go), 150 PU / 112 SO. R/U FOSV, circ. sub & 5' pup joint. Close annular & pressure up to 250 PSI. P/U, observe pressure bleed off through circulation ports., PJSM with Doyon, M-1 and Peak. Reverse circulate 71 bola corrosion inhibited 9.2 ppg brine @ 4 BPM, 330 PSI, Pump through injection line to the OA taking returns out of the 7" liner, Line up and reverse circ 70.5 bbis diesel from vac truck 4 bpm, 340 psi freeze protecting 9 5/8" x 7" annulus to 2500', Land hanger w/ 70k on Hanger.,Crew change. Bleed down to cellar and verify seals engaged. Good. Back side dead. Open annular & drain stack. R/D landing joint.. M/U Pack off running tool on jt of 5" DP. RIH & set pack off. RILD as per Wellhead rep. UD running tool. Test Void to 500/5000 psi , 5 min./15 min - good.,R/U test pump, with diesel Test 7" X 9-5/8" annulus to 1000 psi for 30 charted min. Good. Bleed of pressure, R/D test equipment. BD kill and injection lines. Note: 8 bbis to fill hole.,Clear rig floor. R/U to run 4 1/2" jet pump completion, 4.5" handling equipment, Doyon double stack power tongs, tech wire spool and sheave, cannon clamps. M/U XO sub on FOSV. PJSM w/ Doyon and Schlumberger. 2.25 BPH Iosses.,M/U 4-1/2" WLEG w/ pump joint, 6 joints of 4-1/2" 12.6# L-80 TXP tubing, XN assy., 7"x4-1/2" Bluepack packer assy., X nipple assy., SGM & sliding sleeve assembly & 1 joint of 4-1/2" tubing to 394'. Torque connections to 6170 fl/lbs with Doyon double stack tongs.,M/U Tec Wire to SGM gauge assembly. Pressure test gauge cable head to splitter block to 5000 PSI for 5 min. - good test., Run 4-1/2" 12.6# L-80 TXP BTC -SR tubing f/ 394' t/ 5026'. Torque connections to 61701UIbs with Doyon double stack tongs. 115 full cannon clamps and 5 half clamps ran. 8.9 bbis total losses while running tubing.,M/U 4-1/2" x 11" FMC tubing hanger and 5" landing joint. Terminate and feed Tec wire through hanger. While landing hanger, assembly took weight at 5029'. Verify tallies - good. Work W LEG through liner tie -back w/ 15-20K f/ 5029 U 5030'. Land 4-1/2" tubing on tubing hanger with BPV installed at 5060' & RILS. 94K PU / 75K SO, 35K on hanger.,Clear rig floor of tubing equipment. Break down XOs on FOSV & landing joint. UD landing joint.,Begin nipple down operations. Remove trip nipple and MPD drip pan. 7/2/2019 N/D BOPE, prep wellhead, terminate tech wire thru adaptor flange, N/U tree. Well head rep test hanger void to 250 psi low for 5 min, 5000 psi high for 10 min. Install dart in BPV, test tree with diesel to 250 and 5000 psi. 5 min ea. charted. Final Readings upper gauge= 1772 psi, 76.35 deg. Lower gauge= 1775 psi, 76.48 deg.,Well head rep Pull BPV, secure tree. R/U to reverse circulate, test surface lines, pump 85 bbls diesel down I/A 2 bpm, 150 psi, take returns out tbg to cellar, clear cellar with vac truck. FCP 570 psi.,R/U and Let U-tube for 1.5 hrs, freeze protecting 7" x 4 1/2" annulus and tbg to 2500', secure tree.,Set 1 7/8" ball and rod in tree, M/U lubricator, open master valve, dropping ball and rod. Close master valve. R/U test pump on tbg, with diesel pressure up on tog to 3600 psi setting packer as per SLB rep, chart for 30 min., Bleed tubing down to 2200 PSI. Pressure test 4-1/2" x 7" IA to 3600 PSI for 30 min. on chart. Tubing pressure climbed to 2800 PSI due to compression. Bleed off IA pressure then tubing pressure.,R/D circulating and test equipment on tree. Secure tree: close SSV, master and swab valves. Final pressures: OA = 0 PSI, IA = 0 PSI, tubing = 200 PS I.,Clear cellar, move rock washer and fuel trailer. Pick up all landings. PJSM for rig move. Skid rig floor into moving position.,Jack up rig and remove shims. Move rig off M-20. Rig released from M-04 at OO:OO.,Reports swap to M- 04 WSW GP at 00:00. R&P loader remove ASR matting boards from M-04. Sim -ops: Doyon loader remove matting boards from M-20.\ Doyon rig crew picking up trash on the pad.,Doyon loader spotting rig matting boards on M-04. Sim -ops: Doyon rig crew picking up trash on the pad.,Move rig east down the pad from M-20 and spot rig over M-04. Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-20 500292363600 Sperry Drilling Definitive Survey Report 27 June, 2019 HALLIBURTON SPorry Drilling Halliburton Definitive Survey Report Company: Hilwrp Alaska, LLC Local Co-ordinate Reference: Well MPU M-20 Project: Milne Point TVD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Site: M Pt Moose Pad MD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Well: MPU M-20 North Reference: True Wellbore: MPU M-20 Survey Calculation Method: Minimum Curvature Design: MPU M-20 Database: NORTH US+CANADA Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M-20 Magnetics Well Position +N/ -S 0.00 usft Northing: 6,027,889.58 usft Latitude: 70' 29' 14.001 N V) +E/ -W 0.00 usft Easting: 533,843.66 usft Longitude: 149° 43'24.168 W Position Uncertainty 80.96 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 24.90 usft Wellbore MPU M-20 Magnetics Model Name Sample Date Declination Dip Angle Field Strength V) (') (nn BGGM2018 6/26/2019 16.58 80.96 57,422.11779948 Design MPU M-20 Audit Notes: Version: 1.0 Phase: ACTUAL Te On Depth: 13,720.96 Vertical Section: Depth From (TVD) +NIS +E/ -W Direction (usft) (usft) (usft) V) 34.23 0.00 0.00 176.38 Survey Program Date 6/26/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 226.36 5,141.35 MPU M-20 MWD+IFR2+MS+Sag (1) IMP 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sag 06/10/2019 5,207.40 12,102.42 MPU M-20 MWD+IFR2+MS+Sag(2)IMP 2_MWD+IFR2+MS+Sag A013Mb: IIFRdec&multi-station analysis+sag 06/17/2019 12,170.00 13,720.96 M-20PB2 MWD+IFR2+MS+sag (MPU M 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec&multi-station analysis +sag 06/25/2019 13,760.00 14,761.28 M-20 MWD+IFR2+MS+sag(MPU M-20) 2_MWD+IFR2+MS+Sag A013Mb:IIFRdec&multi-station analysis +sag 06/26/2019 Survey Map Map Vertical MD Ili Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 34.23 0.000 0.00 3423 -24.90 0.00 0.00 6,027,889.58 533,843.66 0.00 0.00 UNDEFINED 226.86 0.120 173.41 226.86 167.73 -0.20 0.02 6,027,889.38 533,843.68 0.06 0.20 2_MWD+IFR2+MS+Sag(1) 318.35 0.040 180.11 318.35 259.22 -0.33 0.03 6,027,889.25 533,843.70 0.09 0.33 2_MWD+IFR2+MS+Sag(1) 409.37 0.940 27.40 409.37 350.24 0.30 0.38 6,027,889.89 533,844.04 1.07 4.28 2_MWD+IFR2+MS+Sag(1) 504.54 2.670 25.58 504.48 445.35 3.00 1.69 6,027,892.58 533,845.34 1.82 -2.88 2_MWD+IFR2+MS+Sag(1) 595.67 5.430 13.51 595.38 536.25 9.10 3.62 6,027,898.70 533,847.24 3.15 48.86 2_MWD+IFR2+MS+Sag(1) 687.92 8.220 16.74 686.97 627.84 19.67 6.54 6,027,909.27 533,850.11 3.05 -19.21 2_MWD+IFR2+MS+Sag(1) 794.20 11.700 21.45 781.78 722.65 35.35 12.09 6.027,924.98 533,855.59 3.71 -34.51 2_MWD+IFR2+MS+Sag(1) 879.05 15.670 24.68 873.92 814.79 55.95 20.96 6,027,945.62 533,864.36 4.26 -54.51 2_MWD+IFR2+MS+Sag(1) 974.02 20.120 25.92 964.28 905.15 82.31 33.46 6,027,972.03 533,876.74 4.70 -80.03 2_MWD+IFR2+MS+Sag(1) 1,069.13 25.640 26.48 1,051.87 992.74 115.46 49.80 6,028,005.26 533,892.93 5.81 -112.09 2_MWD+IFR2+MS+Sag(1) 6/27/2019 3:15:29PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-20 Project: Milne Point TVD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Site: M Pt Moose Pad MD Reference: MPU M-20 Actual IRKS @ 59.13usft (Doyon 14) Well: MPU M-20 North Reference: True Wellbore: MPU M-20 Survey Calculation Method: Minimum Curvature Design: MPU M-20 Database: NORTH US+CANADA Survey 5/2712019 3:15:29PM Page 3 COMPASS 5000.15 Build 91 Map Map Vertical MD Inc Azl TVD TVDSS +N7S +E/ -W Northing Easting DLS Section (usft) (1) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 1,164.14 31.600 23.70 1,135.24 1,076.11 156.69 68.99 6,028,046.57 533,911.93 6.43 -152.03 2_MWD+IFR2+MS+Sag(1) 1,257.57 37.820 20.61 1,212.01 1,152.88 205.97 88.93 6,028,095.93 533,931.65 6.92 -199.95 2_MWD+IFR2+MS+Sag(1) 1,354.18 42.980 19.04 1,285.56 1,226.43 264.87 110.12 6,028,154.92 533,952.56 5.44 -257.39 2_MWD+IFR2+MS+Sag(1) 1,448.95 43.200 18.81 1,354.77 1,29564 326.11 131.12 6.028.216,25 533,973.28 0.29 ]IT18 2_MWD+IFR2+MS+Sag(1) 1,543.96 45.190 20.62 1,422.89 1.363.76 388.44 153.47 6,028,278.68 533,995.35 2.48 -377.98 2_MWD+IFR2+MS+Sag(1) 1,637.81 48.580 25.11 1,487.04 1,427.91 451.50 180.14 6,028,341.85 534,021.73 5.02 439.23 2_MW13+1FR2+MS+Sag(1) 1,733.67 51.690 26.73 1,548.48 1,489.35 517.65 212.32 6,028,408.14 534,053.60 3.49 -503.22 2_MWD+IFR2+MS+Sag(1) 1,828.90 54.780 27.24 1,605.47 1,546.34 585.62 246.94 6,028,476.26 534,087.91 3.27 -568.87 2_MWD+IFR2+MS+Sag(1) 1,922.92 52.150 27.70 1,661.44 1,602.31 652.65 281.78 5,028,543.44 534,122.44 2.82 -633.56 2_MWD+IFR2+MS+Sag(1) 2,018.43 49.550 27.48 1,721.73 1,662.60 718.29 316.08 6,028,609.23 534,156.44 2.73 -696.90 2_MWD+IFR2+MS+Sag(1) 2,113.43 49.740 27.95 1,783.25 1,724.12 782.37 349.75 6,028,673.46 534,189.81 0.43 -758.73 2_MWD+IFR2+MS+Sag(1) 2,208.29 47.510 30.27 1,845.95 1,786.82 844.57 384.35 6,028,735.80 534,224.13 2.98 -818.61 2_MWD+IFR2+MS+Sag(1) 2,303.86 45.600 32.61 1,911.67 1,852.54 903.77 420.52 6,028,795.16 534,260.02 2.67 -875.41 2_MW0+IFR2+MS+Sag(1) 2,399.04 42.930 35.10 1,979.83 1,920.70 958.94 457.49 6,028,850.50 534,296.74 3.35 -928.14 2_MWD+IFR2+MS+Sag(1) 2,493.72 39.770 40.40 2,050.92 1,991.79 1,008.41 495.68 6,028,900.14 534,334.70 098 -975.11 2_MWD+IFR2+MS+Sag(1) 2,588.99 35,900 43.97 2,126.15 2,067.02 1,051.74 534.84 6,028,943.64 534,373.66 4+67 -1,015.88 2_MWD+IFR2+MS+Sag(1) 2,684.23 31.870 49.02 2,205.22 2,146.09 1,088.35 57323 6,028,980.42 534,411.88 5.18 -1,049.99 2_MWD+IFR2+MS+Sag(1) 2,779.54 27.440 55.07 2,288.04 2,22891 1,117.45 61026 6,029,009.68 534,448.77 5.60 -1,076.69 2_MWD+IFR2+MS+Sag(1) 2,874.36 26.620 64.97 2,372.55 2,313.42 1,138.95 647.44 6,029,031.36 534,485.85 4.82 -1,095.81 2_MWD+IFR2+MS+Sag(1) 2,96981 24.890 73.25 2,456.54 2,399.41 1,153.80 686,07 6,029,046.37 534,524.40 4.18 -1,108.18 2_MWD+IFR2+MS+Sag(1) 3,065.47 23.970 85.80 2,545.69 2,486.56 1,161.03 724.75 6,029,053.78 534,563.05 5.50 -1,112.95 2_MWD+IFR2+MS+Sag(1) 3,160.49 25.110 96.01 2,632.17 2,573.04 1,160.33 764.07 6,1129,053.26 534,602.36 4.62 -1,109.77 2_MWD+IFR2+MS+Sag(1) 3,255.28 25.760 106.26 2,717.81 2,658.68 1,152.45 803.86 6,029,045.56 534,642.19 4.69 -1,099.40 2_MWD+IFR2+MS+Sag(1) 3,350.08 26.320 116.22 2,803.03 2,743.90 1,137.39 842.51 5,029,030.68 534,680.91 4.65 -1,081.93 2_MWD+IFR2+MS+Sag(1) 3,445.21 26,360 123.62 2,888.31 2,829.18 1,116.37 87903 6,029,009.83 534,717.51 3.45 -1.058.65 2_MWD+IFR2+MS+Sag(1) 3,540.46 26.990 130.17 2,973.44 2,914.31 1,090.72 913.16 6,028,984.33 534,751.76 3.16 -1,030.89 2_MWD+IFR2+MS+Sag(1) 3,635.30 29.270 135.86 3.057.08 2,997.95 1,060.19 94576 6,028,953.96 534,784.50 3.71 -998.36 2 MWD+IFR2+MS+Sag(1) 3,731.00 32.230 141.06 3,139.33 3,08020 1,023.53 978.11 6,028,917.45 534,817.00 4.16 -959.74 2_MWD+IFR2+MS+Sag(1) 3,826.07 33.920 144.65 3,219.00 3,159.87 982.17 1,009.39 6,028,876.24 534,848.47 2.72 -916.48 2_MW13+1FR2+MS+Sag(1) 3,921.33 37.560 149.54 3,296.33 3,237.20 935.44 1,039.51 6,028,829.65 534,878.80 4.85 -867.95 2_MWD+IFR2+MS+Sag(1) 4,016.57 40.150 154.66 3,370.51 3,311.38 882.65 1,067.38 6,028,776.99 534,906.90 4.33 4i13.50 2_MW0+IFR2+MS+Sag(1) 4,111.57 44.580 159.39 3,440.70 3,381.57 823.71 1,092.24 6,028,718.17 534,932.03 574 -753.11 2_MWD+IFR2+MS+Sag(1) 4,207.07 50.360 163.71 3,505.25 3,446.12 756.97 1,114.38 6,028,651.54 534,954.47 6.91 -685.11 2_MWD+IFR2+MS+Sag(1) 4,303.20 52380 166.59 3,565.00 3,505.87 684.20 1,133.64 6,028,578.86 534,974.06 3.44 -611.26 2_MWD+IFR2+MS+Sag(1) 4,398.11 55,950 169.05 3,620.29 3,561.16 608.81 1,149.88 6,028,503.55 534,990.64 3.95 -534.99 2_MWD+IFR2+MS+Sag(1) 4,493.34 58.410 17116 3,671.91 3,612.78 529.91 1,163.19 6,028,424.73 535,004.31 3.52 455.41 2_MWD+IFR2+MS+Sag(1) 4,588.28 63.280 173.94 3,718.15 3,659.02 447.67 1,173.47 6,028,342.54 535,014.96 5.51 -372.69 2_MWD+IFR2+MS+Sag(1) 4,683.42 66.020 175.23 3,758.89 3,699,76 362.09 1,181.57 6,028,257.00 535,023.45 3.13 -28676 2_MWD+IFR2+MS+Sag(1) 4,778.21 68.160 174.49 3,795.78 3,736.65 275.13 1,189.40 6,028,170.09 535,031.67 2.37 -199.49 2_MWD+IFR2+MS+Sag(1) 4,873.33 72.640 177.44 3,827.69 3,768.56 185.78 1,195.67 6,028,080.78 535,038.35 5.54 -109.92 2_MWD+IFR2+MS+Sag(1) 5/2712019 3:15:29PM Page 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hiloorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-20 MPU M-20 MPU M-20 Local Cc -ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M-20 MPU M-20 Actual RKB @ 59.13usft (Doyon 14) MPU M-20 Actual RKB @ 59.13usft (Doyon 14) True Minimum Curvature NORTH US+CANADA Survey - Map Map Vertical MD Inc. Azi TVD NDSS +N/S +E( -W Northing Easting DLS Section (usft) (°) (') (usft) (usft) (usft) (usft) (ft) Of) r1loo') (ft) Survey Tool Name 4,969.00 76.930 179.20 3,852.79 3,793.66 93.53 1,198.36 6,027,988.55 535,041.46 4.82 -17.68 2_MWD+IFR2+MS+Sag(1) 5,062.54 83.500 181.62 3,868.69 3,809.56 1.41 1,197.68 6,027,896.44 535,041.20 7.47 74.21 2_MWD+IFR2+MS+Sag(1) 5,141.35 85.420 183.00 3,876.29 3,817.16 -76.97 1,194.52 6,027,818.06 535,038.40 300 152.23 2_MWD+IFR2+MS+Sag(1) 5,207.40 85.500 182.54 3,881.52 3,822.39 -142.73 1,191.33 6,027,752.28 535,035.51 0.70 217.66 2_MWD+1FR2+MS+Sag(2) 5,247.66 85.810 184.14 3,884.57 3,825.44 -182.81 1,189.00 6,027,712.20 535,033.36 4.04 257.51 2_MWD+IFR2+MS+Sag(2) 5,343.18 88290 185.22 3,889.49 3,830.36 -277.87 1,181.21 6,027,617.11 535,026.01 2.83 351.90 2_MWD+IFR2+MS+Sag(2) 5,439.39 88.960 184.85 3,891.80 3,832.67 -373.68 1,172.77 6,027,521.27 535,018.00 0.80 446.98 2_MWD+IFR2+MS+Sag(2) 5,535.29 88.840 183.93 3,893.64 3,834.51 469.28 1,165.43 6,027,425.65 535,011.10 097 541.93 2_MWD+IFR2+MS+Sag(2) 5,630.83 89.950 183.08 3,894.65 3,835.52 -564.64 1,159.59 6,027,330.28 535,005.69 1.46 636.72 2_MWD+IFR2+MS+Sag(2) 5,725.94 90.570 182.89 3,894.21 3,835.08 -659.62 1,154.64 6,027,235.29 535,001.17 0.68 731.20 2_MWD+IFR2+MS+Sag(2) 5,821.08 90.750 181.22 3,893.12 3,833.99 -754.69 1,151.23 6,027,140.21 534,998.20 1.77 825.86 2_MWD+IFR2+MS+Sag(2) 5,916.50 91.250 181.59 3,891.45 3,832.32 -850.06 1,148.89 6,027,044.84 534,996.29 0.65 920.90 2_MWD+IFR2+MS+Sag(2) 6,011.54 91.990 182.61 3,888.77 3,829.64 -945.00 1,145.41 6,026,949.90 534,993.24 1.33 1,015.43 2_MWD+IFR2+MS+Sag(2) 6,106.81 92.230 184.84 3,885.26 3,826.13 -1,040.00 1,139.22 6,026,854.88 534,987.49 2.35 1,109.85 2_MWD+IFR2+MS+Sag(2) 6,202.19 91.740 185.21 3,881.95 3,822.82 -1,134.95 1,130.87 6,026,759.90 534,979.57 0.64 1,204.09 2_MWD+IFR2+MS+Sag(2) 6,297.27 91.990 184.02 3,878.86 3,819.73 -1,229.67 1,123.23 6,026,665.15 534,972.36 1.28 1,298.14 2_MWD+IFR2+MS+Sag(2) 6,392.10 93.780 183.50 3,874.09 3,814.96 -1,324.17 1,117.02 6,026,570.63 534,966.56 1.97 1,392.06 2_MWD+IFR2+MS+Sag(2) 6,487.53 93.660 183.81 3,867.90 3,808.77 -1,419.21 1,110.94 6,026,475.58 534,960.94 0.35 1,486.52 2_MWD+IFR2+MS+Sag(2) 6,582.75 92.850 183.68 3,862.49 3,803.36 -1,514.07 1,104.74 6,026,380.70 534,955.16 0.86 1,580.80 2 MWD+IFR2+MS+Sag(2) 6,678.66 91.490 183.95 3,858.86 3,79973 -1,609.70 1,098.36 6,026,285.06 534,949.22 1.45 1,675.83 2_MWD+IFR2+MS+Sag(2) 6,773.83 91.310 184.65 3,856.53 3,797.40 -1,704.57 1,091.23 6,026,190.16 534,942.52 0.76 1,770.07 2 MWD+IFR2+MS+Sag(2) 6,868.22 89.890 185.11 3,855.54 3,796.41 -1,798.61 1,083.20 6,026,096.09 534,934.92 1.58 1,863.41 2_MWD+IFR2+MS+Sag(2) 6,963.41 89.330 183.59 3,856.19 3,797.06 -1,893.52 1,075.98 6,026,001.16 534,928.14 1.70 1,957.68 2_MWD+IFR2+MS+Sag(2) 7,058.32 90.140 187.16 3,856.63 3,797.50 -1,988.00 1,067.09 6,025,906.65 534,919.68 3.86 2,051.40 2_MW13+1FR2+MS+Sag(2) 7,153.40 88.470 188.39 3,857.78 3,79865 -2,082.19 1,054.23 6,025,812.41 534,907.25 2.18 2,144.60 2_MWD+IFR2+MS+Sag(2) 7,248.12 89.090 187.72 3,859.80 3,800.67 -2,175.95 1,040.96 6,025,718.60 534,894.40 0.96 2,237.34 2_MWD+1FR2+MS+Sag(2) 7,343.86 90.140 187.12 3,860.44 3,801.31 -2,270.89 1,028.59 6,025,623.62 534,882.47 1.26 2,331.30 2_MWD+IFR2+MS+Sag(2) 7,438.72 92.730 184.35 3,858.07 3,798.94 -2,365.23 1,019.12 6,025,529.25 534,873.43 4.00 2,424.85 2_MWD+IFR2+MS+Sag(2) 7,533.64 94.040 183.12 3,852.46 3,793.33 -2,459.78 1,012.95 6,025,434.68 534,867.69 1.89 2,518.82 2_MWD+IFR2+MS+Sag(2) 7,628.53 92.360 180.65 3,847.17 3,78804 -2,554.46 1,009.83 6,025,340.00 534,865.00 3.14 2,613.12 2_MWD+IFR2+MS+Sag(2) 7,724.71 92.600 179.26 3,843.00 3,783.87 -2,650.54 1,009.91 6,025,243.92 534,86552 1.47 2,709.02 2_MWD+IFR2+MS+Sag(2) 7,820.42 91.990 179.51 3,839.17 3,780.04 -2,746.17 1,010.93 6,025,14831 534,86(1 0.69 2,804.52 2_MWD+IFR2+MS+Sag(2) 7,915.29 92.790 180.67 3,835.22 3,776.09 -2,840.96 1,010.78 6,025,053.53 534,867.26 1.48 2,899.11 2_MWD+IFR2+MS+Sag(2) 8,010.63 91.370 178.96 3,831.76 3,772.63 -2,936.23 1,011.09 6,024,958.27 534,868.00 2.33 2,994.21 2_MWD+IFR2+MS+Sag(2) 8,105.75 92.670 179.22 3,828.40 3,769.27 -3,031.27 1,012.60 6,024,863.24 534,869.94 1.39 3,089.16 2_MWD+IFR2+MS+Sag(2) 8,200.72 93.780 179.36 3,823.06 3,76393 -3,126.08 1,013.78 6,024,768.45 534,871.55 1.18 3,183.85 2_MWD+IFR2+MS+Sag(2) 8,296.58 94.770 181.17 3,815.91 3,756.78 -3,221.67 1,013.34 6,024,672.87 534,871.54 2.15 3,279.22 2_MWD+IFR2+MS+Sag(2) 8,391.84 95.960 184.68 3,807.00 3,747.87 -3,316.37 1,008.50 6,024,578.16 534,867.14 3.88 3,373.43 2_MWD+IFR2+MS+Sag(2) 8,487.18 94.340 186.66 3,798.45 3,739.32 -3,410.86 999.12 6,024,483.64 534,858.19 2.68 3,467.13 2_MWD+IFR2+MS+Sag(2) 8,582.79 93.780 185.13 3,791.68 3,732.55 -3,505.72 989.32 6,024,388.75 534,848.83 1.70 3,561.19 2_MWD+IFR2+MS+Sag(2) W712019 3:15:29PM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-20 MPU M-20 MPU M-20 Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M-20 MPU M-20 Actual RKB @ 59.13usft (Doyon 14) MPU M-20 Actual RKB @ 59.13usft (Doyon 14) True Minimum Curvature NORTH US+CANADA Survey - - Map Map vertical MD Inc Azl TVD NDSS +NIS +E/.W Northing Easting DLS Section (usft) (1) 0 (usft) (usft) (usft) (usff) (ft) (ft) (-/109') (ft) Survey Tool Name 8,678.14 94.650 184.01 3,7&1.67 3,725.54 ],600.51 98175 6,024,293.93 534,841.68 1.48 3,655.31 2_MWD+IFR2+MS+Sag(2) 8,773.23 94.270 183.83 3,777.27 3,718.14 -3,695.09 975.26 6,024,199.33 534,835.63 0.44 3,749.29 2_MWD+IFR2+MS+Sag(2) 8,868.06 96.320 185.01 3,768.52 3,709.39 -3,789.22 967.99 6,024,105.17 534,826.79 2.49 3,842.78 2_MWD+IFR2+MS+Sag(2) 8,963.16 95.140 183.09 3,759.03 3,69990 -3,883.61 961.31 6,024,010.77 534,822.54 2.36 3,936.55 2_MWD+IFR2+MS+Sag(2) 9.058.33 93.960 183.31 3,751.48 3,692+35 -3,978.33 956.01 6,023,916.04 534,817.67 1.26 4,030.75 2_MWD+IFR2+MS+Sag(2) 9,153.95 93.530 182.39 3,74523 3,686.10 4.073.62 951.27 6,023,820.73 534,813.36 ton 4,125.56 2_MWD+IFR2+MS+Sag(2) 9,247.55 91.860 179.33 3,740.83 3,681.70 4,157.10 94987 6,023,727.26 534,812.39 3.72 4,218.75 2_MWD+IFR2+MS+Sag(2) 9,345.03 91.860 179.13 3,737.67 3,678.54 3,264.51 951.18 6,023,629.86 534,814.14 0.21 4,316.06 2_MWD+IFR2+MS+Sag(2) 9,440.45 92.670 18179 3,733.89 3,674.76 4,359.85 95041 6,023,534.53 534,813.81 2.91 4,411.15 2_MWD+IFR2+MS+Sag(2) 9,535.50 94.410 184.51 3,728.02 3,668.89 4.454.56 945.20 6,023,439.81 534,809.03 3.39 4,505.35 2_MWD+IFR2+MS+Sag(2) 9,630.96 93.470 186.38 3,721.46 3,662.33 -0,549.36 936.16 6,023,344.98 534,800.42 2.19 4,599.39 2_MWD+IFR2+MS+Sag(2) 9,725.43 95.890 186.95 3,713.76 3.654.63 4,642.87 925.24 6,023,251.42 534,789.92 2.63 4,692.02 2_MWD+IFR2+MS+Sag(2) 9,821.06 96.380 184.56 3,703.54 3,644.41 3,737.47 915.70 6,023,156.80 534,780.82 2.54 4,785.83 2_MWD+IFR2+MS+Sag(2) 9,916.16 93530 182.73 3,695.32 3,636.19 4,832.01 909.68 6,023,062.24 534,775.23 3.56 4,879.80 2_MWD+IFR2+MS+Sag(2) 10,011.42 91.740 182.18 3,690.94 3,631.81 3,927.07 905.61 6,022,967.16 534,771.59 1.97 4,974.42 2_MWD+IFR2+MS+Sag(2) 10,106.36 90.440 182.40 3,689.14 3,630.01 -5,021.92 901.82 6,022,872.31 534,768.23 1.39 5,068.84 2_MWD+IFR2+MS+Sag(2) 10,201.28 91.370 182.30 3,687.64 3,628.51 -5,116.75 897.92 6,022,777.48 534,764.77 0.99 5,163.23 2_MWD+1FR2+MS+Sag(2) 10,252.37 91.990 182.61 3,686.14 3,627.01 -5,167.77 89574 6,022,726.45 534,762.81 1.36 5,214.01 2_MWD+IFR2+MS+Sag(2) 10,296.63 91.430 182.18 3,684.82 3,62569 -5,211.97 893.89 6,022,682.25 534,761.17 1.59 5,258.01 2_MWD+IFR2+MS+Sag(2) 10,348.79 90.560 18275 3,683.91 3.624,78 -5,264.07 891.65 6,022,630.14 534,759.16 199 5,309.86 2_MWD+IFR2+MS+Sag(2) 10,391.80 91.120 182.08 3,683.28 3,624.15 -5,307.04 889.83 6,022,587.17 534,757.54 2.03 5,352.63 2_MW0+IFR2+MS+Sag(2) 10,444.32 89.700 182.72 3,682.91 3.623.78 -5,359.51 887.63 6,022,534.69 534,755.58 2.97 5,404.86 2 MWD+IFR2+MS+Sag(2) 10,485.57 89.950 184.32 3,683.03 3,623.90 -5,400.68 885.10 6,022,493.52 534,753.24 3.93 5,445.79 2_MWD+IFR2+MS+Sag(2) 10,539.18 89.950 185.13 3,683.08 3,62395 -5,454.11 880.69 6,022,440.07 534,749.07 1.51 5,498.83 2_MWD+IFR2+MS+Sag(2) 10,581.20 89.770 185.36 3,683.18 3,624.05 -5,495.95 876.84 6,022,398.22 534,745.42 0.70 5,540.35 2_MWD+IFR2+MS+Sag(2) 10,632.61 90.140 185.32 3,683.22 3,624.09 -5,547.14 872.06 6,022,347.01 534,740.87 072 5,591.13 2_MWD+IFR2+MS+Sag(2) 10,675.91 89.830 185.77 3,683.23 3,624.10 -5,590.24 867.88 6,022,303.90 534,736.88 1.26 5,633.88 2_MWD+IFR2+MS+Sag(2) 10,727.96 89.830 185.45 3,683.39 3,624.26 -5,642.04 862.79 6,022252.09 534,732.03 0.61 5,685.25 2_MWD+IFR2+MS+Sag(2) 10,771.07 89.330 184.95 3,683.70 3,624.57 -5,684.97 858.88 6,022,209.14 534,728.32 1.64 5,727.85 2_MWD+IFR2+MS+Sag(2) 10,823.95 89,270 184+61 3,684.35 3,625.22 -5,737.66 85447 6,022,156.43 534,724.15 0.65 5,780.16 2_MWD+IFR2+MS+Sag(2) 10,865.55 89.210 184.22 3,684.90 3,625,T -5,779.13 851.27 6,022,114.95 534,721.14 0.95 5,821.35 2_MWD+IFR2+MS+Sag(2) 10,918.25 89.080 183.45 3,685.69 3,626,56 -5,831.71 847.75 6,022,062.37 534,717.85 1.48 5,873.60 2_MWD+IFR2+MS+Sag(2) 10,961.33 90.270 183.49 3,685.93 3,626.80 -5,874.71 845.14 6,022,019.36 534,715.44 2.76 5,916.35 2_MWD+IFR2+MS+Sag(2) 11,012.22 91.320 184.51 3,685+23 3,626.10 -5,925.47 841.59 6,021,968.59 534,712.12 2.88 5,966.78 2_MWD+IFR2+MS+Sag(2) 11,055.97 93.170 184.06 3,683.51 3,624.38 -5,969.06 838.33 6,021,924.99 534,709.05 4.35 6,010.08 2_MWD+IFR2+MS+Sag(2) 11,150.65 95.780 183.28 3,676.13 3,617.00 -6,063.25 832.28 6,021,830.78 534,703.44 2.88 6,103.70 2_MWD+IFR2+MS+Sag(2) 11,246.03 94.270 163.86 3,66777 3,608.64 -6,158.07 826.37 6,021,735.94 534,697.96 1.70 6,197.96 2_MWD+IFR2+MS+Sag(2) 11,341.24 93.840 184.95 3,661.04 3,601.91 -6,252.76 819.07 6,021,641.23 534,691.09 1.23 6,292.00 2_MWD+IFR2+MS+Sag(2) 11,436.48 92.790 183.66 3,655.53 3,596.40 -6,347.57 811.93 6,021,546.39 534,684.39 1.74 6,386.17 2_MWD+IFR2+MS+Sag(2) 11,530.64 93.290 181.19 3,650.54 3,59141 -6,441.51 807.96 6.021,452.45 534,680.84 2.67 6,479.67 2_MWD+IFR2+MS+Sag(2) 627/2019 3:15:29PM Page 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-20 Project: Milne Point TVD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Site: M Pt Moose Pad MD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Well: MPU M-20 North Reference: True Wellbore: MPU M-20 Survey Calculation Method: Minimum Curvature Design: MPU M-20 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/S +E/ -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (-/100') (ft) Survey Tool Name 11,626.25 93.040 180.96 3,645.26 3,586.13 -6,536.96 806.17 6,021,357.01 534,679.48 0.36 6,574.81 2_MWD+IFR2+MS+S9g(2) 11,721.58 91,180 182.60 3,641.75 3,582.62 -6,632.17 803.21 6,021,261.79 534,676.96 2.60 6,869.65 2_MWD+IFR2+MS+Sag(2) 11,815.27 91.120 185.60 3,639.87 3,580.74 -6,725.59 796.51 6,021,168.35 534,670.69 3.20 6,762.46 2_MWD+IFR2+MS+Sag(2) 11,912.10 92.850 185.99 3.636.51 3,577.38 -6,821.86 786.74 6,021,072.04 534,661.35 183 6,857.92 2_MWD+IPR2+MS+Sag(2) 12,006.66 93.790 187.99 3,631.04 3,571.91 -6,915.56 775.25 6,020,978.31 534,650.30 2.33 6,950.70 2_MWD+IFR2+MS+Sag(2) 12,102.42 92.360 188.26 3,625.90 3,566.77 -7,010.21 761.74 6,020,883.60 534,637.21 1.52 7,044.32 2_MWD+IFR2+MS+Sag(2) 12,170.00 91.320 184.99 3,623.73 3,564.60 -7,077.30 753.95 6,020,816.48 534,629.73 5.08 7,110.78 2 MWD+IFR2+MS+Sog(3) 12,196.66 89.390 185.25 3,623.56 3,564.43 -7,103.85 751.57 6,020,789.92 534,627.47 7.30 7,137.13 2_MWD+IFR2+MS+Sag(3) 12,292.76 85.430 184.49 3,627.91 3,568.78 -7,199.49 743.42 6,020,694.26 534,619.76 4.20 7,232.06 2_MWD+IFR2+MS+Sag(3) 12,387.25 84.080 185.01 3,636.54 3,577.41 -7,293.26 735.63 6,020,600.47 534,612.39 1.53 7,325.15 2_MWD+IFR2+MS+Sag(3) 12,482.95 84.690 184.68 3,645.91 3,586.78 -7,388.15 727.58 6,020,505.54 534,604.78 0.72 7,419.35 2_MWD+IFR2+MS+Sag(3) 12,577.16 86.500 184.71 3,653.14 3,594.01 -7,481.77 719.89 6,020,411.90 534,597.52 1.92 7,512.29 2_MWD+IFR2+MS+Sag(3) 12,672.58 88.840 184.08 3,657.02 3,597.89 -7,576.82 712.59 6,020,316.83 534,590.65 2.54 7,606.70 2_MW0+IFR2+MS+Sag(3) 12,767.59 90.390 183.83 3,657.66 3,598.53 -7,671.60 706.04 6,020,222.03 534,584.53 1.65 7,700.87 2_MWD+IFR2+MS+Ssg(3) 12,863.63 90.140 182.53 3,657.22 3,598.09 -7,767.49 700.71 6,020,126.13 534,579.64 1.38 7,796:23 2_MWD+IFR2+MS+Sag(3) 12,958.76 91.680 182.24 3,655.71 3,596.58 -7,862.52 696.75 6,020,031.09 534,576.11 1.65 7,890.83 2_MWD+IFR2+MS+Sag(3) 13,053.67 92.360 183.21 3,652.36 3,593.23 -7,957.26 692.24 6,019,936.33 534,572.03 1.25 7,985.09 2_MWD+IFR2+MS+Sag(3) 13,149.35 90,440 182.22 3,650.02 3,590.89 -8,052.80 687.71 6,019,840.79 534,567.94 2.26 8.080.16 2_MWD+IFR2+MS+Sag(3) 13,244.47 90.880 179.62 3,648.93 3,589.80 -8,147.90 686.18 6,019,745.70 534,566.85 2.77 8,174.96 2_MWD+IFR2+MS+Sag(3) 13,339.56 91.810 179.99 3,646.69 3,587.56 -8,242.96 686.51 6,019,650.65 534,567.60 1.05 8,269.86 2_MWD+IFR2+MS+Sag(3) 13,435.36 92.800 180.30 3,642.84 3,583.71 -8,338.68 686.27 6,019,554.93 534,567.79 1.08 8,365.37 2_MWD+IFR2+MS+Sag(3) 13,530.15 92.230 180.45 3,638.68 3,579.55 -8,433.37 685.65 6,019,460.25 534,567.61 0.62 8,459.84 2_MWD+IFR2+MS+Sag(3) 13,625.67 91.620 181.87 3,635.47 3,576.34 -8,52882 683.71 6,019,364.80 534,566.11 1.62 8,554.97 2_MWD+IFR2+MS+Sag(3) 13,720.96 92.790 184.42 3,631.81 3,572.68 -8,623.88 678.49 6,019,269.72 534,561.32 2.94 8,649.52 2_MWD+IFR2+10S+Sag(3) 13,760.00 93.100 184.00 3,629.80 3,57067 -8,662.77 675.63 6,019,230.83 534,558.63 1.34 8,688.14 2_MWD+IFR2+MS+Sag(4) 13,814.52 90.010 183.94 3,628.32 3,569.19 -8,717.13 671.86 6,019,176.46 534,555.11 5.67 8,742.16 2_MWD+IFR2+MS+Sag(4) 13,909.60 89.210 182.20 3,628.97 3,569.84 -8,812.07 666.76 6,019,081.51 534,550.45 2.01 8,836.58 2_MWD+IFR2+MS+Sag(4) 14,005,19 89.390 182.84 3,630.14 3,571.01 -8,907.56 662.56 6,018,986.01 534,546.68 0.70 8,931.62 2_MWD+IFR2+MS+Sag(4) 14,100.25 89.700 183.04 3,630.89 3,571.76 -9,002.49 657.69 6,018,891.07 534,542.24 0.39 9,026.05 2_MWD+IFR2+MS+Sag(4) 14,196.03 92.250 186.58 3,629.26 3,570.13 -9,097.89 649.66 6,018,795.63 534,534.65 4.55 9,120.76 2_MWD+IFR2+MS+Sag(4) 14,291.19 90.990 185.38 3,626.57 3,567.44 -9,192.50 639.75 6,018,701.00 534,525.17 1.83 9,214.55 2_MWD+IFR2+MS+Sag(4) 14,386.31 93050 184.87 3,623.22 3,564.09 -9,287.17 63126 6,018,606.29 53,517.11 2.23 9,308.50 2_MWD+IFR2+MS+Sag(4) 14,481.95 92.420 183.54 3,618.65 3,559.52 -9,382.44 624.25 6,018,511.00 534,510.54 1.54 9,403.14 2 MWD+IFR2+MS+Sag(4) 14,576.40 90.500 181.61 3,616.25 3,557.12 -9,476.76 620.01 6,018,416.68 53,506.73 2.88 9,497.00 2_MWD+IFR2+MS+Sag(4) 14,671.53 88.830 181.04 3,616.80 3,557.67 -9,571.86 617.81 6,018,321.58 53,504.96 1.85 9,591.77 2 MWD+IFR2+MS+Sag(4) 14,761.28 87.420 180.73 3,619.74 3,560.61 -9,661.55 616.43 6,018,231.89 53,503.98 1.61 9,681.19 2_MWD+IFR2+MS+Sag(4) 14,83080 87.420 180.73 3,622.83 3,56370 -9,730.19 615.55 6,018,163.25 534,503.42 0.00 9,749.64 PROJECTEDWTD Checked By: Mitch Laird -- michaeLcalkins2@hal °,,;,,"„a -- Approved By: liburton.com;„,„�^°^•^^ Date: 6/27/19 6127/2019 3:15:29PM Page 6 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-20PB1 500292363670 Sperry Drilling Definitive Survey Report 27 June, 2019 HALLIBURTON �._ Sperry Drilling Halliburton Definitive Survey Report Company: Hiloorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-20 Project: Milne Point TVD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Site: M Pt Moose Pad MD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Well: MPU M-20 North Reference: True Wellbore: MPU M-20PB1 Survey Calculation Method: Minimum Curvature Design: MPU M-20PB1 Database: NORTH US+CANADA Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M-20 Magnetics Model Name Sample Date Well Position -NIS 0.00 Usti Northing: 6,027,889.58 usft Latitude: 70° 29' 14.001 N +E/ -W 0.00 Usti Easting: 533,843.66 usft Longitude: 149° 43'24.168 W Position Uncertainty Inc 0.00 Usti Wellhead Elevation: 0.00 usft Ground Level: 24.90 usft Wellbore MPU M -20P81 Magnetics Model Name Sample Date Declination Dip Angle Field Strength M M (nT) BGGM2018 6130/2019 Map 16.57 80.96 57,421.87271626 MD Inc AY, TVD TVDSS +N/.S Design MPU M-20PBI Easting DLS Section Audit Notes: (I (I (usft) (usft) (usft) Version: 1.0 Phase: ACTUAL Tie On Depth: 34.23 Survey Tool Name Vertical Section: Depth From (TVD) -NIS +EbW Direction 0.00 0.00 (usft) (usft) (usft) (') UNDEFINED 22686 34.23 0.00 0.00 183.45 -0.21) purvey Program Data 6/26/2019 From To (usft) (usft) Survey (Wellbore) Toot Name Description Survey Date 226.36 5,141.35 MPU M-20 MWD+IFR2+MS+Sag (1) IMP 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec& multi -station analysis +sag 06/10/2019 5,207.40 13,116.97 MPU M-20 MWD+IFR2+MS+Sag (2) (MP 2_MWD+IFR2+MS+Sag A013MIc IIFR dec & multi -station analysis +sag 06117/2019 Survey Map Map Vertical MD Inc AY, TVD TVDSS +N/.S +E/ -W Northing Easting DLS Section (usft) (I (I (usft) (usft) (usft) (usft) (it) (ft) (°1100') (ft) Survey Tool Name 34.23 0.000 0.00 34.23 -24.90 0.00 0.00 6,027,889.58 533,843.66 0.00 0.00 UNDEFINED 22686 0.120 173.41 226.86 167.73 -0.21) 0.02 6,027,889.38 533,84368 0.06 0.20 2_MWD+IFR2+MS+Sag(1) 318.35 0640 180.11 318.35 259.22 -0.33 0.03 6,027,889.25 533,843.70 0.09 0.32 2_MWD+IFR2+MS+Sag(1) 409.37 0.940 27.40 409.37 350.24 0.30 0.38 6,027,889.89 533,844.04 1.07 -0.33 2_MWD+IFR2+MS+Sag(1) 504.54 2.670 25.58 504.48 445.35 3.00 1.69 6,027,892.58 533,845.34 1.82 J.09 2_MWDAFR2+10S+Sag(1) 595.67 5.430 13.51 595.38 536.25 9.10 3.62 6,027,898.70 533,x47.24 3.15 -9.31 2 MWD+IFR2+MS+Sag(1) 687.92 8.220 16.74 686.97 627.84 19.67 6.54 6,027,909.27 533,850.11 3.05 -20.02 2_MWD+IFR2+MS+Sag(1) 784.20 11.700 21.45 781.78 722.65 35.35 12.09 6,027,924.98 533,855.59 3.71 -36.01 2_MWD+IFR2+MS+Sag(1) 879.05 15.670 24.68 873.92 814.79 55.95 20.96 6,027,945.62 533,864.36 4.26 -57.11 2_MWD+IFR2+MS+Sag(1) 974,02 20.120 25.92 964.28 905.15 82.31 33.46 6,027,972.03 533,876.74 4.70 -84.17 2_MWD+IFR2+MS+Sag(1) 1,069.13 25640 26.48 1,051.87 992.74 115.46 49.80 6,028,005.26 533,89293 5.81 -118.25 2_MWD+IFR2+MS+S9g(1) 1,164.14 31,600 23.70 1,135.24 1,076.11 156.69 68.99 6,028,046.57 533,911.93 6.43 -160.56 2_MWD+IFR2+MS+Sag(1) 1,257.57 37.820 2061 1,212.01 1,152.88 205.97 88.93 6,028,095.93 533,931.65 6.92 -210.95 2_MWD+IFR2+MS+Sag(1) 612 712 019 12:13:07PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-20 MPU M-20PB7 MPU M-20PB1 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M-20 MPU M-20 Actual IRKS @ 59.13usft (Doyon 14) MPU M-20 Actual RKB @ 59.13usft (Doyon 14) True Minimum Curvature NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +El -W Northing Easting DLS Section (usR) (') (1) (usR) (usR) (usft) (usR) (R) (R) (-/100') (R) Survey Tool Name 1,354.18 42.980 19.04 1,285.56 1,22643 264.87 110.12 6,028,154.92 533,952.56 5.44 -271.01 2_MWD+IFR2+MS+Sag(1) 1,448.95 43.200 18.81 1,354.77 1,295.64 326.11 131.12 6,028,216.25 533,973.28 0.29 -333.41 2_MWD+IFR2+MS+Sag(1) 1,543.96 45.190 20.62 1,422.89 1,363.76 388.44 153.47 6,028,278.68 533,995.35 2.48 -396.98 2_MWD+IFR2+MS+Sag(1) 1,637.81 48.580 25.11 1,487.04 1,427.91 451.50 180.14 6,028,341.85 534,021.73 5.02 461.52 2_MWD+IFR2+MS+Sag(1) 1,733.67 51.690 26.73 1,548.48 1,489.35 517.65 212.32 6,028,408.14 534,053.60 3.49 -529.49 2_MWD+IFR2+MS+Sag(1) 1,828.90 54.780 2]24 1,60547 1,546.34 585.62 24694 6,028,476.26 534,087.91 3.27 599.42 2_MWD+IFR2+MS+Sag(1) 1,922.92 52.150 27.70 1,661.44 1,602.31 652.65 281.78 6,028,543.44 534,122.44 2.82 -668.42 2_MWD+1FR2+MS+Sag(1) 2,01843 49.550 27.48 1,721.73 1,66260 718.29 316.08 6,028,609.23 534,156.44 2.73 -736.01 2_MWD+IFR2+MS+Sag(1) 2,113.43 49.740 27.95 1,783.25 1,724.12 782.37 349.75 6,028,673.46 534,189.81 0.43 -802.00 2_MWD+IFR2+MS+Sag(1) 2,208.29 47.510 30.27 1,845.95 1,786.82 644.57 384.35 6,028,735.80 534,224.13 2.98 -866.16 2_MWD+IFR2+MS+Sag(1) 2,303.86 45.600 32.61 1,911.67 1,852.54 903.77 420.52 6,028,795.16 534,260.02 2.67 -927.43 2_MWD+IFR2+MS+Sag(1) 2,399.04 42.930 35.10 1,979.83 1,920.70 958.94 457,49 6,028,850.50 534,296.74 3.35 -984.74 2_MWD+IFR2+MS+Ssg(1) 2,493.72 39.T70 40.40 2,050.92 1,991.79 1,008.41 49568 6,028,900.14 534,334.]0 4.98 -1,036.41 2_MWD+IFR2+MS+Sag(1) 2,588.99 35900 43.97 2,126.15 2,067.02 1,051.74 534.84 6,028,943.64 534,373.66 4.67 -1,082.02 2_MWD+IFR2+MS+Sag(1) 2,684.23 31.870 49.02 2,205.22 2,14609 1,088.35 573.23 6,028.980.42 534,411.88 5.16 -1,120.87 2_MWD+IFR2+MS+Sag(1) 2,779.54 27.440 55.07 2,288.04 2,228.91 1,117.45 610.26 6,029,009.68 534,448.77 5.60 -1,152.14 2_MWD+IFR2+MS+Seg(1) 2,874.36 26.620 64.97 2,372.55 2,313.42 1,138.95 647.44 6,029,031.36 534,485.85 4.82 -1,175.85 2_MWD+IFR2+MS+Sag(1) 2,969.81 24.890 73.25 2,456.54 2,399.41 1,153.80 68607 6,029,046.37 534,524.40 4.18 -1,192.99 2_MWD+IFR2+MS+Sag(1) 3,065.47 23.970 85.80 2,545.69 2,486.56 1,161.03 724.75 6,029,053]8 534,563.05 5.50 -1,202.54 2_MWD+IFR2+MS+Sag(1) 3,160.49 25.110 96.01 2,632.17 2,573.04 1,16033 76407 6,029,053.26 534,602.36 4.62 -1,204.21 2_MWO+IFR2+MS+Sag(1) 3,255.28 25.760 106.26 2,717.81 2,658.66 1,152.45 803.86 6,029,045.56 534,642.19 4.69 -1,198.74 2_MWD+IFR2+MS+Sag(1) 3,350.08 26.320 116.22 2,803.03 2,743.90 1,137.39 842.51 6,029,030.68 534,680.91 4.65 -1,186.03 2_MWD+IFR2+MS+Sag(1) 3,445.21 26.360 123.62 2,888.31 2,829.18 1,116.37 879.03 6,029,009.83 534,717.51 3.45 -1,167.25 2_MWD41FR2+MS+Sag(1) 3,540.46 26.990 130.17 2,973.44 2,914.31 1,090.72 913.16 6,028,984.33 534,751.76 3.16 -1,143.69 2_1AWD+1FR2+MS+Sag(1) 3,635.30 29.270 135.86 3,057.08 2,997.95 1,060.19 945.76 6,028,953.96 534,784.50 3.71 -1,115.18 2_MWD+IFR2+MS+Sag(1) 3,731.00 32.230 141.06 3,139.33 3,080.20 1,023.53 978.11 6,028,917.45 534,817.00 4.16 -1,080.54 2_MWD+IFR2+MS+Sag(1) 3,826.07 33.920 144.65 3,219.00 3,159.87 982.17 1,009.39 6,028,876.24 534,848.47 2.72 -1,041.14 2_MWD+IFR2+MS+Sag (1) 3,921.33 37.560 149.54 3,296.33 3,237.20 935.44 1,039.51 6,028,829.65 534,878.80 4.85 -996.30 2_MWD+IFR2+MS+Sag(1) 4,016.57 40.150 154.66 3,370.51 3,311.38 882.65 1,067.38 6,028,776.99 534,906.90 4.33 -945.28 2_MWD+IFR2+MS+Sag(1) 4,111.57 44.580 15939 3,440.70 3,381.57 823.71 1,092.24 6,028,718.17 534,932.03 5.74 -887.95 2_MWD+IFR2+MS+Sag(1) 4,207.07 50.360 163.71 3,505.25 3,446.12 756.97 1,114.38 6,028,651.54 534,954.47 6.91 -822.66 2_MWD+IFR2+MS+Sag(1) 4,303.20 52.780 166.59 3,565.00 3,505.87 684.20 1,133.64 6,028,578.86 534,974.06 3.44 -751.18 2_MWD+IFR2+MS+Sag(1) 6,398.11 55.950 169.05 3,620.29 3,561.16 608.81 1,149.88 6,028,503.55 534,990.64 3.95 -676.90 2_MWDNFR2+MS+Sag(1) 4,493.34 58.410 171.76 3,671.81 3.612.78 529.97 7,163.79 6,028,424.73 535,004.31 3.52 -598.95 2_MWD+IFR2+MS+Sag (1) 4,588.28 63.280 173.94 3,718.15 3,659.02 447.67 1,173.47 6,028,342.54 535,014.96 5.51 -517.48 2MWD+IFR2+MS+Sag(1) 4,6a3.42 66.020 175.23 3,758.89 3,699.76 362.09 1,181.57 6,028,257.00 535,023.45 3.13 -032.53 2_MWD+IFR2+MS+Seg(1) 4,778.21 68.160 174.49 3,795.78 3,736.65 275.13 1,189.40 6,028,170.09 535,031.67 2.37 -346.21 2_MWD+IFR2+MS+Sag(1) 4,873.33 72,640 177.44 3,82].69 3,768.56 185.78 1,195.67 6,028,080.78 535,038.35 5.54 -257.39 2_MWD+IFR2+MS+Ssg(1) 4,969.00 76.930 179.20 3,852.79 3,793.66 93.53 1,198.36 6,027,988.55 535,041.46 4.82 -165.47 2_MWD+IFR2+MS+Sag(1) 5,062.54 83.500 181.62 3,868.69 3,809.56 1.41 1,197.68 6,027,896.44 535,041.20 7.47 -73.48 2MWD+IFR2+MS+Sag(1) 6/27/2019 12:13:07PM Page 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-20 Project: Milne Point TVD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Site: M Pt Moose Pad MD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Well: MPU M-20 North Reference: True Wellbore: MPU M-20PB1 Survey Calculation Method: Minimum Curvature Design: MPU M-20PB1 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (1) (•) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 5,141.35 85.420 183.00 3,876.29 3,817.16 -76.97 1,194.52 6,027,818.06 535,038.40 3.00 4.94 2_MWD+IFR2+MS+Sag(1) 5,207.40 85.500 182.54 3,881.52 3,822.39 -142.73 1,191.33 6,027,752.28 535,035.51 0.70 70.78 2_MWD+IFR2+MS+Sag(2) 5,247.66 85.810 184.14 3,884.57 3,82544 -182.81 1,189.00 6,027,712.20 535,033.36 4.04 110.92 2_MWD+IFR2+MS+Sag(2) 5,343.18 88.290 185.22 3,889.49 3,830.36 -277.87 1,181.21 6,027,617.11 535,026.01 2.83 206.29 2_MWD+IFR2+MS+Sag(2) 5,439.39 88.960 184.85 3,891.80 3,832.67 -373.68 1,172.77 6,027,521.27 535,018.00 0.80 302.43 2_MWD+IFR2+MS+Sag(2) 5,53529 88.840 18393 3,893.64 3,834.51 469.28 1,165.43 6,027,425.65 535,011.10 0.97 398.30 2_MWD+IFR2+MS+Sag(2) 5,630.83 89.950 183.08 3,894.65 3,835.52 -564.64 1,159.59 6,027,330.28 535,00569 1.46 493.83 2_MWD+IFR2+MS+Sag(2) 5,725.94 90.570 182.89 3,894.21 3,835.08 -659.62 1,154.fi4 6,027,235.29 535,001.17 0.68 588.94 2_MWD+IFR2+MS+Sag(2) 5,821.08 90.750 181.22 3,893.12 3,833.99 -754.69 1,151.23 6,027.140.21 534,998.20 1.77 684.04 2_MWD+IFR2+MS+Sag(2) 5,916.50 91.250 181.59 3,891.45 3,832.32 450.06 1,148.89 6,027,044.84 534,996.29 0.65 779.38 2_MWD+IFR2+MS+Sag(2) 6,011.54 91.990 182.61 3,888.77 3,829.64 -945.00 1,145.41 6,026949.90 534,993.24 1.33 874.36 2_MWD+IFR2+MS+Sag(2) 6,106.81 92.230 184.84 3,885.26 3.826.13 -1,040.00 1,139.22 6,026,854.88 534,98]49 2.35 969.56 2_MWD+IFR2+MS+Sag(2) 6,202.19 91.740 185.21 3,881.95 3,822.82 -1,134.95 1,130.87 6.026.759.90 534,979.57 0.64 1,064.84 2_MWD+IFR2+MS+Sag(2) 6,297.27 91.990 184.02 3,878.86 3,819.73 -1,229.67 1,123.23 6,026,665.15 534,972.36 1.28 1,159.85 2_MWD+IFR2+MS+Sag(2) 6,392.10 93780 183.60 3,874.09 3,81496 -1,324.17 1,117.02 6,026,570.63 534,966.58 1.97 1,254.56 2_MWD+IFR2+MS+Sag(2) 6,487.53 93660 183.81 3,867.90 3,808.77 -1,419.21 1,110.94 6,026,475.58 534,960.94 0.35 1,349.78 2_MWD+IFR2+MS+Sag(2) 6,582.75 92.850 183.68 3,862.49 3,803.36 -1,514.07 1,104.74 6,026,380.70 534,955.16 0.86 1,444.85 2_MWD+IFR2+MS+Sag(2) 6,678.66 91.490 183.95 3,858.86 3,799.73 1,609.70 1,098.36 6,026,285.06 534,949.22 1.45 1,540.68 2_MWD+IFR2+MS+Sag(2) 6,773.83 91.310 184.65 3,856.53 3,797.40 -1,704.57 1,091.23 6,026,190.16 534,942.52 0.76 1,635.82 2_MWD+IFR2+MS+Sag(2) 6868.22 89.890 185.11 3,855.54 3,79641 -1,798.61 1,083.20 6,026,096.09 534,934.92 1.58 1,730.17 2_MWD+IFR2+MS+Sag(2) 6,963.41 89330 183.59 3,856.19 3,79706 -1,893.52 1,075.98 6,026,001.16 534,928.14 1.70 1,825.34 2_MWD+IFR2+MS+Sag(2) 7,058.32 90.140 187.16 3,856.63 3,797.50 -1,988.00 1,067.09 6,025,906.65 534,919.68 3.86 1,920.18 2_MWD+IFR2+MS+Sag(2) 7,153.40 88.470 188.39 3,857.78 3,798.65 -2,082.19 1,054.23 6,025,812.41 534,907.25 2.18 2,014.98 2_MWD+IFR2+MS+Sag(2) 7,248.12 89.090 187.72 3,859.80 3,800.67 -2,175.95 1,040.96 6,025,718.60 534,894.40 0.96 2,109.37 2_MWD+IFR2+MS+Sag(2) 7,343.86 90.140 187.12 3,860.44 3,801.31 -2,270.89 1,028.59 6,025,623.62 534,882.47 1.26 2,204.88 2_MWD+IFR2+MS+Sag(2) 7,438.72 92.730 184.35 3,858.07 3,798.94 -2,36523 1,019.12 6,025,529.25 534,873.43 4.00 2,299.61 2_MWD+IFR2+MS+Sag(2) 7,533.64 94040 183.12 3,852.46 3,793.33 -2,459.78 1,012.95 6,025,434.68 534,867.69 1.89 2,394.36 2_MWD+IFR2+MS+Sag(2) 7,628.53 92.360 180.65 3,847.17 3,788.04 -2,554.46 1,009.83 6,025,340.00 534,865.00 3.14 2,489.06 2_MW0+IFR2+MS+Sag(2) 7,724.71 92.600 179.26 3,843.00 3,783.87 -2,650.54 1,009.91 6,025,243.92 534,865.52 1.47 2,564.97 2_MWD+IFR2+MS+Sag(2) 7,820.42 91.990 179.51 3,839.17 3,780.04 -2,746.17 1,010.93 6,025,148.31 534,866.98 0.69 2,680.36 2_MWD+IFR2+MS+Sag(2) 7,915.29 92.790 180.67 3,835.22 3,776.09 -2,840.96 1,010.78 6,025,053.53 534,867.26 1.48 2,774.98 2_MWD+IFR2+MS+Sag(2) 8,010.63 91.370 178.96 3,831.76 3,77263 -2,93623 1,011.09 6,024,958.27 534,868.00 2.33 2.870.06 2_MWD+IFR2+MS+Sag(2) 8,105.75 92.670 179.22 3,828.40 3,769.27 -3,031.27 1,012.60 6,024,863.24 534,869.94 1.39 2,964.84 2_MWD+IFR2+MS+Sag(2) 8,200.72 93.780 179.36 3,823.06 3,763.93 -3,126.08 1,013.78 5,024,768.45 534,871.55 1.18 3,059.41 2_MWD+IFR2+MS+Sag(2) 8,296.58 94.770 181.17 3,815.91 3,756.78 -3,221.67 1,013.34 6,024,672.87 534,871.54 2.15 3,154.85 2_MWD+IFR2+MS+Sag(2) 8,391.84 95.960 184.68 3,807.00 3,747.87 -3,316.37 1,008.50 6,024,578.16 534,867.14 3.88 3,249.67 2_MWD+IFR2+MS+Sag(2) 8,487.18 94.340 186.66 3,798.45 3,739.32 -3,410.86 999,12 6,024,483.64 534,858.19 2.68 3,344.55 2_MWD+IFR2+MS+Sag(2) 8,582.79 93.780 185.13 3,791+68 3,732.55 -3,505.72 989.32 6,024,388.75 534,848.83 1.70 3,439.83 2_MWD+IFR2+MS+Sag(2) 8,678.14 94650 184.01 3,784.67 3,725.54 -3,600.51 981.75 6,024,293.93 534,841.68 1.48 3,534.90 2 MWD+IFR2+MS+Sag(2) 8,773.23 94.270 183.83 3,777.27 3,718.14 -3,695.09 975.26 6,024,199.33 534,835.63 0.44 3,629.70 2_MWD+IFR2+MS+Sag(2) 6/27/2019 12:13.07PM Page 4 COMPASS 5000.15 Build 91 I ( Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-20 project: Milne Point TVD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Site: M Pt Moose Pad MD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Well: MPU M-20 North Reference: True Waltham: MPU M-20PB1 Survey Calculation Method: Minimum Curvature Design: MPU M-20PB1 Database: NORTH US+CANADA Survey 6/272019 12:13:07PM Page 5 COMPASS 5000.15 Build 91 Map Map vertical MD Inc AZI TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,866.06 96.320 185.01 3,768.52 3,709,39 -3,789.22 967.99 6,024,105.17 534,828.79 2.49 3,724.11 2_MWD+IFR2+MS+Sag (2) 8,963.16 95.140 183.09 3,759.03 3,699.90 -3,883.61 961.31 6,024,010.77 534,822.54 2.36 3,818.72 2_MWD+IFR2+MS+Sag(2) 9,058.33 93.960 183.31 3,751.48 3,692.35 -3,978.33 956.01 6,023,916.04 534,817.67 1.26 3,913.59 2_MWD+IFR2+MS+Sag(2) 9,153.95 93.530 182.39 3,745.23 3,686.10 4,073.62 951.27 6,023,820.73 534,813.36 1.06 4,009.00 2_MWD+IFR2+MS+Sag(2) 9,247.55 91.860 179.33 3,740.83 3,68170 4,167.10 949.87 6,023,727.26 534,812.39 3.72 4,102.38 2_MWD+IFR2+MS+Sag(2) 9,345.03 91.860 179.13 3,73267 3,678.54 4,264.51 951.18 6,023,629.86 SM.t14.14 0.21 4,199.55 2_MWD+IFR2+MS+Sag(2) 9,440.45 92.670 181.79 3,733.89 3,674.76 4,359.85 95041 6,023,534.53 534,813.81 2.91 4,29475 2_MWD+IFR2+MS+Sag(2) 9,53550 94.410 184.51 3,728.02 3,668.89 4.454.56 945.20 6,023,439.81 534,809.03 3.39 4,389.61 2_MWD+IFR2+MS+Sag(2) 9,630.96 93470 186.38 3,721.46 3,662.33 4,549.36 936.16 6,023.344.98 534,800.42 2.19 4,484.78 2_MWD+IFR2+MS+Sag(21 9,725.43 95.890 186.95 3,713.76 3,654.63 4,642.87 925.24 6,023,251.42 534,789.92 2.63 4,578.78 2_MWD+IFR2+MS+Sag(2) 9,821.06 96.380 184.56 3,703.54 3,644.41 4,737.47 915.70 6,023,156.80 534,780.82 2.54 4,673.78 2_MWD+IFR2+MS+Sag(2) 9,916.16 93.530 182.73 3,695.32 3,636.19 4,832.01 909.68 6,023,062.24 534,775.23 3.56 4,768.51 2_MWD+IFR2+MS+Sag(2) 10,011.42 91.740 182.18 3,690.94 3,631.81 4,927.07 905.61 6,022,967.16 534,771.59 1.97 4,863.65 2_MWD+IFR2+MS+Sag(2) 10,106.36 90.440 182.40 3,689.14 3,630.01 -5,021.92 901.82 6,022,872.31 534,768.23 1.39 4,958.55 2_MWD+IFR2+MS+Sag(2) 10,201.28 91.370 182.30 3,687.64 3,628.51 -5,116.75 897.92 6,022,777.48 534,764.77 0.99 5,053.44 2_MWD+IFR2+MS+Sag(2) 10,252.37 91.990 182.61 3,686.14 3,627A1 -5,167.77 895.74 6,022,726.45 534,762.81 1.36 5,104.50 2_MWD+IFR2+MS+Sag(2) 10,296.63 91.430 182.18 3,684.82 3,625.69 -5,211.97 89389 6,022,682.25 534,761.17 1.59 5,148.73 2_MWD+IFR2+MS+Sag(2) 10,348.79 90.560 182.75 3,683.91 3,624.78 -5,264.07 891.65 6,022,630.14 534,759.16 1.99 5,200.87 2_MWD+IFR2+MS+Sag(2) 10,391.80 91.120 182.08 3,683.28 3,624.15 -5,307.04 889.83 6,022,587.17 534,757.54 2.03 5,243.87 2_MWD+IFR2+MS+Sag(2) 10,444.32 89700 182.72 3,682.91 3,623.78 -5,359.51 887.63 6,022,534.69 534,755.58 2.97 5,296.38 2_MWD+IFR2+MS+Sag(2) 10,485.57 89.950 184.32 3,683.03 3,623.90 -5,400.68 885.10 6,022,493.52 534,753.24 3.93 5,337.63 2_MWD+IFR2+MS+Sag(2) 10,539.18 89.950 185.13 3,683.08 3,623.95 -5,454.11 880.69 6,022,440.07 534,749.07 1.51 5,391.23 2_MWD+IFR2+MS+Sag(2) 10,581.20 89.770 185.36 , 3,683.18 3,624.05 -5,495.95 876.84 6,022,398.22 534,745.42 0.70 5,433.22 2_MWD+IFR2+MS+Sag (2) 10,632.61 90.140 185.32 3,683.22 3,624.09 -5,54].14 872.06 6,022,347.01 534,740.87 0.72 5,484.61 2_MWD+IFR2+MS+Sag(2) 10,675.91 89.830 185.77 3,683.23 3,624.10 -5,590.24 867.88 6,022,303.90 534,736.88 1.26 5,527.88 2_MWD+IFR2+M5+Sag(2) 10,727.96 89.830 185.45 3,683.39 3,62626 -5,642.04 862.79 6,022,252.09 534,732.03 0.61 5,579.89 2_MWD+IFR2+MS+Sag(2) 10,771.07 89.330 184.95 3,683.70 3,624.57 -5,686.97 858.88 6,022,209.14 534,728.32 1.64 5,622.98 2_MWD+IFR2+MS+Sag(2) 10,823.95 89.270 184.61 3,684.35 3,625.22 -5,737.66 854.47 6,022,156.43 534,724.15 0.65 5,675.84 2_MWD+IFR2+MS+Sag(2) 10,865.55 89.210 184.22 3,684.90 3,625.77 6,779.13 851.27 6,022,114.95 534,721.14 0.95 5,717.43 2_MWD+IFR2+MS+Sag(2) 10,918.25 89.080 183.45 3,685,69 3,626.56 -5,831.71 847.75 6,022,062.37 534,717.85 1.48 5,770.12 2_MWD+IFR2+MS+Sag(2) 10,961.33 90.270 183.49 3,685.93 3,626.80 -5,874.71 845.14 6,022,019.36 534,715.44 2.76 5,813,20 2_MWD+IFR2+MS+Sag(2) 11,012.22 91.320 184.51 3,685.23 3,626,10 -5,925.47 841.59 6,021,968.59 534,712.12 2.88 5,864.08 2_MWD+IFR2+MS+Sag(2) 11,055.97 93.170 18406 3,683.51 3,624.38 -5,969.06 838.33 6,021,924.99 534,709.05 4.35 5,907.79 2 MWD+IFR2+MS+Sag(2) 11,150.65 95.780 183.28 3,676.13 3,617.00 41,06325 832.28 6,021.830.78 534,703.44 2.88 6,002.17 2_MWD+IFR2+MS+Sag(2) 11,246.03 94.270 183.86 3,667.77 3,608.64 -6,158.07 826.37 6,021,735.94 534,697.96 1.70 6,097.18 2_MWD+IFR2+MS+Sag(2) 11,341.24 93.840 184.95 3,661.04 3,601.91 -6,252.76 819.07 6,021,641.23 534,691.09 1.23 6,192.14 2_MWD+IFR2+MS+Sag(2) 11,436.48 92.790 183.66 3,655.53 3,596.40 -6,347.57 811.93 6,021,546.39 534,684.39 1.74 6,287.21 2_MWD+IFR2+MS+Sag(2) 11,530.64 93.290 181.19 3,650.54 3,591.41 -6,441.51 807.96 6,021,452.45 534,680.84 2.67 6,381.21 2_MWD+IFR2+MS+Sag(2) 11,626.25 93.040 180.96 3,645.26 3,586.13 6,536.96 806.17 6,021,35701 534,679.48 0.36 6,476.60 2_MWD+IFR2+MS+Sag(2) 11,721.58 91.180 182.60 3,64175 3,582.62 -6,632.17 803.21 6,021,261.79 534,676.96 2.60 6,571.81 2_MWD+IFR2+MS+Sag(2) 6/272019 12:13:07PM Page 5 COMPASS 5000.15 Build 91 Company: Project: Site: Well: Wellbore: Design: Survey Halliburton Definitive Survey Report Hilcorp Alaska, LLC Local Co-ordinate Reference: Milne Point TVD Reference: M P1 Moose Pad MO Reference: MPU M-20 North Reference: MPU M-20PB7 Survey Calculation Method: MPU M-20PB1 Database: MD Inc (usft) (') 11,815.27 91.120 11,912.10 92.850 12,006.66 93.790 12,102.42 92.360 12,198.04 90.880 12,291.71 90.080 12,387.75 86.860 12,483.13 84.750 12,577.96 86.060 12,673.60 85.310 12,768.34 85.320 12,864.04 86.120 12,959.79 87.240 13.054.22 87.360 13,116.97 87.790 13,188.00 87.790 Well MPU M-20 MPU M-20 Actual IRKS @ 59.13usft (Doyon 14) MPU M-20 Actual RKB @ 59.13usft (Doyon 14) True Minimum Curvature NORTH US + CANADA Checked By Mitch Laird �_._„�..,..- Approved By: mlchaefcalkim2@ha81bu = 6/27/19 rton,com Date: 6272019 12:13:07PM Page 6 COMPASS 5000.15 Build 91 Map Map vertical Azi WD TVDSS -NIS +E/ -W Northing Easting DLS Section (I (usft) (usft) (usft) (usft) (ft) (ft) V1100') (ft) Survey Tool Name 185.60 3,639.87 3,580.74 -6,725.59 796.51 6,021,168.35 534,670.69 3.20 6,665.47 2_MWD+IFR2+MS+Sag(2) 185.99 3,636.51 3,577.38 -6,821.86 786.74 6,021,072.04 534,661.35 1.83 6,762.15 2_MWD+IFR2+MS+Sag(2) 187.99 3,631.04 3,571.91 -6,915.56 77525 6,020,978.31 534,650.30 2.33 6,856.37 2_MWD+IFR2+MS+Sag(2) 188.26 3,625.90 3,566.77 -7,010.21 761.74 6,020,883.60 534,637.21 1.52 6,951.67 2_MWD+IFR2+MS+Sag(2) 183+64 3,623.20 3,564.07 -7,105.25 751.83 6,020,788.52 534,627+74 5.07 7,047.13 2_MWD+IFR2+MS+Sag(2) 183.06 3,622.41 3,563.28 -7,198.76 746.36 6,020,695.00 534,622+70 1.05 7,140.80 2_MWD+IFR2+MS+Sag(2) 181.58 3,624.97 3,565.84 -7,294.67 742.47 6,020,599.08 534,619.25 3.69 7,236.77 2_MWD+IFR2+MS+Sag(2) 181.86 3,631.95 3,572.82 -7,38975 739.62 6,020,504A0 534,616.82 2.23 7,331.85 2_MWD+IFR2+MS+Sag(2) 182.21 3,639.55 3,58942 -7,484.21 736.26 6,020,409.54 534,613.90 1.43 7,426.34 2_MWD+IFR2+MS+Sag(2) 181.42 3,646.74 3,587.61 -7,579.53 733.24 6,020,314.21 534,611.31 1.14 7,521.67 2_MWD+IFR2+MS+Sag(2) 181.35 3,664.48 3,595.35 -7,673.93 730.96 6,020,219.82 534,609.46 0.07 7,616.03 2_MWD+IFR2+MS+Sag(2) 181.50 3,661.62 3,602.49 -7,769.33 728.59 6,020,124.41 534,607.52 0.85 7,711.40 2_MWD+IFR2+MS+Sag(2) 182.90 3,667.17 3,608.04 -7,864.84 724.92 6,020,028.89 534,604.28 1.87 7,806.97 2_MWD+IFR2+MS+Sag(2) 184.47 3,67162 3,612.49 -7,958.97 718.85 6,019,934.75 534,598.65 1.67 7,901.29 2_MWD+IFR2+MS+Sag(2) 165.75 3,674.27 3,615.14 -8,021.41 713.27 6,019,872.29 534,593.35 2.15 7,963.95 2_MWD+IFR2+MS+Sag(2) 185.75 3,677.01 3,617.88 -8,092.03 706.16 6,019,801.84 534,586.56 0.00 8,034.87 PROJECTED IOTD Checked By Mitch Laird �_._„�..,..- Approved By: mlchaefcalkim2@ha81bu = 6/27/19 rton,com Date: 6272019 12:13:07PM Page 6 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-20PB2 500292363671 Sperry Drilling Definitive Survey Report 27 June, 2019 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Coordinate Reference: Well MPU M-20 Project: Milne Point TVD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Site: M Pt Moose Pad MD Reference: MPU M-20 Actual IRKS @ 59.13usft (Doyon 14) Well: MPU M-20 North Reference: True Wellbore: MPU M-20PB2 Survey Calculation Method: Minimum Curvature Design: MPU M-20PB2 Database: NORTH US+CANADA 'rojeR Milne Point, ACT, MILNE POINT Aap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level ieo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Aap Zone: Alaska Zone 04 Using geodetic scale factor Nell MPU M-20 From To Nell Position +N/ -S 0.00 usft Northing: 6,027,889.58 usft Latitude: 70° 29' 14.001 1• 5,141.35 MPU M-20 MWD+IFR2+MS+Sag (1) (MP +E/ -W 0.00 usft Easting: 533,843.66 usft Longitude: 149° 43'24.168 N aosition Uncertainty 12,170.00 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 24.90 usft Wellbore MPU M-20PB2 Magnetics Model Name Sample Date BGGM2018 6'25/2019 Design Audit Notes: Version: Vertical Section: MPU M-20PB2 1.0 Phase: Depth From (TVD) (usft) 3423 Declination (I ACTUAL -NIS (usft) 0.00 Dip Angle 16.58 Tie On Depth: +FJ -W (usft) 0.00 Field Strength (nT) 80.96 57,422.22002738 12,102.42 Direction (°) 175.69 Survey Program Date 6/26/2019 From To lust[) (usft) Survey (Wellbore) Tool Name Description Survey Date 226.36 5,141.35 MPU M-20 MWD+IFR2+MS+Sag (1) (MP 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis+sag 06/10/2019 5,207.40 12,102.42 MPU M-20 MWD+IFR2+MS+Sag (2) (MP 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec& multi -station analysis+sag O6/17/2019 12,170.00 13,857.99 M-20PB2 MWD+IFR2+MS+sagMPU M 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sag 06/25/2019 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/S +E/ -W Northing Easting DLS Section (usft) (°) (1 (usft) (usft) (usft) (usft) (ft) (ft) (9100) (ft) Survey Tool Name 3423 0.000 0.00 34.23 -24.90 0.00 0.00 6,027,889.58 533,843.66 0.00 0.00 UNDEFINED 226.86 0.120 173.41 226.86 167.73 -0.20 0.02 6,027,889.38 533,843.68 0.06 0.20 2_MWD+IFR2+MS+Sa9(1) 318.35 0.040 180.11 318.35 259.22 -0.33 0.03 6,027,889.25 533,843.70 0.09 0.33 2_MWD+IFR2+MS+S8g(1) 409.37 0.940 27.40 409.37 350.24 0.30 0.38 6,027,889.89 533,844.04 1.07 -0.27 2_MWD+IFR2+MS+Sag(1) 504.54 2.670 25.58 504.48 445.35 3.00 1.69 6,027,892.58 533,845.34 1.82 -2.86 2 MWD+IFR2+MS+Sag(1) 595.67 5.430 13.51 595.38 536.25 9.10 3.62 6,027,898.70 533,847.24 3.15 -8.81 2_MWD+IFR2+MS+Sag(1) 687.92 8.220 16.74 686.97 627.84 19.67 6.54 6,027,909.27 533,850.11 3.05 -19.12 2 MWD+IFR2+MS+Sag(1) 784.20 11.700 21.45 781.78 722.65 35.35 12.09 6,027,924.98 533,855.59 3.71 -34.34 2_MWD+IFR2+MS+Sag(1) 879.05 15.670 24+68 873.92 814.79 55.95 20.96 6,027,945.62 533,864.36 4.26 -54.22 2_MWD+IFR2+MS+Ssg(1) 974.02 20.120 25.92 964.28 905.15 82.31 33.46 6,027,972.03 533,876.74 4.70 -79.56 2_MWD+IFR2+MS+Sag(1) 1,069.13 25640. 26.48 1,051.87 992.74 115.46 49.80 6,028,005.26 533,892.93 5.81 -111.40 2_MWD+IFR2+MS+Sag(1) 1,164.14 31.600 23.70 1,135.24 1,076.11 156.69 68.99 6,028,046.57 533,911.93 6.43 -151.07 2_MWD+IFR2+MS+Sag(1) 6272019 2:46:13PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-20 Project: Milne Point TVD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Site: M Pt Moose Pad MD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Well: MPU M-20 North Reference: True Wellbore: MPU M -20P82 Survey Calculation Method: Minimum Curvature Design: MPU M-20PB2 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100-) (ft) Survey Tool Name 1,257.57 37.820 20.61 1,212.01 1,152.88 205.97 88.93 6,028,095.93 533,931.65 6.92 -19871 2_MWD+IFR2+MS+Sag(1) 1,354.18 42.980 19.04 1,285.56 1,226.43 264.87 110.12 6,028,154.92 533,952.56 5.44 -255.85 2_MWD+IFR2+MS+Sag(1) 1,448.95 43.200 18.81 1,354.77 1,295.64 326.11 131.12 6,028,216.25 533,973.28 0.29 -315.34 2_MWD+IFR2+MS+Sag(1) 1,543.96 45.190 20.62 1,422.69 1,363.76 388.44 153.47 6,028,278.68 533,995.35 2.48 -375.82 2_MWD+IFR2+MS+Sag(1) 1,637.81 48.580 25.11 1,487.04 1,42291 451.50 180.14 6,028,341.85 534,021.73 5.02 436,70 2_MWD+IFR2+MS+Sag(1) 1,733.67 51.690 26.73 1,548.48 1,489.35 51265 212.32 6,028,408.14 534,05360 3.49 500.25 2_MWD+IFR2+MS+Sag(1) 1,828.90 54.780 27.24 1,605.47 1,546.34 585.62 246.94 6,028,47626 534,087.91 3.27 -565.43 2_MWD+IFR2+MS+Sag(1) 1,922.92 52.150 27.70 1,661.44 1,602.31 652.65 281.78 6,028,543.44 534,122.44 2.82 -629.65 2_MWD+IFR2+MS+Sag(1) 2,018.43 49.550 27.48 1,721.73 1,662.60 718.29 31608 6,028 609.23 534,156.44 2.73 -692.53 2_MWD+IFR2+MS+Sag(1) 2,113.43 49.740 27.95 1,783.25 1,724.12 782.37 349.75 6,028,673.46 534,189.81 0.43 -753.91 2_MWD+IFR2+MS+Sag(1) 2,208.29 47,510 30.27 1,845.95 1,786.62 844.57 384.35 6,028,735.80 534,224.13 2.98 -813.32 2_MWD+IFR2+MS+Sag(1) 2,303.86 45.600 32.61 1,911.67 1,852.54 903.77 420.52 6,028,795.16 534,260.02 2.67 -869.64 2_MWD+IFR2+MS+Sag(1) 2,399.04 42.930 35.10 1,979.83 1,920.70 958.94 45749 6,028,850.50 534,296.74 3.35 -921.89 2_MWD+IFR2+MS+Sag(1) 2,493.72 39.770 40.40 2,050.92 1,991.79 1,008.41 495.68 6,028,900.14 534,334.70 4.98 -96835 2_MWD+IFR2+MS+Sag(1) 2,588.99 35.900 43.97 2,126.15 2,067.02 1,051.74 534.84 6,028,943.64 534,373.66 4.67 -1,008.62 2_MWD+IFR2+MS+Sag(1) 2,684.23 31.870 4962 2,205.22 2,146.09 1,088.35 573.23 6,028,98042 534,411.88 5.16 -1,042.24 2_MWD+IFR2+MS+Sag(1) 2,779.54 27.440 55.07 2,288.04 2,228.91 1,117.45 610.26 6,029,009.68 534,448.77 5.60 -1,068.47 2_MWD+IFR2+MS+Sag(1) 2,874.36 26.620 64.97 2,372.55 2,31342 1,138.95 647.44 6,029,031.36 534,485.85 4.82 -1,087.13 2_MWD+IFR2+MS+Sag(1) 2,969.81 24.890 73.25 2,458.54 2,39941 1,153.80 686,07 6,029,046.37 534,524.40 4.18 -1,099.03 2_MWD+IFR2+MS+Seg(1) 3,065.47 23.970 85.80 2,54569 2,486,56 1,161.03 724.75 6,029,053.78 534,563.05 5.50 -1,103.34 2_MWD+IFR2+MS+Sag(1) 3,160.49 25.110 96.01 2,632.17 2,573.04 1,160.33 764.07 6,029,053.26 534,602.36 4.62 -1,099.69 2_MWD+IFR2+MS+Sag(1) 3,255.26 25.760 106.26 2,717.81 2,658.68 1,152.45 803.86 6,029,045.56 534,642.19 4.69 -1,068.84 2_MWD+IFR2+MS+Sag(1) 3,350.08 26.320 116.22 2,803.03 2,743.90 1,137.39 842.51 6,029,030.68 534,680.91 4.65 -1,070.92 2_MWD+IFR2+MS+Sag(1) 3,445.21 26.360 123.62 2,888.31 2,829.18 1,116.37 879.03 6,029,009.83 534,717.51 3.45 -1,047.23 2_MWD+IFR2+MS+Sag(1) 3,540.46 26.990 130.17 2,973.44 2,914.31 1,090.72 913.16 6,028,984.33 534,751.76 3.16 -1,019.08 2_MWD+IFR2+MS+Sag(1) 3,635.30 29270 135.86 3,057.08 2,997.95 1,060.19 945.76 6,028,95396 534,784.50 3.71 -986.19 2_MWD+IFR2+MS+Sag(1) 3,731.00 32.230 141.06 3,139.33 3,060.20 1,023.53 978.11 6,028,917.45 534,817.00 4.16 -947.21 2_MWD+IFR2+MS+Sag(1) 3,826.07 33.920 144.65 3,219.00 3,159.87 982.17 1,00939 6,028,876.24 534,848.47 2.72 -903.62 2_MWD+IFR2+MS+Sag(1) 3,921.33 37.560 149.54 3,296.33 3,237.20 935.44 1,039.51 6,028,829.65 534,878.80 4.85 -854.75 2_MWD+IFR2+MS+Sag(1) 4,016.57 40.150 154.66 3,370.51 3,311.38 882.65 1,067.38 6,028,776.99 534,906.90 4.33 -800.02 2_MWD+IFR2+MS+Sag(1) 4,111.57 44.580 159.39 3,440.70 3,381.57 823.71 1,092.24 6,028,718.17 534,932.03 5.74 -739.38 2_MWD+IFR2+MS+Sag(1) 4,207.07 50.360 16331 3,505.25 3,446.12 756.97 1,114.38 6,028,651.54 534,954.47 6.91 -671.17 2_MWD+IFR2+MS+Sag(1) 4,303.20 52.780 166+59 3,565.00 3,505.87 684.20 1,133.64 6,028,578.86 534,974.06 3.44 -597.15 2_MWD+IFR2+MS+Sag(1) 4,398.14 55.950 169.05 3,620.29 3,561.16 608.81 1,149.88 6,028.503.55 534,990.64 3.95 52876 2_MWD+IFR2+MS+Sag(1) 4,493.34 58.410 171.76 3,671.91 3,61278 529.91 1,163.19 6,028,424.73 535,004.31 352 44108 2_MWD+IFR2+MS+Sag(1) 4,588.28 63.280 173.94 3,718.15 3,659.02 447.67 1,173.47 6,028,342.54 535,014.96 5.51 358.30 2_MWD+IFR2+MS+Sag(1) 4,683.42 66.020 175.23 3,758.89 3,699.76 362.09 1,181.57 6,028,257.00 535,023.45 3.13 -272.35 2_MWD+IFR2+MS+Sag(1) 4,778.21 68.160 174.49 3,795.78 3.736.65 275.13 1,189.40 6,028,170.09 535,031.67 2.37 -185.05 2_MWD+IFR2+MS+Sag(1) 4,873.33 72.640 177.44 3,827.69 3,768.56 185.78 1,195.67 6,028,060.78 535,038.35 5.54 -95.48 2_MWD+IFR2+MS+Sag(1) 4,969.00 76.930 179.20 3,852.79 3,793.66 93.53 1,198.36 6.027,988.55 535.041.46 4.82 -3.29 2_MWD+IFR2+MS+Sag(1) 6272019 2:46:13PM Page 3 COMPASS 5000.15 BUO 91 Halliburton Definitive Survey Report Company: Hilcom Alaska, LLC Local Co-ordinate Reference: Well MPU M-20 Project: Milne Point TVD Reference: MPU M-20 Actual IRKS @ 59.13usft (Doyon 14) Site: M Pt Moose Pad MD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Well; MPU M-20 North Reference: True Wellbore: MPU M-20PB2 Survey Calculation Method: Minimum Curvature Design: MPU M-20PB2 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc An TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) (1 (usft) (usft) (usft) (usft) (ft) (ft) ('/100') (ft) Survey Tool Name 5,062.54 83.500 181.62 3,868.69 3,809.56 1.41 1,197.68 6,027,896.44 535,041.20 7.47 88.52 2_MW13+1FR2+MS+Sag(1) 5,141.35 85.420 183.00 3,876.29 3,817.16 -76.97 1,194.52 6,027,818.06 535,038.40 3.00 166.43 2_MWD+IFR2+MS+Sag(1) 5,207.40 85.500 182.54 3,881.52 3,822.39 -142.73 1,191.33 6,027,752.28 535.035.51 0.70 231.78 2_MWD+IFR2.+MS+Sag(2) 5,247.66 85.810 184.14 3,884.57 3,825.44 -182.81 1,189.00 6,027,712.20 535,033.36 4.04 271.56 2_MWD+IFR2+MS+Sag(2) 5,343.18 88.290 185.22 3,889.49 3,830.36 -277.87 1,181.21 6,027,617.11 535,026.01 2.83 365.77 2_MWD+IFR2+MS+Sag(2) 5,439.39 88.960 184.85 3,891.80 3.83267 -373.68 1,172.77 6,027,521.27 535,018.00 0.80 460.68 2_MWD+IFR2+MS+Sag(2) 5,535.29 88.840 183.93 3,893.64 3,834.51 469.28 1,165.43 6,027,425.65 535,011.10 0.97 555.46 2_MWD+IFR2+MS+Sag(2) 5,630.83 89.950 183.08 3,894.65 3,835.52 -564.64 1,159.59 6,027,330.28 535,005.69 1.46 650.11 2_MWD+IFR2+MS+Sag(2) 5,725.94 90.570 182.89 3,894.21 3,835.08 -659.62 1,154.64 6,027.235.29 535,001.17 0.68 744.45 2_MWD+IFR2+MS+Sag(2) 5,821.08 90.750 181.22 3,893.12 3,833.99 -754.69 1,151.23 6,027,140.21 534,998.20 1.77 838.99 2_MWD+IFR2+MS+Sag(2) 5,916.50 91.250 181.59 3,891.45 3,832.32 -850.06 1,148.6.9 6,027,044.84 534,996.29 0.65 933.92 2_MWD+IFR2+MS+Sag(2) 6,011.54 91.990 182.61 3,888.77 3,829.64 -945.00 1,145.41 6,026,949.90 534,993.24 1.33 1,028.33 2_MWD+IFR2+MS+Sag(2) 6,106.81 92.230 184.84 3,885.26 3,826.13 -1,040.00 1,139.22 6,026,854.88 534,987.49 2.35 1,122.59 2_MWD+IFR2+MS+Sag(2) 6,202.19 91.740 185.21 3,881.95 3,822.82 -1,134.95 1,130.87 6,026,759,90 534,979.57 0.64 1.216,66 2_MWD+IFR2+MS+Sag(2) 6,297,27 91.990 184.02 3,878.86 3,819.73 -1,229.67 1,123.23 6,026,665.15 534,972.36 1.28 1,310.53 2_MW13+1FR2+MS+Sag(2) 6,392.10 93.780 183.50 3,874.09 3,814.96 -1,324.17 1,117.02 6,026,570.63 534,966.58 1.97 1,404.30 2_MWD+IFR2+MS+Sag(2) 6,487.53 93.660 183.81 3,867.90 3,808.77 -1,419.21 1,110.94 6,026,475.58 534,960.94 0.35 1,498.61 2_MWD+IFR2+MS+Sag(2) 6,582.75 92.850 183.68 3,862.49 3,803.36 -1,514.07 1,104.74 6,026,380.70 534,955.16 0.86 1,592.74 2_MWD+IFR2+MS+Sag(2) 6,678.66 91.490 183.95 3,858.86 3,79973 -1,609.70 1,098.36 6,026,285.06 534,949.22 1.45 1,687.62 2_MWD+IFR2+MS+Sag(2) 6,773.83 91.310 184.65 3,856.53 3,797.40 -1)0457 1,091.23 6,026,190.16 534,942.52 0.76 1,781.69 2_MWD+IFR2+MS+Sag(2) 6,868.22 89.890 185.11 3,855.54 3,79641 -1,798.61 1,083.20 6,026,096.09 534,934.92 1.58 1,874.86 2_MWD+IFR2+MS+Sag(2) 6,963.41 89.330 183.59 3,856.19 3.797.06 -1,893.52 1,075.98 6.026,001.16 534,928.14 1.70 1,968.96 2_MWD+1FR2+MS+Sag(2) 7,058.32 90.140 187.16 3,856.63 3,797.50 -1,988.00 1,067.09 6,025,906.65 534,919.68 3.86 2,062.50 2_MWD+IFR2+MS+Sag(2) 7,153.40 88.470 188.39 3,857.78 3,798.65 -2,082.19 1,054.23 6,025,812.41 534,90].25 2.18 2,155.47 2_MWD+IFR2+MS+Sag(2) 7,248.12 89.090 187.72 3,859.80 3,800.67 -2,175.95 1,040.96 6,025,718.60 534,894.40 0.96 2,247.97 2_MWD+IFR2+MS+Sag(2) 7,343.86 90.140 187.12 3,860.44 3,801.31 -2,270.89 1,028.59 6,025,623.62 534,882.47 1.26 2,341.71 2_MWD+IFR2+MS+Sag(2) 7,438.72 92.730 184.35 3,858.07 3,798.94 -2,365.23 1,019.12 6,025,52925 534,873.43 4.00 2,435.07 2_MWD+IFR2+MS+Sag(2) 7,533.64 94.040 183.12 3,852.46 3,793.33 -2,459.78 1,012.95 6,025,434.68 534,867.69 1.89 2,528.89 2_MWD+IFR2+MS+Sag(2) 7,628.53 92.360 180.65 3,847.17 3,788.04 -2,554.46 1,009.83 6,025,340.00 534,865.00 3.14 2,623.07 2_MWD+IFR2+MS+Sag(2) 7,724.71 92.600 179.26 3,843.00 3,783.87 -2,650,54 1,009.91 6,025,243.92 534,865.52 1.47 2,718.89 2_MWD+1FR2+MS+Sag(2) 7,820.42 91.990 179.51 3,839.17 3,780.04 -2,746.17 1,010.93 6,025,148.31 534,866.98 0.69 2,814.32 2_MWD+IFR2+MS+Sag(2) 7,915.29 92.790 180.67 3,635.22 3,776.09 -2,840.96 1,010.78 6,025,053.53 534,867.26 1.48 2,908.83 2_MWD+IFR2+MS+Sag(2) 8,010.63 91.370 178.96 3,831.76 3,77263 -2,936.23 1,011.09 6,024,958.27 534,868.00 2.33 3,003.85 2_MWD+IFR2+MS+Sag(2) 8,105.75 92.670 179.22 3,628.40 3,76927 3,031.27 1,012.60 6,024,863.24 534,869.94 1.39 3,098.74 2_MWD+IFR2+MS+Sag(2) 8,200.72 93.780 179.36 3,823.06 3,763.93 -3,126.08 1,013.78 6,024,768.45 534,871.55 1.18 3,193.38 2_MW0+1FR2+MS+Sag(2) 8,296.58 94.770 181.17 3,815.91 3,756.78 .3,221.67 1,01334 6,024,672.87 534,871.54 2.15 3,288.66 2_MWD+IFR2+MS+Sag(2) 8,391.84 95.960 184.68 3,807.00 3,747.87 -3,316.37 1,008.50 6,024,578.16 534,867.14 3.88 3,382.73 2_MWD+IFR2+MS+Sag(2) 8,487.18 94.340 186.66 3,79845 3,739.32 -3,410.86 999.12 6,024,483.64 534,858.19 2.68 3,476.24 2_MWD+IFR2+MS+Sag(2) 8,582.79 93.780 185.13 3,791.68 3,732.55 -3,505.72 989.32 6.024.388.75 534,848.83 1.70 3,570.10 2_MW0+IFR2+MS+Sag(2) 8,678.14 94.650 184.01 3,784.67 3,72554 -3,600.51 981.75 6,024,293.93 534,841.68 1.48 3,664.05 2_MWD+IFR2+MS+Sag(2) 6/27/2019 2:46:13PM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-orc inate Reference: Well MPU M-20 Project: Milne Point TVD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Site: M Pt Moose Pad MD Reference: MPU M-20 Actual RKB @ 59.13usft (Doyon 14) Well: MPU M-20 North Reference: True Wellbore: MPU M-20PB2 Survey Calculation Method: Minimum Curvature Design: MPU M-20PB2 Database: NORTH US+CANADA Survey 67272019 2:46:13PM Page 5 COMPASS 5000.15 Build 91 Map Map Vertical MD Inc Aal TVD TVDSS +N/S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) leak) (usft) (usft) (ft) (ft) ('1100') (ft) Survey Tool Name 8,773.23 94.270 183.83 3,777.27 3,718.14 -3,69509 975.26 6,024,199.33 534,835.63 0.44 3,757.88 2_MWD+IFR2+MS+Sag(2) 8,868.06 96.320 185.01 3,768.52 3,709.39 -3,789.22 967.99 6,024,105.17 534,828.79 2.49 3,851.21 2_MWD+IFR2+MS+Sag(2) 8,963.16 95.140 183.09 3,759.03 3,699.90 -3,883.61 961.31 6,024,010.77 534,822.54 2.36 3,944.82 2_MWD+IFR2+MS+Sag(2) 9,058.33 93.960 183.31 3,751.48 3,692.35 -3,978.33 956.01 6,023,916.04 534,817.67 1.26 4,038.88 2_MWD+IFR2+MS+Sag(2) 9,153.95 93.530 182.39 3,745.23 3,686.10 4,073.62 951.27 6,023,820.73 534,813.36 1.06 4133.55 2_MWD+IFR2+MS+Sag(2) 9,247.55 91.860 179.33 3,740.83 3,681.70 3,167.10 949.87 6,023,727.26 534812.39 3,72 4,22665 2_MWDHFR2+MS+Sag(2) 9,345.03 91.860 179.13 3,737.67 3,678.54 4,264.51 951.18 6,023,629.86 534,814.14 0.21 4,323.89 2_MWD+IFR2+MS+Sag(2) 9,440.45 92.670 181.79 3,733.89 3,674.76 4,359.85 950.41 6,023,534.53 534,813.81 2.91 4,418.90 2_MWD+IFR2+MS+Sag(2) 9,535.50 94.410 184.51 3,728.02 3,668.89 4,454.56 945.20 6,023,439.81 534,809.03 3.39 4,512.95 2_MWD+IFR2+MS+Sag(2) 9,630.96 93.470 186.38 3,721.46 3,662.33 3,549.36 936.16 6,023,344.98 534,800.42 2.19 4,606.81 2_MWD+IFR2+MS+Sag (2) 9,725.43 95.890 186.95 3,713.76 3,654.63 4,64287 925.24 6,023,251.42 534,789.92 2.63 4,699.23 2_MWD+IFR2+MS+Sag(2) 9,821.06 96.380 184.56 3,703.54 3,644.41 4,737.47 915.70 6,023,156.80 534780.82 2.54 4,792.85 2_MWD+IFR2+MS+Sag(2) 9,916.16 93.530 182.73 3,695.32 3,636.19 4,832.01 909.68 6,023,062.24 534,775.23 3.56 4,886.67 2_MWD+IFR2+MS+Sag(2) 10,011.42 91.740 182.18 3,690.94 3,631.81 3,927.07 905.61 6,022,967.16 534,771.59 1.97 4,981.16 2_MWD+IFR2+MS+Sag(2) 10,106.36 90.440 182.40 3,689.14 3,630.01 -5,021.92 901.82 6,022,872.31 534,768.23 1.39 5,075.45 2_MWD+IFR2+MS+Sag(2) 10,201.28 91.370 182.30 3,687.64 3,628.51 -5,116.75 897.92 6,022,777.48 534,764.77 0.99 5.169.72 2_MWD+IFR2+MS+Sag(2) 10,252.37 91.990 182.61 3,686.14 3,627.01 -5,16777 895.74 6,022,726.45 534,762.81 1.36 5,220.43 2_MWD+IFR2+MS+Sag(2) 10,296.63 91.430 182.18 3,684.82 3,625.69 -5,211.97 893.89 6,022,682.25 534761.17 1.59 5,264.37 2_MWD+IFR2+MS+Sag(2) 10,348.79 90.560 182.75 3,683.91 3,624.78 -5,264.07 891.65 6,022,630.14 534,759.16 1.99 5,316.16 2_MWD+IFR2+MS+Sag(2) 10,391.80 91.120 182.08 3,683.28 3,624.15 -5,307.04 88983 6,022,587.17 534,757.54 2.03 5,358.87 2_MWD+IFR2+MS+Sag(2) 10,444.32 89.700 182.72 3,682.91 3,623.78 -5,359.51 887.63 6,022,534.69 534,755.58 2.97 5,411.03 2_MWD+IFR2+MS+Sag(2) 10,485.57 89.950 184.32 3,683.03 3,623.90 -5,400.68 885.10 6,022,493.52 534,753.24 3.93 5,451.89 2_MWD+IFR2+MS+Sag(2) 10,539.18 89.950 185.13 3,683.08 3,623.95 -5,454.11 880.69 6,022,440.07 534,749.07 1.51 5,504.64 2_MWD+IFR2+MS+Sag(2) 10,581.20 89.770 185.36 3,683.18 3,624.05 -5,495.95 876.84 6,022,398.22 534745.42 0.70 5,546.27 2_MWD+IFR2+MS+Sag(2) 10,632.61 90.140 185.32 3,683.22 3,624.09 -5,547.14 872.06 6,022,347.01 534,740.87 0.72 5,596.96 2_MWD+IFR2+MS+Sag(2) 10,675.91 89.830 185.77 3,683.23 3,624.10 -5,590.24 867.88 6,022,303.90 534,736.88 1.26 5,639.62 2_1hWD+IFR2+MS+Sag(2) 10,727.96 89.830 185.45 3,683.39 3,624.26 -5,642.04 862.79 6,022,252.09 534,732.03 0.61 5,690.89 2_MWD+IFR2+MS+Sag(2) 10,771.07 89.330 184.95 3,683.70 3,624.57 -5,684.97 858.88 6,022,209.14 534,728.32 1.64 5,733.41 2_MWD+IFR2+MS+Sag(2) 10,823.95 89,270 184.61 3,684.35 3,625.22 -5,737.66 854.47 6,022,156.43 534,724.15 0.65 5,785.62 2_MWD+IFR2+MS+Sag(2) 10,865.55 89.210 184.22 3,684.90 3,625.77 -5,779.13 851.27 6,022,114.95 534721.14 0.95 5,826.73 2_MWD+IFR2+MS+Sag(2) 10.918.25 89.080 183.45 3,685.69 3,626.56 -5,831.71 847.75 6,022,062.37 534,717.85 1.48 5,878.90 2_MWD+IFR2+MS+Sag(2) 10,961.33 90.270 183.49 3,685.93 3,626.80 -5,874.71 84514 6,022,019.36 534,715.44 2.76 5,921.58 2_MWD+1FR2+MS+Sag(2) 11,012.22 91.320 184.51 3,685.23 3,626.10 -5,925.47 841.59 6,021,968.59 534,712.12 2.88 5,971.93 2_MWD+IFR2+MS+Sag(2) 11,055.97 93.170 184.06 3,683.51 3,624.38 5,969.06 838.33 6,021,924.99 534,709.05 4.35 6,015.15 2_MWD+IFR2+MS+Sag (2) 11,150.65 95.780 183.28 3,676.13 3,617.00 -6,083.25 832.28 6,021,830.78 534,703.44 2.88 6,108.62 2_MWD+IFR2+MS+Sag(2) 11,246.03 94.270 183.86 3,667.77 3,60864 -6,158.07 826.37 6,021,735.94 534,697.96 1.70 6,202.74 2_MWD+IFR2+MS+Sag(2) 11,341.24 93.840 184.95 3,661.04 3,601.91 -6,252.76 819.07 6,021,641.23 534,691.09 1.23 6,296.61 2_MWD+IFR2+MS+Sag(2) 11,436.48 92.790 183.66 3,655.53 3,596.40 -6,347.57 811.93 6,021,546.39 534,684.39 1.74 6,390.62 2_MWD+IFR2+MS+Sag(2) 11,530.64 93.290 181.19 3,650.54 3,591.41 -6,441.51 80]96 6,021,452.45 534,680.84 2.67 6,483.99 2 MWD+IFR2+MS+Sag(2) 11,626.25 93.040 180.96 3,645.26 3,586.13 -6,536.96 806.17 6,021,357.01 534,679.48 0.36 6,57983 2_MWD+IFR2+MS+Sag(2) 67272019 2:46:13PM Page 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Coordinate Reference: Well MPU M-20 Project: Milne Point TVD Reference: MPU M-20 Actual IRKS @ 59.13usft (Doyon 14) Site: M Pt Moose Pad MD Reference: MPU M-20 Actual IRKS @ 59.13usft (Doyon 14) Well: MPU M-20 North Reference: True Wellbore: MPU M-20PB2 Survey Calculation Method: Minimum Curvature Design: MPU M-20PB2 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NlS +FJ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 11,721.58 91.180 182.60 3,641]5 3,582.62 -6,632.17 80321 6,021,261.79 534,676.96 2.60 6,67335 2_MWD+IFR2+MS+Sag(2) 11,815.27 91.120 185.60 3,639.87 3,580.74 £,725.59 796.51 6,021,168.35 534,670.69 3.20 6,76641 2_MWD+IFR2+MS+Sag(2) 11,912.10 92.850 185.99 3,636.51 3,577.38 -6,821.86 786.74 6,021,072.04 534,661.35 1.83 6,861.68 2_MWD+IFR2+MS+Sag(2) 12,00666 93790 187.99 3,631.04 3,571.91 -6,915.56 775.25 6,020,978.31 534,650.30 2.33 6,954.24 2_MWD+IFR2+MS+Sag(2) 12,102.42 92.360 188.26 3,625.90 3,566.77 -7,010.21 761.74 6,020,883.60 534,637.21 1.52 7,047.62 2_MWD+IFR2+MS+Sag(2) 12,170.00 91.320 184.99 3,623.73 3.564.60 -7,077.30 753.95 6,020,816.48 534,629.73 5.08 7,113.93 2_MWD+IFR2+MS+Sag(3) 12,196.66 89.390 185.25 3,623.56 3,564.43 -7,103.85 751.57 6,020,789.92 534,627.47 7.30 7,140.23 2_MWD+IFR2+MS+Sag(3) 12,292.76 85.430 184.49 3,627.91 3,568.78 -7,199.49 743.42 6.020.694.26 534.619.76 4.20 7,234.98 2_MWD+IFR2+MS+Sag(3) 12,387.25 84.080 185.01 3,636.54 3,577.41 -7,293.26 735.63 6,020,600.47 534,612.39 1.53 7,327.90 2_MWD+IFR2+MS+Sag(3) 12,482.95 84.690 184.68 3,645.91 3,58678 -7,388.15 727.58 6,020,505.54 534,604.78 0.72 7,421.93 2_MWD+IFR2+MS+Sag(3) 12,577.16 86.500 184.71 3,653.14 3,594.01 -7,48137 719.89 6,020,411.90 534,597.52 1.92 7,514.70 2_MWD+IFR2+MS+Sag(3) 12,672.58 88.840 184.08 3,657.02 3,597.89 -7,576.82 712.59 6,020,316.83 534,590.65 2.54 7,608.94 2_MWD+IFR2+MS+Sag(3) 12,767.59 90.390 183.83 3,657.66 3,598.53 -7,671.60 706.04 6,020,222.03 534,584.53 1.65 7,702.96 2_MWD+IFR2+MS+Sag(3) 12,863.63 90.140 182.53 3,657.22 3,598.09 -7,767.49 700.71 6,020,126.13 534,579.64 1.38 7,798.17 2_MWD+IFR2+MS+Sag(3) 12,958.76 91.680 182.24 3,655.71 3,596.58 -7,862.52 696.75 6,020,031.09 534,576.11 1.65 7,892.64 2_MWD+IFR2+MS+Sag(3) 13,053.67 92.360 183.21 3,652.36 3,593.23 -7,957.26 692.24 6,019,936.33 534,572.03 1.25 7,986.78 2_MWD+IFR2+MS+Sag(3) 13,149.35 90.440 182.22 3,650+02 3,590.89 -8,052.80 687.71 6,019,84039 534,56].94 2.26 8,081.71 2_MWD+IFR2+MS+Sag(3) 13,244.47 90.880 179.62 3,648.93 3,589.80 -8,14790 686.18 6,019,745.70 534,566.85 2.77 8,17642 2_MWD+IFR2+10S+Seg(3) 13,339.56 91.810 179.99 3,646.69 3,587.56 -8,242.96 686.51 6,019,650.65 534.567.60 1.05 8,271.23 2_MWD+IFR2+MS+Sag(3) 13,435.36 92.800 180.30 3,642.84 3,583.71 -8,338.68 686.27 6,019,554.93 534,567.79 1.08 8,366.67 2_MWO+IFR2+MS+Sag(3) 13,530.15 92.230 180.45 3,638.68 3,579.55 -8,433.37 685.65 6,019,460.25 534,567.61 0.62 8,461.05 2_MWD+IFR2+MS+Sag(3) 13,625.67 91.620 181.87 3,635.47 3,576.34 -8,528.82 683.71 6,019,364.80 534,566.11 1.62 8,556.08 2_MWD+IFR2+MS+Sag(3) 13,720.96 92.790 184.42 3,631.81 3,572.68 -8,623.88 678.49 6,019,269.72 534,561.32 2.94 8,650.48 2_MWD+IFR2+MS+Sag(3) 13,814.02 93.530 183.43 3,62668 3,567.55 -6,716.58 672.13 6,019,177.01 534,555.38 1.33 8,742.44 2_MWD+IFR2+MS+Sag(3) 13,857.99 94.590 183.92 3,623.56 3,564.43 -8,760.35 669.32 6,019,133.23 534,552.77 2.65 8,785.88 2_MWD+IFR2+MS+Sag(3) 13,926.00 94,590 183.92 3,618.12 3,55899 -8,827.99 664.68 6,019,065.58 534,548.44 0.00 8,852.97 PROJECTED to TO Mitch Laird michael.calkins2@hallib w Checked By: --- Approved By: urton.com Date: 6/27/19 627/2019 2:46:13PM Page 6 COMPASS 5000.15 Build 91 Hllcorp Energy Company CASING & CEMENTING REPORT Lease 8 Well No, MP M-20 Date Run 16 ,1.19 County State Alaska Supv. D.Yessak l J. Vanderpool CASING RECORD cadre � TO 5,194.00 Shoe Depth: 5,187.00 PBTD: No, Jts. Delivered 145 No. Jts. Run 124 No, Jts. Returned 22 Fig. Delivered 5,800.31 Ftg. Run 5,011.33 Ftg. Returned 788.98 Length Measurements WAD Threats Fig, Cut A 18.25 Ftg. Balance RKB RKB to BHF RKBW CHF RKB to THF Cal; Al On Hook: 295 Type Float Collar Antelope No. His to Run: 29.5 Call Wt On Slips: 120000 Type of Shoe: Antelope Casing Crew: Doyon Rotate Csg X Yes No Recip Deg X Yes No Ft. Min. 9A PPG Fluid Description: Spud Mud liner hanger Info(Maou$ otle0: finer top Packerl: _Yes X No Liner hanger test pressure: Floats Held X Yes No. Centralizer Placement 03 each 9-518" x 12-10 Fxpmcdo-liter centralizers ran. 2 each with 4 stop rings on joint #1. 1 free readmit on joint #2. 1 each on joint #3 84 with 4 stop rings. Shoe@ 5187 FC@ 5,106.26 Casing (Or Liner) Detail Preflush (Spacer) Setting Depths its. Component Size Wt Gretle THD Make Length Bottom Top 1 Shoe 103/4 50.0 0 TXP BTC -SR Antelope 1.57 5,187.00 5,185.43 2 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 79.17 5,185.43 5,106.26 1 Float Collar 103/4 50.0 0 TXP BTC -SR Antelope 1.35 5,106.26 5,104.91 1 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 39.00 5,104.91 5,065.91 1 Baffle Adapter 103/4 50.0 0 TXP BTC -SR HES 1.53 5,065.91 5,064.38 67 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 2,657.02 5,064.38 2,407.36 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 18.46 2,407.36 2,388.90 1 ES Cementer 11 103/4 0 TXP BTC -SR HES 2.84 2,38890 2,386.06 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 18.85 2,386.06 2,367.21 57 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 2,311.65 2,367.21 55.56 1 Casing Cut Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 23.14 55.56 32.42 $6.2 Mixing / Pumping Rata (bpm): 3.5 o Post Flesh (Spacer) Type: Density (ppg) Cal; Al On Hook: 295 Type Float Collar Antelope No. His to Run: 29.5 Call Wt On Slips: 120000 Type of Shoe: Antelope Casing Crew: Doyon Rotate Csg X Yes No Recip Deg X Yes No Ft. Min. 9A PPG Fluid Description: Spud Mud liner hanger Info(Maou$ otle0: finer top Packerl: _Yes X No Liner hanger test pressure: Floats Held X Yes No. Centralizer Placement 03 each 9-518" x 12-10 Fxpmcdo-liter centralizers ran. 2 each with 4 stop rings on joint #1. 1 free readmit on joint #2. 1 each on joint #3 84 with 4 stop rings. Shoe@ 5187 FC@ 5,106.26 Top of Liner Preflush (Spacer) Type: Tuned Spacer Density (ppg) 10 Volume pumped (BBLs) 60 Lead Slurry Type: Lead Cement Sacks: 350 Yield 2.35 Density (ppg) 12 Volume pumped(BBIs) WA Miring/ Pumping Rate (bpm): 4 Tail Slurry w Type: Tail Cement Sacks: 400 Yield: 1.16 Density (ppg) 15.8 Volume pumped (BBLs) 82.4 Mixing/ Pumping Rate (bpm): 4 F Post Flesh (Spacer) m Type: Density (p (port) Rate(bpm): Volume: LL Displacement: Type: Spud Mud Density (ppg) 9.4 Rate (bpm): 6 Volume (actual I calculated): 383.86/383.1 FCP(psi): 680 Pump used for lisp Rig Bump Plug? X Yes No Bump press 13� Casing Related? X Yes _No Reciprocated? X Yes -No is Returns during job 100 Cement returns to surface? X Yes No Spacerrelums? X Yes -No Vol to Sud: 0 Cement In Place AL 15:25 Q 6I17Y2019 Estimated TOC: 2,388 Method Used To Determine TOC: Calculation/ Trace cement to surface Stage Collar@ 2388.06 Type ES Cementer Closure OK Y Preflush (Spacer) Type: Tuned Spacer Details(ppg) 10 Volume pumped(BBLs) 60 Lead Slurry Type: Permafrost L Sacks: 460 Yield: 4.41 Emery(ppg) 107 Volume pumped(BBLs) 380 Mixing/ Pumping Rate (bpm): 5 Tail Slurry Type: Premium Sacks: 270 Yield: 1.17 Density (ppg) 15.8 Volume pumped (BBLs) $6.2 Mixing / Pumping Rata (bpm): 3.5 o Post Flesh (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Spud Mud Density (ppg) 9.4 Rate (bpm): 6 Volume (actual I calculated). 179.81/180.`- FCP(psi): 400 Pump used for lisp: Rig Bump Plug? X Yes No Bump press 15', Casing Related? _Yes X No Reciprocated? _Yes X No is Returns during job 100 Cement returns to surface? X Yes No Spacerretums? Yes X No Vol to Surf: 237 Cement In Place At: 1:30 Date: w1won Estimated TOC: 32 Method Used To Determhe TOC: Returns to surface Post lob Calculations: Calculated Cunt Vol ® D% excess 314.15 Total Volume curt Pumped: 645 Curt returned to surface: 237 Ga Iodated cement left in welteds.. 408 OH volume Calculated : ] OH volume actual: 3]].22 Actual % Washout: 25 MPU M-20 OH Sidetrack Summary PTD: 219-083 / API: 50-029-23636-00-00 PBI PB2 TD 13,188' MD / 3,677' TVD 13,926' MD / 3,618' TVD KOP 12,170' MD 13,810' MD Date 6/24/2019 6/25/2019 PTD: 219-083 / API: 50-029-23636-00-00 DATE 07/18/2019 21 903 Debra Oudean Hilcorp Alaska, LLC 3 1 0 0 9 GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 F -mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Abby Bell Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 MPU M-20 + PB1 + PB2 PTD 219-083 CD 1: Geosteering Data MPU M-20 PI31 MD Final 7/19/201910:10AM Filefolder 6/29/2019 6:22 PKI LAS File RECEIVE® JUL 19 2019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Rilrnrp alnrLo. LL(: DATE 07/18/2019 219083 Debra Oudean Hilcorp Alaska, LLC 31010 GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Abby Bell Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 MPU M-20 + PB1 + PB2 PTD 219-083 CD 1: Geosteering Data 7/18.12G1g10:10AM File folder µ MPU M-20 PB1 LWD Final 612912019 6:22 RA LAS File JUL 19 2019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 DATE 07/18/2019 Uebra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Abby Bell Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 MPU M-20 + PB1 + PB2 PTD 219-083 CD 1: Geosteering Data MPU M-20 PBl LIAID Final 7/18,Q01910:10AM Filefolder 6W29./2019 6:22 PM LAS File 219083 3101 1 R lS.e;�e��Ei JUL 19 2019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Boyer, David L (CED) From: Joe Engel <jengel@hilcorp.com> Sent: Thursday, May 30, 2019 1:01 PM To: Boyer, David L (CED) Cc: Davies, Stephen F (CED); Cody Dinger Subject: RE: [EXTERNAL] Typo in MPU M-20 Assigned API Number Thanks, Dave. We will update our copy -Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Boyer, David L (CED) [maitto:david.boyer2@alaska.gov] Sent: Thursday, May 30, 2019 10:35 AM To: Joe Engel <jengel@hilcorp.com> Cc: Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: [EXTERNAL] Typo in MPU M-20 Assigned API Number Hi Joe, We found a typo in the assigned API number for the Hilcorp MPU M-20 recently approved PTD application. On your Duplicate Copy, please change the API number to: 50-029-23636-00-00. Sorry for the error. Thank you, Dave Boyer AOGCC The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-20 Hilcorp Alaska, LLC Permit to Drill Number: 219-083 Surface Location: 5037' FSL, 321' FEL, SEC. 14, T13N, R9E, UM, AK Bottomhole Location: 634' FSL, 289' FWL, SEC. 24, T13N, R9E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, &4V Daniel T. Seamount, Jr. Commissioner DATED this Zq day of May, 2019. LNdF.w%.# J7.Y G L�_L.? STATE OF ALASKA Ab, -..A OIL AND GAS CONSERVATION COMM—ON MAY 2 4 ?pig PERMIT TO DRILL 20 AAC 25.005 Anr_Oil" 1a. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas Ll Service - WAG ❑ Service - Disp ❑ 1c. Spec I I ro os for: Drill ❑� Lateral ❑ Stratigraphic Test ❑ Development -Oil Service - Winj ❑ Single Zone ❑� Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry EJ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 MPU M-20 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 14,781' TVD: 3,556' Milne Point Field Schrader Bluff Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 5037' FSL, 321' FEL, Sec 14, T13N, R9E, UM, AK ADL025514, ADL355023, ADL388235 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 648' FNL, 855' FWL, Sec 13, T1 3N, R9E, UM, AK LONS 16-004 6/22/2019 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 634' FSL, 289' FWL, Sec 24, TI 3N, R9E, UM, AK 7735 1073' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 58.7' 15. Distance to Nearest Well Open Surface: x-533843 y- 6027889 Zone -4 GL / BF Elevation above MSL (ft): 25' to Same Pool: 950' to MPU M-14 16. Deviated wells: Kickoff depth: 400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 93.4 degrees Downhole: 1715 Surface: 1329 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) Cond 20" 215# X-42 Weld 113' Surface Surface 113' 113' ±270 0 Slg 1 L - 805 ft3 / T - 458 ft3 12-1/4" 9-5/8" 40# L-80 TXP SR 5,478' Surface Surface 5,478' 3,909' Stg 2 L - 1937 ft3 / T - 314 fl3 Tieback 7" 26# L-80 TXP SR 5,338' Surface Surface 5,338' 3,895' Tieback Assy. 8-1/2" 6-5/8" 20# L-80 Hyd 563 9,443' 5,338' 3,895' 14,781' 3,556' Cementless Slotted Liner 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes ❑ No R 20. Attachments: Property Plat Q BOP SketchD Drilling Program B Time v. Depth Plot 8✓ Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirementsB 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'eft l?I h11COr .COITI Authorized Title: Drilling Manager Contact Phone: 777-8395 Fol MoN7Y MYE/t-$ Authorized Signature: Date:I. 41 Commission Use Only Permit to Drill PI Number: Permit Approv //�� ?j9 q See cover letter for other Number: — O 50- OZ - -00 ' Data. requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other. �, ��� ) ?- Samples req'd: Yes L]No[� ,,,� Mud log req'd: Yes E] NIP?' �S 1 HzS measures: Yes ❑ No Directional svy req'd: Yes Ly No ❑ r[7 Spacing exception mq'd: Yes [I No L7y� Inclination -only svy req'd: Yes ❑ Noy Post initial injection MIT req'd: Yes ❑ No ❑ APPROVED BY Approved by: COMMISSIONER THE COMMISSION Dale: S' t Submit Form and /�• a 1010 e A2017 his permit isiva f¢ �rih� f10 e�YtA of approval per 20 AAC 25.005(8 Attachments in Duplicate vd , _ :i' ` I V 1 ///��� L- �16��Fi U Hilcorp 5.24.2019 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7'" Avenue Anchorage, Alaska 99501 Re: Application for Permit to Drill MPU M-20 Dear Commissioner, ]oe Engel Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email: jengel@hilcorp.com Hilcorp Alaska, LLC hereby submits for review and approval for a Permit to Drill an onshore production well at Milne Point'M' Pad, well slot 20. Drilling operations are intended to commence approximately June 22nd, 2019, pending rig schedule. M_ a multi well program targeting the Schrader Bluff sand on The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. An 8.5" lateral section will then be drilled. A 6-5/8" slotted liner will be run in the open hole section and the well produced with a jet pump assembly. The M-20 directional plan has the surface hole crossing the unity boundary to the north, in to KRU, and then returning to MPU before landing in the target zone. M-20 will not be producing hydorcarbons from KRU and no pay zone will be open with 500 feet of the MPU boundary, in compliance with AOGCC regulations. The wellbore easement application has been submitted and we expect an authorization no later than mid-June. M-20 will not be spudded without authorization. A copy of our wellbore easement application has been attached for reference. The Doyon 14 will be used to drill and complete the wellbore. Please find attached the Form 10-401, Application For Permit to Drill per 20 AAC 25.005 (a) and the drilling program for MPU M-20, which includes information required by 20 AAC 25.005 (c). If you have any questions, or require further information, please do not hesitate to contact myself (Joe Engel) at 777-8395 or jengel@hilcorp.com or Monty Myers at 777-8431 or mmyers@hilcorp.com. Sincerely, 9� Joe Engel Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 Hilcorp Alaska, LLC Milne Point Unit (MPU) M-20 Drilling Program Version 1 5/24/19 Table of Contents 1.0 Well Summary .................................................................................................................................1 2.0 Management of Change Information ............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 18.0 6.0 Planned Wellbore Schematic..........................................................................................................6 19.0 7.0 Drilling / Completion Summary .....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................10 10.0 N/U 21-1/4" 2M Diverter System.................................................................................................11 11.0 Drill 12-1/4" Hole Section.............................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 13.0 Cement 9-5/8" Surface Casing.....................................................................................................21 14.0 BOP N/U and Test.........................................................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 6-5/8" Production Liner........................................................................................................32 17.0 Run 7" Tieback..............................................................................................................................36 18.0 Run Jet Pump Completion...........................................................................................................39 19.0 RDMO............................................................................................................................................40 20.0 Doyon 14 Diverter Schematic.......................................................................................................41 21.0 Doyon 14 BOP Schematic.............................................................................................................42 22.0 Wellhead Schematic......................................................................................................................43 23.0 Days Vs Depth................................................................................................................................44 24.0 Formation Tops & Information...................................................................................................45 25.0 Anticipated Drilling Hazards.......................................................................................................46 26.0 Doyon 14 Layout............................................................................................................................49 27.0 FIT Procedure................................................................................................................................50 28.0 Doyon 14 Choke Manifold Schematic..........................................................................................51 29.0 Casing Design.................................................................................................................................52 30.0 8-1/2" Hole Section MASP............................................................................................................53 31.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................54 32.0 Surface Plat (As Built) (NAD 27).................................................................................................55 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart ..................................................................56 34.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50...............................................................57 H HilcoTrp . 1.0 Well Summary Milne Point Unit M-20 SB Producer Drilling Procedure Well MPU M-20 Pad Milne Point "M" Pad Planned Completion Type Jet Pump on 3-1/2" Production Tubing Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 14,781' MD / 3,556' TVD PBTD, MD / TVD 14,770' MD / 3,555' TVD Surface Location (Governmental) 5037' FSL, 321' FEL, Sec 14, T13N, R9E, UM, AK Surface Location (NAD 27) X= 533843.6, Y= 6027889.5 Top of Productive Horizon (Governmental) 648' FNL, 855' FWL, Sec 13, T13N, R9E, UM, AK TPH Location (NAD 27) X= 535021.9Y= 6027489 BHL (Governmental) 634' FSL, 289' FWL, Sec 24, TON, R9E, UM, AK BEL AD 27 X= 534505, Y=6018210 AFE Number 1912739 AFE Drilling Days 21 AFE Completion Das 5 AFE Drilling Amount $4,473,600 AFE Completion Amount $2,044,682 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1329 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1715 psig Work String 5" 19.5# 5-135 DS -50 & NC 50 KB Elevation above MSL: 33.7 ft + 25.0 ft = 58.7 ft GL Elevation above MSL: 25.0 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 2.0 Management of Change Information 11 Hilcorp Alaska, LLC HEjlcorp Changes to Approved Permit to Drill Date: 512 412 01 9 Subject: Changes to Approved Permit to Drill for MPU M-20 File #: MPU M-20 Drilling and Completion Program Any modifications to MPU M-20 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved in advance to the AOGCC.1 Approval: Drilling Prepared: Drilling Engineer Page 3 u re Date Date Milne Point Unit M-20 SB Producer Hilcorp H co Drilling Procedure 2.0 Management of Change Information 11 Hilcorp Alaska, LLC HEjlcorp Changes to Approved Permit to Drill Date: 512 412 01 9 Subject: Changes to Approved Permit to Drill for MPU M-20 File #: MPU M-20 Drilling and Completion Program Any modifications to MPU M-20 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved in advance to the AOGCC.1 Approval: Drilling Prepared: Drilling Engineer Page 3 u re Date Date H Hilcorp Ene�gi GnnpmY 3.0 Tubular Program: Milne Point Unit M-20 SB Producer Drilling Procedure 4.0 Drill Pipe Information: All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 5.0 Internal Reporting Requirements Milne Point Unit M-20 SB Producer Drilling Procedure 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolinit7a hilcorp.com, mmyers .hilcorp, jenael@hilcorp.com and cdinger@hilcoip.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mmyers@hilcorp,com jengel(a hilcorp.com and cdinger@hilcoEp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers@hilcom.com iengel@hilcoEp.com and cdinger - hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 lengel@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 907.947.9533 twellman@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Milne Point Unit M-20 SB Producer Hilcorp Drilling Procedure E�Caapwq 6.0 Planned Wellbore Schematic ft 0 Ew: 38.7/4i Sw.: lig TD=IA783" (Nq /TD=3 •s55VjT V0j PSTD-A77B jNgjTD=3,5WPVN Page 6 OPEN HOLE /CEMENT DETAIL ---------i 42' Milne Point Unit 12-1/d'Ist stage Well MPU Moose Pad M-20 PROPOSED SCHEMATIC Last Completed: Proposed &1/3" PTD: TBD --------------------------- TREE & WEII}IFi10 ------ Tree Camera. 3 IA' SM 1 Wsllhead FML 11"SM TC -IA w/11'x 31/2'TC-11Top and Ran= Tubing 2867" Hangar with 3"DW'11'BPV pwfik. 2ea W NPTmrnmllinn. OPEN HOLE /CEMENT DETAIL ---------i 42' SO yNs(1DYards g4RPalgdumped down hacksidel 12-1/d'Ist stage L-875 R3 /T-458 R3 12-3/d"2rd ua8e I L-1937R3/T-33483 &1/3" Csmeo4raa Skttetl liner in 8-1j2"hok 9.5/8' I Sudxe I ml48D/T8P I 8.67E 1 Sud![! I 5,478'1 221 7" TieLack 2N'L9'J/F1P 6151" Surlae 5,338' 011383 TUBING DETAIL WELL INCUNATION DETAIL kOP tD 397 Max 1101. An Ie=@let Pum Max llak A.& . @ l(NFik Maxll eAn a"Tuhi Tal Mullok Angle=B9.4 ' ' JEWELRY DETAIL N. Tw MD Nem Drift ID upper Completion 1 29' Tobin Ilan er 3.1/r TC -11 Top & Wv) w/ Blas Rin on han pup 2867" 2 e1.5W' 3.5" GLM wI1.5"SDSLV set 4ZOOD MI3t.) 2.867' 3 !4,057 35"Oixhergr Prewre Gauge MandrellD'achatge Gauge! 2875" 4 -4,107 15" XD sidi.R Sleeve 2.833" Paxkiag Bae 2813" S !4.150' 3.5"G.9eh.dmlw/k"Wtalltake Guu 2875" 6 -4,207 3 5'. X Nipn1.12.813'Pmkin Bad! 2.813" 7 !4,250' 7'x35'PIIL Retdorahle Padmr;50k Sh. Release 2885" 8 •A3W' 3.5"Md NiP ef281r Pakin,, Bare; 215"NoGol&W ED 175M WCC 2.750" 9 lSAS0' 3.S"WLEG 2867' LowerCarpkti. 30 5,338' BOTSLZXPLiner TDOPxpkerw78D5h7-5/8'x4518' 6.177' 11 5,338' T Tkhzk Amy lB2S'OD No-Cnj &ISI" 12 5.350' 7't1v511U563 L-80x6-5j1V'jjX 1563 L- XO 5.924" 13 1 S,SW' I 6-5jr Shtted liner 5924" 14 1 14,781' 1 Shoe •---------------------------------------------------' GENERAL WELLINFO ' API: TBD Dr111W nd CaioletMb D n14 -TBD 7.0 Drilling / Completion Summary Milne Point Unit M-20 SB Producer Drilling Procedure MPU M-20 is a grassroots jet pump producer planned to be drilled in the Schrader Bluff OA sand. M-20 is part of a multi well program targeting the Schrader Bluff sand on M -Pad. The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. An 8.5" lateral section will then be drilled. A 6-5/8" slotted liner will be run in the open hole section and the well produced with a jet pump assembly. The M-20 directional plan has the surface hole crossing the unity boundary to the north, in to KRU, and then returning to MPU before landing in the target zone. M-20 will not be producing hydorcarbons from KRU and no pay zone will be open with 500 feet of the MPU boundary, in compliance with AOGCC regulations. The wellbore easement application has been submitted and we expect an authorization no later than mid- June. M-20 will not be spudded without authorization. A copy of our wellbore easement application has been attached for reference. The Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately June 22th, 2019, pending rig schedule. Surface casing will be run to 5,477 MD / 3,908' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point `B" pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. N/U & Test 21-1/4" Diverter and 16" diverter line 3. Drill 12-1/4" hole to TD of surface hole section. Run and cement 9-5/8" surface casing 4. N/D diverter, N/U & test 13-5/8" x 5M BOP 5. Drill 8-1/2" lateral to well TD. Run 6-5/8" production liner 6. Run 7" tieback 7. Run completion 8. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR+ ADR (For geo-steering) Page 7 H Hilcorp E., C m x Milne Point Unit M-20 SB Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-20. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flowfrom the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: No variances are requested at this time. See note in Section 7 regarding wellbore easement application. Page 8 Summary of BOP Equipment & Notifications Milne Point Unit M-20 SB Producer Drilling Procedure Hole Section Equipment Test Pressure(psi) 12 1/4" • 21-1/4" 2M Diverter w/ 16" Diverter Line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 250/40M- 0 Blind ram in bum cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/4900' 3�x ° • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPs utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.repp@alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guv.schwartz(_@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loeppOaalaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@-alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors(a alaska.gov Test/Inspection notification standardization format: htip://doa alaska eov/ogc/forms/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 H Hilcorp E�� CST 9.0 R/U and Preparatory Work Milne Point Unit M-20 SB Producer Drilling Procedure 9.1 M-20 will utilize a newly set 20" conductor on M -Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and RAJ. 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<80°F). 9.10 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.11 Ensure 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @110 spm @ 95% volumetric efficiency. Page 10 Milne Point Unit M-20 SB Producer Hilcorp Drilling Procedure R.mC-Pffy 10.0 N/U 21-1/4" 2M Diverter System 10.1 N/U 21-1/4" Hydril MSP 2M Diverter System (Diverter Schematic attached to program). • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N/U 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest i¢nition source • Place drip berm at the end of diverter line 10.2 Notify A9C LCC. Function test diverter. Ensure that the knife gate and annular are operated on th same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. Page 11 H Hilcox Uc 10.5 Rig & Diverter Orientation: • May change on location M-10 ■ M-11 ■ M-13 ■ M-12 M-14 ■ M-20 M-15 ■ M-16 ■ 75' Radius Clear of lanition Sources Milne Point Unit M-20 SB Producer Drilling Procedure Diverter Line Drawing Not To Scale MPU M -Pad Diverter Line May Be Oriented Different On Location Page 12 0 Hilc�r gam 9 11.0 Drill 12-1/4" Hole Section Milne Point Unit M-20 SB Producer Drilling Procedure 11.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before MAJ. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub for wireline gyro • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 11.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4" hole section to section TD, in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. • Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Slow in/out of slips and while tripping to keep swab and surge pressures low • Ensure shakers are functioning properly. Check for holes in screens on connections. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. • Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). • Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. Page 13 .� n Hilcorp E..w Canyny Milne Point Unit M-20 SB Producer Drilling Procedure • Gas hydrates have not been seen on M -Pad. However, be prepared for them. In MPU they have been encountered typically around 2100-2400' TVD (just below permafrost). Be prepared for hydrates: Gas hydrates can be identified by the gas detector and a decrease in MW or ECD Monitor returns for hydrates, checking pressurized & non -pressurized scales Do not stop to circulate out gas hydrates — this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. 11.4 12-1/4" hole mud program summary • Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ DDB. Depth Interval MW ) Surface — Base Permafrost 8:9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells MW can be cut once —500' below hydrate zone • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Page 14 Milne Point Unit M-20 513 Producer Drilling Procedure Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 — 9.2 ppg Pre -Hydrated AquageUfreshwater spud mud Pro erftes: Section Densi Viscosity Plastic Viscosity Yield Point AN FL PH Tem Surface 8.8 - 9.8 75-175 20-40 25-45 <10 8.5-9. 0.08 System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-1 Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 Pol Pac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH t/ bottom, proceed to BROOH t/ HWDP • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5 —10 It / minute, adjust as dictated by hole conditions • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 15 / d H Hilcor b� 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. Milne Point Unit M-20 SB Producer Drilling Procedure 12.2 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120' shoe track assembly consisting of: 9-5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle 'Top Hat' 1 joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • Ensure bypass baffle is correctly installed on top of float collar. This end up. —, Bypass Baffle W • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 16 ff Me � 2 12.5 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. So No_ Closing Sleeve No. Shear Pins Dpening Sleeve No. Shear Pins ES Cementer Depth Baffle Adapter (if used) ID Depth Bypass or Shutoff Baffle to Depth Float Collar Depth Float Shoe Depth Hole TD "Reference Casing Sales Manual s:"On S Page 17 "A Oaerall Length B Alii. to At., Orillow C Max. Tool OD D Opening seat ID E Closing Seat 10 Plug Set Part No. SO No. Closing Plug OD Opening Plug OD OD Shut-off Plug OD Bypass Plug (d used) OD Milne Point Unit M-20 SB Producer Drilling Procedure Hik., Eill Runrung DrEer ESll [.mental Shut Off Plug Baffle Adapter gy-Pass pug jl L L1.i By Pass Batik float Collar rbzt Slave H Hilcorp ��, Milne Point Unit M-20 SB Producer Drilling Procedure 12.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: • 1 centralizer every joint t/ — 1000' MD from shoe • 1 centralizer every 2 joints to 2,000' above shoe (Top of Ugnu) • Verify depth of lowest Ugnu water sand for isolation with Geologist • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES -II Stage tool so that it is positioned at least 100' TVD below the permafrost (— 2,500' MD). (Halliburton ESIPC with packer element may be used). • Install centralizers over couplings on 5 joints below and 55 Joints above stage tool. • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. • ESIPC: Ensure tool is pinned properly. ESIPC packer to inflate at — 2080 psi, and the tool to open at — 3000 psi. Reference ESIPC Procedure. 9-5/8" 40# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8" 18,860 ft -lbs 20,960 ft -lbs 23,060 ft -lbs Page 18 PERFORMANCE Body Yasd stn ngh 316 x1000 as, Imemalr" 5750 psi sb1Ys 80000 psi Collapse 3090 Psi GEOMETRY I Milne Point Unit 10.625 in. 4.891 in. Cauplmg Length Mheads per s 10825. 5 Connection IC Connection OD Option 8.823 in. REGULAR M-20 SB Producer Drilling Procedure HiIii TXP® BTC ......11/08.12018 Outside Diameter 9-625 in. Min. Watt Thickness 87.6't 11)Grai L80 low Type 1 Wall Thickness 0i Connection OD REGULAR COUPLING PIPE BOOT OpGnn Body: Red 1st Send: Red! Grade 180 Type 1• Ddtt API standard tat Bard: Brown 2nd Sand: 2nd Bard: - Bnowm Type Casing 3m Band: - 3m Sand: - 01h Band - PIPE BODY DATA GEOMETRY Nominal CO 9.825 in. Nominal Weight d01pstt 1 8.679.. Naninal IC, 8.835 in 9612 Thickness 0.393 in. Pa. End Might 38.8711 OD TWsrance API PERFORMANCE Body Yasd stn ngh 316 x1000 as, Imemalr" 5750 psi sb1Ys 80000 psi Collapse 3090 Psi GEOMETRY I C.ton OD Make-up Lass. 10.625 in. 4.891 in. Cauplmg Length Mheads per s 10825. 5 Connection IC Connection OD Option 8.823 in. REGULAR PERFORMANCE —71 Tensien Elfciency 100.0% : a int Yisd Strength 916.000x1000 Intertal Phiswm capacity m 5750000 Psi Ips Compression EffPienc9 100% Compression snei 916000x1000 Max. Planets, Sending 38:1008 Ibs Edema] F:- sure Capacity 3090.008 pe. MAKE-UP TORQUES klm+mum 18aan ft Ts Optimum 20960%-Ibs MaYtnum 23060 ft -Ips OPERATION LIMIT TORQUES Operating li hree 356009 -lbs Yield Tara, 43400 ft M. Notes This connection is fultj interchangeable with TXP® BTC - 9 625 in- - 36143.5147153.5158.4 Ibs1H [1] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C31 ISO 10400 - 2007. Oatasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which will be reduced. Please contact a local Tenaris technical sales representative. Page 19 Milne Point Unit M-20 SB Producer Drilling Procedure 12.8 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: 0 1 centralizer every 2 joints to base of conductor 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. V/ Page 20 n Hilcorp MC 13.0 Cement 9-5/8" Surface Casing Milne Point Unit M-20 SB Producer Drilling Procedure 13.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pumps will be utilized for displacement, and how fluid will be fed to displacement PUMP- • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/1J cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated I" Stage Total Cement Volume: Page 21 if 73X 3SL� Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" � (4,477'- 2500') x .0558 bpf x 1.3 = 143.4 805.1 J Casing Total Lead 143.4 805.1 12-1/4" OH x 9-5/8" (5,477'- 4,477') x .0558 bpf x 1.3 = 72.5 407 Casing 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 21 if 73X 3SL� n Hilcor mx Milne Point Unit M-20 S8 Producer Drilling Procedure Cement Slurry Design (1St Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 5,357' x.0758 bpf = 406 bbls 80 bbls of water to be left behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, t4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until Page 22 0 Lead Slurry Tail Slurry System ExtendaCEM TM System SwiftCEM TM System Density 11.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk ✓ 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 5,357' x.0758 bpf = 406 bbls 80 bbls of water to be left behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, t4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until Page 22 0 n Hilcorp Euugy Cmyoy Milne Point Unit M-20 SB Producer Drilling Procedure cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. If ESIPC is ran, pressure up to 3000 psi to open tool and function as an ES -II stage tool 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 23 '� n Hite orp E ® Second Stage Surface Cement Job: Milne Point Unit M-20 SB Producer Drilling Procedure 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2"d stage is ready. Hold pre job safety meeting. • Past wells have seen pressure increase while circulating through stage tool after reduced rate 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump curt per below recipe for the 2"d stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2"1 Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) SwiftCEM •" System (Hal Cem) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1= 28.6 161 v 12-1/4" CH x 9-5/8" Casing (2000'- 110') x .0558 bpf x 3 = 316.4 1776.3 J Total Lead 345 1937 12-1/4" CH x 9-5/8" Casing (2500'- 2000') x .0558 bpf x 2 = 55.8 314 ~ Total Tail 55.8 314 Cement Slurry Design (2nd stage cement job): Page 24 456 2zc Lead Slurry Tail Slurry System Permafrost L SwiftCEM •" System (Hal Cem) Density 10.7 lb/gal 15.8 lb/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.08 gal/sk Page 24 456 2zc 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2500' x.0758 bpf= 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1000 — 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns duringjob, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run" casing tally & casing and cement report to jengel@hilcorp.com and cdinger@hilcorp com This will be included with the EOW documentation that goes to the AOGCC. Page 25 Milne Point unit M-20 SB Producer Hilcorp Enogy CimryvY Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2500' x.0758 bpf= 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1000 — 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns duringjob, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run" casing tally & casing and cement report to jengel@hilcorp.com and cdinger@hilcorp com This will be included with the EOW documentation that goes to the AOGCC. Page 25 ff Hilcorp R. C -p 14.0 BOP N/U and Test Milne Point Unit M-20 SB Producer Drilling Procedure 14.1 N/D the diverter T, knife gate, diverter line & N/U 11" x 13-5/8" 5M casing spool. 14.2 N/U 13-5/8" x 5M BOP as follows: • BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13- 5/8" x 5M mud cross / 13-5/8" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in \ bottom cavity. �O • Single ram can be dressed with 2-7/8" x 5" VBRs 5 N/U bell nipple, install flowline. G • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment 14.4 Run 5" BOP test plug 14.5 Test BOP to 250/3222-Qsi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Test 5" testloints • Confirm test pressures with PTD • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.6 R/D BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 8.9 ppg F1oPro fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 6" liners in mud pumps. Page 26 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.22° PDM) Milne PointUnit M-20 SB Producer Drilling Procedure 15.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool or ESIPC. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 R/U and test casing to 2500 psij 30 min. Ensure to record volume / pressure (every V4 bbl) and L plot on FIT graph. AO CC reg is 50% of burst = 5750 / 2 = —2875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent L5 5 pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry ya' i Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20' of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.0_nrnr. EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD Cleanout BHA 15.9 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135 DS50 & NC50. • Run a ported float in the production hole section. 15.10 8-1/2" hole section mud program summary: • Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Use appropriate SAFECARB blend on this well Page 27 Milne Point Unit M-20 SB Producer Drilling Procedure • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaninlr • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9 — 9.5 ppg F1oPro drilling fluid Pro ernes: IntervalDensit Size PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 1 15-30 4-6 1 <10% <8 <1 1.0 <100 System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/100 bbls) 55 gal dm 0.2 FLONIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE -GARB 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 lb sx 10 Soda Ash so lb sx 0.5 Page 28 n Hilcorp L,� ��> 15.11 TIH with 8-1/2" directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Flo Pro drilling fluid Milne Point Unit M-20 SB Producer Drilling Procedure 15.13 Begin drilling 8.5" hole section, on -bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations • If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding .5% lubes 15.14 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer. • Flow Rate: 350-550 gpm, target min. AV's 200 ft/min, 385 gpm • RPM: 120+ • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low • Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD, pump pressure & hookload trends for hole cleaning indication • Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Reservoir plan is to undulate between Schrader OA & OA3 lobes in 1000-1500' MD increments, and keeping DLS <3° when moving between lobes • Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. • Target ROP is as fast as we can clean the hole without having to backream connections • Schrader Bluff OA Concretions: 5-10% of lateral • L-47:6%, L-50 9.5% • F-106: 6.1%, F-107: 4.7%, F-018: 9.9%, F-109: 10%, F-110: 10.1% • Offset injection and abnormal pressure has been seen on M-10, -11, -12. MPD will be utilized to monitor pressure build up on connections. • Close Approaches: • There are no close approaches on M-20 15.15 Reference: Open hole sidetracking practice: • If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. Page 29 H Hilcorp E, .2 Milne Point Unit M-20 SB Producer Drilling Procedure Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed • Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary • If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum 15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 15.18 Displace 1.5 OH + Liner volume with viscosifred brine. • Proposed brine blend (same as used on M-16, aiming for an 8 on the 6rpm reading) - KCl: 7.1bbp for 2% NaCl: 60.9ppg for 9.4ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42ppb Flo -Vis Plus: 1.25ppb Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 15.19 BROOH with the drilling assembly to the 9-5/8" casing shoe • Circulate at full drill rate (less if losses are seen, 350 gpm min). • Rotate at maximum rpm that can be sustained. Pulling speed 5 —10 min/std (slip to slip time, not including connections), adjust as dictated by hole conditions If backreaming operations are commenced, continue backreaming to the shoe 15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOK 15.21 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. Page 30 Milne Point Unit M-20 SB Producer Drilling Procedure 15.22 Monitor well for flow / monitor for pressure build up with MPD. Increase fluid weight if necessary Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise 15.23 POOH and LD BHA. 15.24 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 31 H Hilcorp U� 16.0 Run 6-5/8" Production Liner Milne Point Unit M-20 SB Producer Drilling Procedure 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 6- 5/8" pre drilled liner, the following well control response procedure will be followed: • PIU & M/U the 5" safety joint (with 6-5/8" crossover installed on bottom, TIW valve in open position on top, 6-5/8" handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 6-5/8" Predrilled liner. • Slack off and with 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW. • Proceed with well kill operations. 16.2. R/U 6-5/8" liner running equipment. • Ensure 6-5/8" 20# Hydril 563 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.3. Run 6-5/8" slotted production liner • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run round nose float shoe on bottom. • 6-5/8" slotted liner will auto —fill • 6-5/8" Liner will be centralized with 1/joint free floating • If needed, install swell packers as per the lower completion tally. • Remove protective packaging on swell packers just prior to picking up • Do not place tongs or slips on the packer element 6-5/8" 20 # Hydril 563 Torque OD Minimum Optimum Maximum Yield Torque 6-5/8 5,900 ft -lbs 7,100 ft -lbs 1 10,300 ft -lbs 36,000 ft -lbs Page 32 H Hilcorp Milne Point Unit M-20 SB Producer Drilling Procedure Wedge 5634@ 11.W2018 4us: do G:anccr &02in Min. Well AT.59 Malc-up La. "Win. 7hm 1pmin 3.29 Cnnpcllee CO La n62 BEGuI Thianer. 1.1 Grade Lao Ter Ian ERewr4y 997 Jmnl Yvld slraigm 4304163.1090 eaem.L Pmzpum CapacCl 611911.1109 Ae Type 1 Ib, wall Tnialnea 0.26E n Comeebon OD REGULAR AN.. 0.Fwatrla 2w 14 51.6'11Nd IV, Dillon COIALIRG WEeObY MAREIIP TORQUES Brr Rea Isl Vane Red Gmde LBO Type i' Drift Aal sm.d.ra 1,t Band: a.. 2rd it .. 'OCa+a:2l Tcreup 31011 IOP vau Trim p Marti 2rd Bad Drown RUCK -ON TYPe Casing and Vand • ad Band: Notes 41n Bmrtl GEOMETRY Wedge 563E - 6.625 in. - 24128132 1tMt upm.nal00 6.619n Npmf+al YYulgm 4a001t,,M Opfl 6.944.n. Npmaul0 6.049 m. 'Nall lh"rpp. 0.214 m. Fa{n End W.grl 14.S11Nm OQ Tn1arY[a AAI 1 PERFORMANCE =_Np rwa svenpm a96,t000ms Imcmal rima 60%0". axlv=_ e66M pu Galapsp 3471 y.1 CONNECT14DN DATA GEOMETRY I.nn.o., CO 7.390,n. .. 'Wgi'ln 9291n C.nnadnn to s.en'n. Malc-up La. "Win. 7hm 1pmin 3.29 Cnnpcllee CO La n62 BEGuI PERFORMANCE Ter Ian ERewr4y 997 Jmnl Yvld slraigm 4304163.1090 eaem.L Pmzpum CapacCl 611911.1109 Ae Ib, u.pmpres%ipn EOc�ncy 1000 �. .,pmpre>%lan st."}t 459040.1000 AN.. 0.Fwatrla 2w 14 51.6'11Nd IV, caarral9tes5um Capon. 3470-0110 ps Couple, face La9d 326060 be MAREIIP TORQUES Mt�mum smoitb. 9pgmum 7140 L2s Ya>:mum .04041'. ms OPERATION UMIT TORQUES 'OCa+a:2l Tcreup 31011 IOP vau Trim p Marti RUCK -ON Meimum laaad z lbi M .Jnr Y. 11300 Mtc Notes This connection is fully interchangeable with: Wedge 563E - 6.625 in. - 24128132 1tMt Connection i iih OopelessS Technc4og y are Bully compatible •nth the same mnnectien in its Standard version Page 33 H Hilcorp Emrp C®quy Milne Point Unit M-20 SB Producer Drilling Procedure 16.6. Ensure to run enough liner to provide for approx 150' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. • AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8" connection. • Consider having a Joint of solid ipe across BOPE Stack while running inner string 16.7. Before picking up Baker SLZXP liner hanger/ packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. M/U Baker SLZXP liner top packer to inner string and 6-5/8" liner. 16.9. Note PUW, SOW, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.10. RIH w/ liner on 5" HWDP no faster than 30 ft/min —this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. • Ensure 5" HWDP has been drifted • There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. 16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 rpm 16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.15. Rig up to pump down the work string with the rig pumps. 16.16. Break circulation. Begin circulating at —1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker. Page 34 H Hilcorp Milne Point Unit M-20 SB Producer Drilling Procedure 16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.18. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the WIV) down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 16.19. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP liner hanger to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4500 psi to release the HRDE running tool. 16.20. Bleed DP pressure to zero. Pick up to expose Rotating Dog Sub and set down 50k# without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k# again, 16.21. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.23. P/U pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 16.24. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. 16.25. M/U 3.5" wash tool & RIH w/ remaining DP out of derrick to liner top. 16.26. Wash through liner top at max rate & circulate hole clean. Pump sweeps around. Displace well to clean filtered brine after no solids are returned. 16.27. POOH & L/D remaining 5" HWDP & Inner string 16.28. Once inner string is L/D, swap to the completion AFE Page 35 H Hilcorp 17.0 17.1 Run 7" Tieback RIH w/ 3.5" washpipe on 5" dp to clean out liner top. POOH LDDP. Milne Point Unit M-20 SB Producer Drilling Procedure 17.2 RX and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie -back space out calculation. Install and test 7" (250/3000 psi) solid body casing rams. 17.2 R/U 7" casing handling equipment. • Ensure XO to DP made up to FOSV and ready on rig floor. Rig up computer torque monitoring service. String should stay full while running, r/u fill up line and check as appropriate. 17.3 P/U tieback seal assembly and set in rotary table. Ensure 7" seal assembly has x4 1" holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8" x 7" annulus. 17.4 M/U first joint of 7" to seal assy. 17.5 Run 7" 26# TXP tieback to position seal assembly two joints above tieback sleeve. Record up & down weights. 7" 26# TXP MUT OD Minimum Optimum Maximum Yield Tor ue 7" 13,280 ft -lbs 14,750 ft -lbs 16,230 ft -lbs 23,400 ft -lbs Page 36 H Hilcorp aoow n�e.ay TXP® BTC Outside Diameter 7.000m, Wall Thickness 0.362 in. Grade LBO Type I Min. Wall 87.5% Thicknees Connection DD REGULAR Option 1st Band: Red Drift API standard Type Casing Milne Point Unit M-20 SB Producer Drilling Procedure ,—TI- 12,'W2016 (') Grade LBO law Type 1 COLIPLIM3 PIPE BODY Body: Red 1st Band: Red 1st Band: Brown 2nd Band: 2nd Band:- Brawn 3rd Band:- 3rd Band - Coupling Leng&h 4th Band. - PIPE BODY DATA GEOMETRY Normal OD TOM in. Nonviral ft.ght 26lbalt IXiD 6.151 an. Nominal D) 6.276 in Wall Tricvsss 0.362 in. Plait End WEight 25-69lips-it OD Tderame API PERFORMANCE Body Yield SDI 604x100016=-- Inlerrui lieV'. 7240pad SMYS 80000 psi Collapse 5410 psi CONNECTION DATA GEOMETRY Canracfian OD TOM in Coupling Leng&h 10.200 in. Cann bon ID 52" h Malz-up Loss 4.Wgw Thwds per m 5 Connection OD Option REGULAR PERFORMANCE Tendon Eftiancy 100.0% Joint Ywld Strenglh 5D4.000 xlWC W,,al PFesoae Capacity"' 7240.000 psi lbs Corpression Eftiercy 100% Compression strerdh 604.000x1009 Max.Almzstle Bending 52'71110h Ib5 E,simal Pressure Capacity 5410DOD psi MANE-UPTOROUES Minimum 132M Nos Oplinnrn 147506 -lbs Vamm 16230 ft -In OPERATION LIMIT TORQUES Operating Tcque 20000 ft4ts YeklTarquw 23400 Dabs Notes This connectiort is fully interchangeabte with: T)G>8 BTG - 7 in. - 23 1 29132135138 lbilt 11) Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C3 I ISO IMO - 2007. Page 37 17.6 M/U 7" to DP crossover. Milne Point Unit M-20 SB Producer Drilling Procedure 17.7 M/U stand of DP to string, and M/U top drive. 17.8 Break circulation at 1 bpm and begin lowering string. 17.9 Note seal assembly entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. 17.10 Continue lowering string and land out on no-go. Set down 5 — l Ok lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.11 PIU string & remove unnecessary 7" joints. 17.12 P/U hanger assembly and space out. M/U (or L/D) necessary joints and pup joints to position seal assembly 1 ft above "NO-GO DEPTH" when tie -back hanger lands out in wellhead. 17.13 Ensure circulation is possible through 7" string. 17.14 RU and circulation corrosion inhibited brine in the 9-5/8" x 7" annulus. 17.15 With seals stabbed into SBE, Spot diesel freeze protection from 2500' to surface in 7" x 9-5/8" annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent casing collapse of 7", verify collapse pressure of 7" tie back. 17.16 Slack off and land hanger. 17.17 Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 17.18 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off. RILDS. Test void to 3000 psi / 10 min. 17.19 R/D casing running tools. 17.20 Test 7" x 9-5/8" production annulus to 1000 psi / 30 min. 17.3 Set test plug and change top rams from 7" to 2-7/8" x 5-1/2" VBR. Test annular and lower rams to 2-7/8" test joint, 250 low / 3000 psi high. Page 38 H Hilcorp � �2 18.0 Run Jet Pump Completion Milne Point Unit M-20 S8 Producer Drilling Procedure 18.1 Change upper pipe rams back to 2-7/8" x 5" VBR. Test same. Verify the Jet pump components. 18.2 Run the 3-1/2" Jet Pump Completion as noted by completion engineer. a. Jet pump will be reverse circulating 18.3 M/U Jet Pump assembly and RIH to setting depth. i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. 18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.5 MU tubing hanger and landing joint. Terminate control lines. 18.6 Land tubing hanger. 18.7 Drop ball and rod, pressure up to 1,700 psi to start setting of PHL packer. 18.8 Continue to pressure up to 3,000 psi to set packer. 18.9 Pressure up to 3,500 psi to test tubing for 30 minutes and chart. 18.10 Bleed tubing to 2,000 psi. 18.11 Pressure up annulus to 3,500 psi to test casing/packer for 30 minutes and chart. 18.12 Bleed tubing to 0 psi. Pop shear valve from annulus to tubing (2,500 psi differential). 18.13 RILDS and test hanger. LD landing joint. 18.14 Install BPV. Pressure up on 3-1/2" x 7" annulus to 500psi, to test BPV from below. 5 min. 18.15 N/D BOP. 18.16 N/U tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. Terminate the cap strings. 18.17 Circulate diesel freeze protection down 3-1/2" x 7" annulus (Volume should equal capacity of tubing to 2500' + tubing annulus to 2500'). Connect IA to tree and allow diesel freeze protect to "U-tube" into position. Note — this may be done post -rig. 18.18 Pull BPV. Set TWC. Test tree to 250 psi low / 5000 psi high. Pull TWC. Set BPV. 18.19 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.20 Notify AOGCC of SVS testing. Test SVS on horizontal run of tree within 5 days of the start of production. Set low pressure trip below 275 psi Moose Pad header & separator pressure. Page 39 H Hil UW - 19.0 RDMO 19.1 RDMO Doyon 14 Page 40 Milne Point Unit M-20 SB Producer Drilling Procedure Milne Point unit M-20 SB Producer Hilco Drilling Procedure tee„ 20.0 Doyon 14 Diverter Schematic 211:4' 2A1 RFw- 21-0.4' 2M - 0"r 'T' 2144.21 sp» r sm 16.3.'4' 3M 21.1!4' 2M D& Page 41 -16' FO OPMN Knits VWv `18" Drvtt1tt Lira H Milne Point unit M-20 SB Producer Hilcorp E^ C ,-, Drilling Procedure 21.0 Doyon 14 BOP Schematic Page 42 2-7/8" x 5" VBR Blind Rams x 5M NCR hoke Line al Gate Valve 2-7/8" x5 11 VBR 22.0 Wellhead Schematic Page 43 Milne Point Unit M-20 SB Producer Drilling Procedure L Sf Ir +m:au �es 23.0 Days Vs Depth us 111 E111 6000 ss p 8000 a v N v 10000 9 Page 44 12000 14000 MPU M-20 SB OA Producer Days vs Depth Milne Point Unit M-20 5B Producer Drilling Procedure 7 0 5 10 15 20 25 30 Days n HilcoI E.e Cm x 24.0 Formation Tops & Information Milne Point Unit M-20 SB Producer Drilling Procedure MPU M-20 Formations (wp04) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2551 -2038 2097 922.68 8.46 LA3 3807 -3144 3202 1408.88 8.46 Schrader Bluff NA 4588 -3659 3717 1635.48 8.46 Schrader Bluff OA 5347 -3839 3897 1714.68 8.46 L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) GENERALIZED GEOLOGICAL FORE 'AST SS GEOLOGICAL COMMENTS TVD FM LITH DESCRIPTION u D.al NOTE: Sea kld k(usl Well Program for o'er GWik apecNlc casing dealer, depthA akw. .carr:000 weights. grades and corrections. g Ik1[pLSOlib[M cars• b medlim sand and ,mall /gavel E cidr min.rallbton•. AMOUNTSOF GRAVEL 1,000 AREENCOUNTERED WHEN DRILLING THE SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. ,rsp Base permafrost I ,nbeds of sand. clay and st"MM• with amaslDNl 2,11110• Now elcal. WaechpasiDlasid•tr•dti%g to utak wasNnynsmng LJ] 8 415. -,fI*Af No hydrates encountered on L -Pad wells saga. drilled to date. comment INarbob of sand, clave and Yhaba• with 0[a•bal shows of coal. Traces of p3Tb at H- 310 It 3,000 era al at #I. x00 N un be aticky and tlght(L41). flay bNrbedc between ]000 and 4500 It C xTz• L A 3"r h..a. Y UGNU: sed•• atcoarsemM r arl aanda whkhara (.Abr.Dl nub o ot: (bom to b bottom) mane •larIL fku sand. Aft shah Better d•e•kp•dlyd•menlrlgalnl•a»you UGNU Raglans booth, LandYOt••ped. Lipa andschradergidf. Pa•IN•Mo-ocarbonnmlt•d c.snb bswearnarofullradawlolaant NatMm ana4 IMI dawMtM .and cast. '31311' want 1-Ra.c) '4000' (NR) Schrader Bluff Sands: 4,000' j.Rac.w hydda a �m Schrader Bluff: Possible ation crt ..PtW a m.1tlMardunalco 1, aaaptmaocabrnaJandto 400It vat eeat lone while drilling bog strings and running strost ings and rune oJana Cay rico S.hIm•mIlt. Pto4600k oa nmhd casing. Recommend deep setting surface scnn1111Mdh Padd•IL47 (04)'417 (� am rKupar IFNe WSWca ofR LRSar• Easing for tong DEFl .s W%td In radwlluff.. WrIm oompl•t•d in the sambraiwl sand Nonlrm ansa Schrader Bluff sands area potential Bluff sen apote potential Schrader L-PaehbaMtmb,.andw.l- differential stuck pipe interval if left un -cased Bluff C Sulam "sir,, laoint In stale below for Kuparuk long strings. Sands' sdfmder Iflull Oesand For I.,r.... hw.11a. Page 45 25.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are no known wells in immediate proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for 112S. No H2S events have been documented on drill wells on this pad. Page 46 Milne Point unit M-20 SB Producer Hilcorp M ComV+^Y Drilling Procedure 25.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are no known wells in immediate proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for 112S. No H2S events have been documented on drill wells on this pad. Page 46 H Hilcorp E� ��> Milne Point Unit M-20 SB Producer Drilling Procedure 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 47 n Hilcorp 8-1/2" Hole Section: Milne Point Unit M-20 SB Producer Drilling Procedure Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of> 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. NeAbnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M - Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti -Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Page 48 Milne Point unit M-20 SB Producer Hilco Drilling Procedure U-2�P 26.0 Dovon 14 Page 49 H Hilcorp U-22. 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Milne Point Unit M-20 SB Producer Drilling Procedure 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 50 28.0 Doyon 14 Choke Manifold Schematic Page 51 Milne Point unit M-20 SB Producer Hilco Drilling Procedure 28.0 Doyon 14 Choke Manifold Schematic Page 51 29.0 Casing Design 11 Calculation & Casing Design Factors Hilcorp DATE: 5/2412019 WELL: MPU M-20 DESIGN BY: Joe Engel Hole Size 12-1/4" Hole Size 8-1/2" Hole Size Drilling Mode MASP: 1329 MASP: Production Mode MASP: 1329 Collapse Calculation: Section Calculation Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: attached MASP determination & attached MASP determination & Normal gradient external stress (0.494 psi/ft) and the casing e�Qcuated for the internal stress Cas ng Section Calculation/Specification 1 2 3 4 Milne Point unit 9-5/8" 65/8" Top (MD) M-20 SB Producer 5,327 HiloomP �� Drilling Procedure 29.0 Casing Design 11 Calculation & Casing Design Factors Hilcorp DATE: 5/2412019 WELL: MPU M-20 DESIGN BY: Joe Engel Hole Size 12-1/4" Hole Size 8-1/2" Hole Size Drilling Mode MASP: 1329 MASP: Production Mode MASP: 1329 Collapse Calculation: Section Calculation Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: attached MASP determination & attached MASP determination & Normal gradient external stress (0.494 psi/ft) and the casing e�Qcuated for the internal stress Page 52 Cas ng Section Calculation/Specification 1 2 3 4 Casing OD 9-5/8" 65/8" Top (MD) 0 5,327 Top (TVD) 0 3,878 Bottom (MD) 5,477 14,780 Bottom (TVD) 3,908 3,555 Length 5,477 9,453 Weight (ppf) 40 20 Grade L-80 L-80 Connection TXP H563 Weight w/o Bouyancy Factor (lbs) 219,080 189,060 Tension at Top of Section (Ibs) 219,080 189,060 Min strength Tension (1000 lbs) 916 459 Worst Case Safety Factor (Tension) 4.18✓ 2.43 Collapse Pressure at bottom (Psi) 1,931 1,965 Collapse Resistance w/o tension (Psi) 3,090 3,470 Worst Case Safety Factor (Collapse) 1.60 1.77 MASP (psi) 1,329 1,257 Minimum Yield (psi) 1 5,750 6,090 Worst case safety factor (Burst) 1 4.33 ✓ 4.84 Page 52 n HilcoR Eomp C®ryvY 30.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 14 8-1/2" Hole Section Hilcorp MPU M-20 Milne Point Unit MD TVD Planned Top: 5477 3908 Planned TD: 14780 3555 Milne Point Unit M-20 SB Producer Drilling Procedure Anticipated Formations and Pressures: 8.8-9.1 Surface 4125 Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OB Sand 3,908 1 1959 Oil 9.64 0.440 Offset Well Mud Densities Wrll MW range Tnn (TVD) Rnttnm ITVDI Date L-50 8.8-9.1 Surface 4125 2015 L-49 9.0-9.2 Surface 4196 2015 L-48 8.9-9.2 Surface 4147 2015 L-47 8.8-9.0 Surface 4158 2015 L-46 9.0-9.3 Surface 4177 2015 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3,908 (ft) x 0.78(psi/ft)= 3048 3048(psi)-[0.1(psi/ft)*3908(ft)]= 2658 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand)_ 3908 (ft) x 0.44(psi/ft)= 1720 psi C,720(psi)-0.1(psi/ft)*3908(ft) 1329psi • ,/ Summary: �— 1. MASP while drilling 8-1/2" production hole isgoverned by pore pressure and evacuation of a nti re wel (bore to gas at 0.1 psi/ft. Page 53 Milne Point Unit M-20 SB Producer Hilcorp Drilling Procedure IM E22 31.0 Spider Plot (NAD 27) (Governmental $ections) _ - A61025509 KUPARUK RIVER UNIT - ' ' A6L355023 __c 11 ADL388235 Sec: 12 Sec6i a0 I `y .F14 ES oI Sec. 14 1 1" \ t-.13 ' ��1 (630) 1 - .Se 1 �'l• 1, r I I 1 a 1L \ i' ♦ I `�� , I g l ,1 • h Y i^ I -7, 7 Y, `l Y 1 I , I , 1 • , ;yam +•'' � , / / 11.403 11 L -3A : JADLoi 'MILE P,�IN 013N009E T�`l1NIT �+,� r 1I , J U013NO10E -------r-ADL025514 'U , .I 5505 . I"igC:l 1 Sec: 24 t Lxirrsl } .. Legend EGbIF1.1DTFFD • MPUM-20_SHL Other Surtace Nolez iSHLj IST KUPARUK ROVER UNI X MPU M-20_TPH Other Bottom Holes (BHL) ADLO25519 Sec. 2[i - - - Other Well Paths _ M.20 '�- MPU M-20_BHL [=Ol and Gas Unli Boundary r —] Pad Foah nnl Milne Point Unit PleelteState Plane Z.4NAD 1927 2 MPU M-20 Well D �.oaD 2.DOD (T�l wp_04 Feet Page 54 n Hil"02 Eevp Cm�poy 32.0 Surface Plat (As Built) (NAD 27) Milne Point Unit M-20 SB Producer Drilling Procedure Page 55 12 -�z-� - THIS PROJECT - M OOSE AD SEC 112 _XC 13 _ ~} _ SCC. 1 SEG 1♦ � I` m�� ■ Y PADS I Y-11 / T I ■ M-13 I v Y -Ix ■ I F� 1` M-14 l I M-20+ I 23 '24s\4I 19 I + M-15 ,' MINE 511E E , M-16 VICINITY MAP I I Ni$ I OF A(gs�9 dbi y�P�E ..•'".a ai 9m ......................... ����%1!°C. Y-04 ■ I U-03 ■ Toroth . BaTAat 10200 MOOSE PAD GRAPHIC SCALE I ' m. (n TT:tT 1 , Rte � 200 K SURVEYOR'S CERTIFICATE LEGEND, NOTES, I HEREBY CERTIFY MAT IAN AS-BULT CaCUCTCfl 1. AtALtA STATE NAME CUXIDMAle3 ARE MRM). ZONE ..SLY MDIFTERE9 AND tK = TO PRACTICE LAND EURICNING IN 2 acO P09TM5 ARE NAMl. THE STATE OF ALASKA AND MAT EY ■ 6Ix51K LCMUCTON 3 8451E CF NCRQCNTAL AND WFVII L O TRX 6 YIADE 6Y K M UNDER 4Y WECT SNJ SIY.D WE SU MSION AND MAT ALL 4. MPU ACOS[ AH PAD SCNE FACTOR M O590MI3 INMfl1BCNS AND O11EA 0`IT.L ME CORRECT AS f REBRUMY 25. 2MW S DATE OF SUR FE■LMY a Mo. 6, REFERENCE FR111 BOOL. HC16-0 K. Lt -TA LOCATED WnNIN PROTRACTED SEC. 14. T. 13 N.. R. 9 E.. UMIAT MERIDIAN. ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC SECTION PAD CELLAR NO. COORDINATES COORDINATES P051T10N OMS P09TION 0.00 OFFSETS ELEVATION BOX EL M-13 Y. 6,027.765.70 N. 1,168.04 7029'12776• 70.4868822' 4,913' FSL 25.0 24.7' X= 533,993.84 E= 1,995.03 149'43'19.766' 149.7221572' 171' FEL Y= 6.027,765.67 N= 1,168.02 70'29'12.780" 70.4868833' 4,913' FSL 250. 24.T M-14 X= 533,903.80 E- 1,904.98 149'43'22.415" 149.7228931' 261' FEL Y. 6,027,765.69 N. 1,16804 7029'12784' 70.4868845' 4.914' FSL 25.1' 24.7' M-15 X. 533,813.87 E= 1,815.05 149'43'25.061• 149.7236281' 351' FEL Y= 6.027.765.37 N= 1,157.73 70'29'12.785' 70.4668847' 4,914' FSL 25.1' 24.9' M-16 X= 533.724AO E= 1,725.26 149'43'27.703" 149.7243619' 441' FEL M-20 Y= 6.027,889.56 N= 1,291.95 70'29'14.001' 70.4872226' 5,037' FSL 25.0' 24.9' X. 533.843.66 E. 1.844.84 149'43'24.168' 149.7233800' 321' FEL bell DurtN I f1111corpAlla AD 19�fli0P MPU MOOSE PAD AS -BUILT CONDUCTORS WELLS 13.14.15.16,20 1 s 1 - Page 55 H Hilcrp .�,2 , Milne Point Unit M-20 SB Producer Drilling Procedure 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs ND MW,PPg 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 1 11111 500 1000 1500 2000 x 2500 3000 3500 4000 4500 Page 56 -MPU L-46 (2015) -MPU L-47 (2015) -MPU L-48 (2015) MPU L-49 (2015) -MPU L-50 (2015) -MPU F-106 (2017) -MPU F-107 (2017) -MPU F-108 (2017) -MPU F-109 (2017) -MPU F-110 (2017) ff Hil TC^ 7- colp F.n Milne Point Unit M-20 SB Producer Drilling Procedure 34.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50 Drill Pipe Configuration Pipe Body OD M 5.000 Poe Body Wall TNdmew co0.362 PipeBody Grade S-135 trillpe LerlgtlrR9nge2 Tool Joint SMYS Connection GPDS50 Tod Joint DD 6.625 Tod Joint ID M 3250 Pin Tong 9 Box Tong m. 12 80 % Inspectm Class Nominal Nominal Weight Designation 19.50 Drill Pipe Approximate Length im 131.5 SmixMiEdge Height 1-r 3132 Raised Tool Joint SMYS (",1120,000 maul 74.100 Upset Type 58,100 lll=ti Max Upset OD (DTE) um 5.125 Friction Factor 11.0 4-0 9.300 nae: TCN sora may nawa nso:aoN. Drill Pipe Performance Drill -Pipe Length Rangel Performance of Drill Pipe with Pipe Body at 80 % InSDOCtlon Class 100 Nominal meth... 2329 0.36 0.0085 0.72 00172 �. rwmmua mur 36,100 Tension Dnly 10 560.600 Drift Size o^1 3.125 w^unae cNmw 32,100 467.400 Note. as moo pakl appals ax uz Wlws Mk: Deli [CC as�Nyvaluex art °CJ (�nnyaa ane Buy vYy p�k 10 ppe b -Hs' m11 bbcalKC, IMertul pa1K Owsinp se otlxr kc1[rs. Connection Performance GPD550 ( 6.625 M) OD X 3.250 (-) ID ) 120,000 (p-) Tool Joint Dimensions Balanced W nn 6.435 eamm�aa Toa.tun ap a r- 5.930 vraaum rl,a nn xala Toa aur iso as 5.93 covpvmrc M Naa to TmMMCOnnec)m ope,aOanal knsk. a WTal)-3T. (IIJOs)s^aWOMaKI t, Tod Jold Torsional Strendh 1eJur 71,890 Tod Jdnt Tensile StremU lLq 1.250,008 Elevator Shoulder Information SmoothEdge Heigh 3132 Raised .0 6.812 Elevator ad 0. 1.658.000 [Assumed Elevator Bore Diameter A5219 Pipe Body Slip Crushing Capacity No jai Iq Sli Crushin Ce � 1°" 498.30 \VI IY/ Assumed Slip Lim 16.5 Transverse Load Factor 1Kl 4-2 Pipe Body Performance Page 57 Elevator OD 3x32 Raised Ea.. Na:: a rasm aa.aw oo moeax akValy ayxap wnwl art yup raxs.y mma. Pipe Body Configuration OD 0.362 (o) Wall S-135) urinal 1 80 % Inspection Class I API Premium Class fat File Body Configuration ( am m •+,�.la,�•i,.n caa wuRa nsm wnnau auionmx 5 (-) OD 0.362(-) Wall S-135) N[h: NOMNI W2 can. -6J' al ma'a RBW rc� ml. Nominal 80 % Inspection Class API Premum Class Pipe 7enslle Straria Iaa M100 560$(10 5601800 Pipe Torsional Strength maul 74.100 58.100 58,100 TJ1PipeBody Torsional natio 0.97 124 124 8D% Pipe Torsional Strength 4-0 9.300 46,500 46.500 Burst torn 17.105 15,638 15,638 Collapse 1Ra1 15.672 10.029 10.029 Pipe OD to5.OD0 4= 4.855 Well Thickness (-,0.362 0.290 0290 Nominal Pipe to to 4276 4.276 4276 ,Cross Sectional Area at Pipe Body i -"n 5275 4.154 4.154 Cross Sectional Area of OD <iea 19.635 18.514 18.514 Cross Sectional Area of ID IM W-2414.360 14.360 14.360 Modulus tw-1 5.708 14.476 4.476 Polar Section Modulus M-3. 11.415 18953 8.953 N[h: NOMNI W2 can. -6J' al ma'a RBW rc� ml. H Hilcorp M-22 Milne Point Unit M-20 SB Producer Drilling Procedure 500204050016200 Weatherford 5" 19.50 Ib/ft S-135 wl NC 50 6-5/8" OD x 3-1/4" ID Tool Joint DRILL PIPE SPECIFICATIONS Grade I S-135 Connection NC 50 Interchangeable With 5' XH & 4-12- IF Upset Type IEU Nominal Weight per Foot 19.50 lbs Adjusted Weight With Tool Joint per Foot 23.08 lbs TOOL JOINT DATA Outside Diameter 6-5/8' Inside Diameter 3-1/4' API Drift 3-1/8' Rabbit OD. Suggested 3-1/16" Minimum Make-up Torque 25.900 ft -lbs Maximum Recommend Make-up Torque 26.800 ft -lbs Torsional Yield Strength 51.700 ft -lbs Tensile Strength 1.269.000 lbs TUBE DATA New Premium Outside Diameter 5.000' 4.855' Inside Diameter 4.276" 4.276' Wall Thickness 0.362" 0.290' Cross Sectional Area 5275 sq in 4.154 sq in Maximum Hook Load/rensile Strength 712.000 lbs 560,800 lbs Slip Crushing / Slip Type (SDXL) 572,100 Itis 453,500 lbs Burst Pressure17.100 psi 16.100 psi Collapse Pressure 15,700 psi 10.000 psi Torsional Yield Stren th 74.100 ft-Ibs 58.100 ft -lbs Capacity W/ Tool Joint 0.726 US aVft 0.726 US aiii Displacement W/ Tool Joint 0.353 US avft 0.322 US allft Excessive heat or pulling when tube is torqued can cause the maximum pull to decrease. Where possible all figures are obtained from OEM data source. NOTE: Weatherford in no way assumes responsibility or liability for any loss, damage or injury resulting from the use of the information listed above. All applications are for guidelines and the data described are at the user's own risk and are the user's responsibility. Page 58 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-20 MPU M-20 Plan: MPU M-20 wp04 Standard Proposal Report 16 May, 2019 HALLIBURTON Sperry Drilling Services I Hi LLIBURTON 8,.—, DAIN.9 f WELL DETARS: Plan: MPU M-20 Ground level: 24.90 +N/ -S +I➢ -W Nn'", ExsanS Laliltude 0.00 0.00 6027889.58 533843.66 70o 29'14,0012N MPU M-20 Wp04 CPI I Sun Dv 44100': 7850' MD, 3847.35TVD End Dir : 7892.33' MD, 3845A5' TVD C 0sAAJ3) Stan Or 4-/100': 11969.84'MD,3602.7T t) End or, : 12031.93' MD, 3600.35' TVD MPU M-20 WpW Tus 'I1.� 3556 Total DepN: 147805'MD, 3555.7 TVD fi 518"xB1A_" MPU M-20 WpIM Lunggmde 149' 43' 24.1681 W Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-20 Wellbore: MPU M-20 Plan: MPU M-20 wp04 REFERENCE INFORMATION Co-oNirete (NSE) Referents: Well Plan: MPU M-20, True NaM Ventral (3V0) Referents: M-20 RKB @ 58.70usfi Measured Depth Referen¢: M-20 RKB 058.Musn Calcula4on Matl Minlmum C..W. CASING DETAILS TVD TVDSS MD Size Name 3908.70 3850.00 5477.60 9-5/8 95/8"x121/4" 3555.70 3497.00 14780.75 6-5/8 6 5/8" x 8 12" 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 West( -)/East(+) (1500 usft/in) A�Sp Start Dir 3'/100': 400' MD, 400TVD 0 35W >sp - Sun Dir 4.25°/100': 600' MD, 599.63TN'D 75p0 3750- _ - - End Dv : 517TOMD, 3882.55'3 Q" Sun Dir 49100' : 5477.6' MD 3908 7WD 9 W x 12114".- - -- End Dir:5645.71'MD,3913.51'TVD M-20 Mal Wp01 MPU M-20 Wp04 CPI I Sun Dv 44100': 7850' MD, 3847.35TVD End Dir : 7892.33' MD, 3845A5' TVD C 0sAAJ3) Stan Or 4-/100': 11969.84'MD,3602.7T t) End or, : 12031.93' MD, 3600.35' TVD MPU M-20 WpW Tus 'I1.� 3556 Total DepN: 147805'MD, 3555.7 TVD fi 518"xB1A_" MPU M-20 WpIM Lunggmde 149' 43' 24.1681 W Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-20 Wellbore: MPU M-20 Plan: MPU M-20 wp04 REFERENCE INFORMATION Co-oNirete (NSE) Referents: Well Plan: MPU M-20, True NaM Ventral (3V0) Referents: M-20 RKB @ 58.70usfi Measured Depth Referen¢: M-20 RKB 058.Musn Calcula4on Matl Minlmum C..W. CASING DETAILS TVD TVDSS MD Size Name 3908.70 3850.00 5477.60 9-5/8 95/8"x121/4" 3555.70 3497.00 14780.75 6-5/8 6 5/8" x 8 12" 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 West( -)/East(+) (1500 usft/in) Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-2 Wellbore: MPU M-20 Design: MPU M-20 wp NALUBURTON ® DDI=7.074 Hi, Naaka. LLC Calalabn MeltedMinimum D-.. Dmr Sylem: ls.sB Xan Met-: Cbeat App -eh On Ort SURem: Pedal Curve Wamng Mated: Error Relio Sec MD A9 ND +NIS +EI -W 1 3360 uuO 0.00 3360 040 0.00 2 40000 0 DO 000 400.00 0.00 0.00 3 60D00 600 10.00 50963 10.30 1.82 4 1756.16 54.90 24 01 1566.87 53430 218.14 5 1986.89 54.90 24.01 1699.54 706.73 294.94 6 597.50 85.00 10345 380265 -107.66 1194.61 7 OUTGO 8500 183AI 3908.70 -405.98 1176,62 8 U4571 91]2 18345 3913.51 -57362 1166.51 9 ]85000 91 2 183.45 384.35 47]2.93 033.92 10 ]892.33 9341 18348 3845,45 3815.14 1031.3] 11 1196964 93.41 103,40 360270 38]].90 784.13 12 12031.93 9093 10340 3600.35 -6939.83 78DM0 13 1470075 90.93 18340 3555.70 -968345 617.35 SECTION DETAILS DIe9 TF.- VSeet a,et 0.00 0.00 0.o0 0.00 0.00 DOD 3.00 1000 -1G.39 425 1519 -546.29 0.00 0.00 -722.98 4.25 150.07 36.62 OOD 0O0 335.48 W20 Heel "Ol 4.00 -0.01 503.43 0.00 000 1706.73 4.OD 1.09 2749.02 0.00 000 6819.29 MPU M-20 wp04 CPI 4.00 -178.13 6881.33 000 ODD 9629.79 MPU M-20.104 To. rn.. To' pEieN6 ea Mn,awmu lr mrE6 CRSWG DETPILS REfERFN[E IxGgtAunON ND MI95 MD Size Neme Coatise Oratl Rereer,u: wax pron: upU M2o. Tw Nwn -75p .7996.]0 995000 54]]60 9516 959'a 121H' w'�16wIR�a"u'µp pl®®y,l a .7555.]0 3d9z.001460.]5 6318 65I6'r Gl? lAa'rot Damp. Dentate: G Wn MCOrh Nrvmundmlun 9518"x12114° d, 0 0 0 M-20 Heel wool Annotation Spent Dir 3"1100': 40V Mo, 49090 Stan Dir 4.25.1100':600' MD, 59363'03➢ EM Dir : 1756.16 MD, 15M8]' TVD Sten Dlr 4.25.11 D6:196689' MD, 1699.5 WD End Dir : 51]7.6 MD, 388255' ND Sent Or 4-1100':54].6' W. 3908.79VD End Dir : 561571' MD. 391351TVD Sun Dir 491D0' 1 7850' MO, 3843SND End Or : 7692OT M0, 3645.45' TVD Sun Dir 4'11 W; 11969.84' MD, 36021TVD End Dir :1203193' MD, 360035' TVD Tout Depth : 14607S MD, 35551 WD WFL.UEIlI Nen:MPUM.N ngg rek 21M ta'aaaa rMO.Nw niwm Dawn. A - 'd uaan. la -4Y N. Date: ath"DGI7 9000 Wlgated: res WaaIM: Cepin Fmm Dwln 70 sun'erlPlex Tnnl 3.790 54]].60 MFI M20 x901 (MPI1 M20) ZMWOHFR2+M5+5 54]]50 1490.]5 MPV M2= uD04(MPM WMj 2 MW0HFR2+MSN^ N Ah hh. o' o' F a' my �� Oy 0 n pg' On OB O Oe t �g h � 6518"x8112" MPU M3D wp06 MPU W20 wo04 CP1 MPU M-20 wp04 Toe -1500 -750 0 750 1500 NEE 3000 3750 4500 5250 6000 6750 7500 8250 GOOD 9750 105N 11250 12000 12750 13500 Ven1081 Section at 183.40° (1500 usfdin) AStan Dir 3-ll0O': 400' MD, 400TVD p Stan 00425°H Do GOV MO. 59963'030 -' End Dir :1758,18' MD, 1586.8]' WD 500C Stan Dir 4.259100' :1986.89' MD, 1699.547 D c_ 750- 50000 coo - -1500 1500 3y-" N z G, { ,$N pda Fl �SeO a AV 2250-. � ^b ti t .. 3000 u N `Otig � 3000- _ 3500 Oti. a Wg 65 g i � 9518"x12114° d, 0 0 0 M-20 Heel wool Annotation Spent Dir 3"1100': 40V Mo, 49090 Stan Dir 4.25.1100':600' MD, 59363'03➢ EM Dir : 1756.16 MD, 15M8]' TVD Sten Dlr 4.25.11 D6:196689' MD, 1699.5 WD End Dir : 51]7.6 MD, 388255' ND Sent Or 4-1100':54].6' W. 3908.79VD End Dir : 561571' MD. 391351TVD Sun Dir 491D0' 1 7850' MO, 3843SND End Or : 7692OT M0, 3645.45' TVD Sun Dir 4'11 W; 11969.84' MD, 36021TVD End Dir :1203193' MD, 360035' TVD Tout Depth : 14607S MD, 35551 WD WFL.UEIlI Nen:MPUM.N ngg rek 21M ta'aaaa rMO.Nw niwm Dawn. A - 'd uaan. la -4Y N. Date: ath"DGI7 9000 Wlgated: res WaaIM: Cepin Fmm Dwln 70 sun'erlPlex Tnnl 3.790 54]].60 MFI M20 x901 (MPI1 M20) ZMWOHFR2+M5+5 54]]50 1490.]5 MPV M2= uD04(MPM WMj 2 MW0HFR2+MSN^ N Ah hh. o' o' F a' my �� Oy 0 n pg' On OB O Oe t �g h � 6518"x8112" MPU M3D wp06 MPU W20 wo04 CP1 MPU M-20 wp04 Toe -1500 -750 0 750 1500 NEE 3000 3750 4500 5250 6000 6750 7500 8250 GOOD 9750 105N 11250 12000 12750 13500 Ven1081 Section at 183.40° (1500 usfdin) HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-20 Wellbore: MPU M-20 Design: MPU M-20 wp04 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M-20 M-20 RKB @ 58.70usft M-20 IRKS @ 58.70usft True Minimum Curvature 'roject Milne Point, ACT, MILNE POINT clap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point clap Zone: Alaska Zone 04 Using geodetic scale factor Site _. M Pt Moose Pad Site Position: From: Map Position Uncertainty: Northing: Easting: 0.00 usft Slot Radius: 6,027,877.65usft Latitude: 533,363.92 usft Longitude: 13-3/16" Grid Convergence: 70° 29'13.9062 N 149'43'38.2855 W 0.26 ° Well Plan: MPU M-20 Well Position +N/ -S 0.00 usft Northing: 6,027,889.58 usft Latitude: 70° 29'14.0012 N +E/ -W 0.00 usft Easting: 533,843.66 usft Longitude: 149° 43'24.1681 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 24.90 usft Wellbore MPU M-20 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) BGGM2018 6/30/2019 16.57 80.96 57,421.87271626 Design MPU M-20 wp04 Audit Notes: Version: Phase: PLAN Tie On Depth: 33.80 Vertical Section: Depth From (TVD) +N/S +E/ -W Direction (usft) (usft) (usft) (") 33.80 0.00 0.00 183.40 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) ("/100usft) (°/100usft) (°/100usft) (°) 33.80 0.00 0.00 33.80 -2490 0.00 0.00 0.00 0.00 0,00 0.00 400.00 0.00 0.00 400.00 341.30 0.00 0.00 0.00 0.00 0.00 0.00 600.00 6.00 10.00 599.63 540.93 10.30 1.82 3.00 3.00 0.00 10.00 1,756.16 54.90 24.01 1,566.87 1.508.17 534.30 218.14 4.25 4.23 1.21 15.19 1,986.89 54.90 24.01 1,699.54 1,640.84 706.73 294.94 0.00 0.00 0.00 0.00 5,177.60 85.00 183.45 3,882.55 3,823.85 -107.66 1,194.61 4.25 0.94 5.00 150.07 5,477.60 85.00 183.45 3,908.70 3,850.00 .405.98 1,176.62 0.00 0.00 0.00 0.00 5,645.71 91.72 183.45 3,913.51 3,854.81 -573.62 1,166.51 4.00 4.00 0.00 -0.01 7,850.00 91.72 183.45 3,847.35 3,788.65 -2,772.93 1,033.92 0.00 0.00 0.00 0.00 7,892.33 93.41 183.48 3,845.45 3,786.75 -2,815.14 1,031.37 4.00 4.00 0.08 1.09 11,969.84 93.41 183.48 3,602.70 3,544.00 -6,877.90 784.13 0.00 0.00 0.00 0.00 12,031.93 90.93 183.40 3,600.35 3,541.65 -6,939.83 780.40 4.00 -4.00 -0.13 -178.13 14,780.75 90.93 183.40 3,555.70 3,497.00 -9,683.45 617.35 0.00 0.00 0.00 0.00 5/162019 1:09:34PM Page 2 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US +CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-20 Wellbore: MPU M-20 Design: MPU M-20 wp04 Planned Survey Measured Vertical Depth Inclination Azimuth Depth TVDss (usft) (1) (1) (usft) usft 33.80 0.00 0.00 33.80 -24.90 100.00 0.00 0.00 100.00 41.30 200.00 0.00 0.00 200.00 141.30 300.00 0.00 0.00 300.00 241.30 400.00 0.00 0.00 400.00 341.30 Start Dir 3%100' : 400' MD, 401 500.00 3.00 10.00 499.95 441.25 600.00 6.00 10.00 599.63 540.93 Start Dir 4.25°1100' : 600' MD, 599.63'TVD 700.00 10.16 16.32 698.62 639.92 800.00 14.37 18.97 796.32 737.62 900.00 18.59 20.44 892.19 833.49 1,000.00 22.83 21.38 985.71 927.01 1,100.00 27.06 22.04 1,076.36 1,017.66 1,200.00 31.30 22.53 1,163.64 1,104.94 1,300.00 35.54 22.91 1,247.09 1,188.39 1,400.00 39.79 23.23 1,326.23 1,267.53 1,500.00 44.03 23.49 1,400.63 1,341.93 1,600.00 48.27 23.71 1,469.89 1,411.19 1,700.00 52.52 23.91 1,533.63 1,474.93 1,756.16 54.90 24.01 1,566.87 1,508.17 End Dir : 1756.16' MD, 1566.87' ND 1,800.00 54.90 24.01 1,592.08 1,533.38 1,900.00 54.90 24.01 1,649.58 1,590.88 1,986.89 54.90 24.01 1,699.55 1,640.85 Start Dir 4.25°1100' : 1986.89' MD, 1699.54'TVD 2,000.00 54.42 24.35 1,707.13 1,648.43 2,100.00 50.77 27.10 1,767.87 1,709.17 2,200.00 47.20 30.15 1,833.49 1,774.79 2,300.00 43.72 33.56 1,903.62 1,844.92 2,400.00 40.36 37.43 1,977.89 1,919.19 2,500.00 37.14 41.87 2,055.88 1,997.18 2,600.00 34.12 46.99 2,137.17 2,078.47 2,700.00 31.34 52.93 2,221.31 2,162.61 2,800.00 28.88 59.84 2,307.83 2,249.13 2,900.00 26.83 67.81 2,396.27 2,337.57 3,000.00 25.29 76.83 2,486.14 2,427.44 3,100.00 24.35 86.70 2,576.94 2,518.24 3,200.00 24.10 97.04 2,668.17 2,609.47 3,300.00 24.53 107.31 2,759.34 2,700.64 3,400.00 25.64 117.00 2,849.95 2,791.25 3,500.00 27.32 125.75 2,939.49 2,880.79 3,600.00 29.48 133.44 3,027.48 2,968.78 3,700.00 32.03 140.09 3,113.43 3,054.73 3,800.00 34.88 145.80 3,196.87 3,138.17 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M-20 M-20 IRKS @ 58.70usft M-20 RKB @ 58.70usft True Minimum Curvature 716.49 299.32 6,028,607.35 534,139.69 Map -732.98 Map 333.75 6,028,679.06 534,173.78 4.25 +Nl-S 854.29 +El -W 6,028,745.46 Northing 4.25 Easting 914.84 DLS Vert Section (usft) 4.25 (usft) 969.37 (usft) 6,028,860.88 (usft) 4.25 -24.90 1,017.59 486.04 0.00 534,325.02 0.00 -1,044.62 6,027,889.58 526.71 533,843.66 534,365.50 0.00 0.00 1,094.05 0.00 6,028,986.09 0.00 4.25 6,027,889.58 1,121.87 533,843.66 6,029,014.10 0.00 0.00 -1,156.05 0.00 651.44 0.00 534,489.83 6,027,889.58 -1,179.16 533,843.66 693.15 0.00 0.00 4.25 0.00 1,161.99 0.00 6,029,054.79 6,027,889.58 4.25 533,843.66 1,160.67 0.00 0.00 534,613.71 0.00 -1,204.62 0.00 815.51 6,027,889.58 534,653.84 533,843.66 -1,198.32 0.00 0.00 6,029,029.33 2.58 4.25 0.45 1,112.74 6,027,892.16 6,029,006.26 533,844.10 4.25 3.00 -2.60 929.05 10.30 534,767.69 1.82 -1,135.59 6,027,899.89 963.96 533,845.43 534,802.76 3.00 -10.39 1,001.11 23.92 6,028,895.11 5.20 4.25 6,027,913.52 533,848.75 4.25 -24.19 44.13 11.72 6,027,933.76 533,855.18 4.25 -44.74 70.81 21.32 6,027,960.48 533,864.66 4.25 -71.95 103.83 33.97 6,027,993.55 533,877.15 4.25 -105.66 143.00 49.58 6,028,032,79 533,892.59 4.25 -145.69 188.10 68.08 6,028,077.97 533,910.88 4.25 -191.81 238.89 89.36 6,028,128.85 533,931.92 4.25 -243.77 295.10 113.31 6,028,185.16 533,955.61 4.25 -301.30 356.40 139.79 6,028,246.58 533,981.81 4.25 -364.06 422.47 168.66 6,028,312.77 534,010.38 4.25 131.72 492.93 199.76 6,028,383.37 534,041.15 4.25 -503.91 534.30 218.14 6,028,424.81 534,059.34 4.25 -546.29 567.06 232.73 6,028,457.64 534,073.78 0.00 -579.86 641.80 266.02 6,028,532.52 534,106.73 0.00 -656.44 706.73 294.94 6,028,597.58 534,135.35 0.00 -722.98 716.49 299.32 6,028,607.35 534,139.69 4.25 -732.98 788.05 333.75 6,028,679.06 534,173.78 4.25 -806.46 854.29 369.83 6,028,745.46 534,209.57 4.25 -874.72 914.84 407.38 6,028,806.17 534,246.84 4.25 -937.39 969.37 446.19 6,028,860.88 534,285.39 4.25 -994.13 1,017.59 486.04 6,028,909.27 534,325.02 4.25 -1,044.62 1,059.22 526.71 6,028,951.08 534,365.50 4.25 -1,088.60 1,094.05 567.99 6,028,986.09 534,406.61 4.25 -1,125.81 1,121.87 609.64 6,029,014.10 534,448.13 4.25 -1,156.05 1,142.53 651.44 6,029,034.95 534,489.83 4.25 -1,179.16 1,155.93 693.15 6,029,048.54 534,531.48 4.25 -1,195.01 1,161.99 734.55 6,029,054.79 534,572.85 4.25 -1,203.51 1,160.67 775.42 6,029,053.65 534,613.71 4.25 -1,204.62 1,151.99 815.51 6,029,045.15 534,653.84 4.25 -1,198.32 1,135.98 854.63 6,029,029.33 534,693.03 4.25 -1,184.67 1,112.74 892.54 6,029,006.26 534,731.04 4.25 -1,163.72 1,082.40 929.05 6,028,976.09 534,767.69 4.25 -1,135.59 1,045.12 963.96 6,028,938.97 534,802.76 4.25 -1,100.45 1,001.11 997.06 6,028,895.11 534,836.06 4.25 -1,058.48 5/162019 1:09:34PM Page 3 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-20 Wellbore: MPU M-20 Design: MPU M-20 wp04 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-20 TVD Reference: M-20 RKB @ 58.70usft MD Reference: M-20 RKB @ 58.70usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,218.64 3,900.00 37.96 150.73 3,277.34 3,218.64 950.60 1,028.18 6,028,844.76 534,867.41 4.25 -1,009.91 4,000.00 41.22 155.01 3,354.41 3,295.71 893.88 1,057.15 6,028,788.17 534,896.63 4.25 -955.00 4,100.00 44.62 158.75 3,427.64 3,368.94 831.26 1,083.82 6,028,725.68 534,923.58 4.25 -894.07 4,200.00 48.12 162.06 3,496.64 3,437.94 763.08 1,108.02 6,028,657.62 534,948.09 4.25 -827.45 4,300.00 51.71 165.03 3,561.02 3,502.32 689.71 1,129.64 6,028,584.35 534,970.03 4.25 -755.49 4,400.00 55.37 167.71 3,620.44 3,561.74 611.56 1,148.54 6,028,506.30 534,989.29 4.25 -678.60 4,500.00 59.08 170.16 3,674.57 3,615.87 529.06 1,164.64 6,028,423.88 535,005.76 4.25 -597.20 4,600.00 62.84 172.43 3,723.10 3,664.40 442.65 1,177.83 6,028,337.55 535,019.35 4.25 -511.73 4,700.00 66.63 174.55 3,765.78 3,707.08 352.83 1,188.05 6,028,247.77 535,029.98 4.25 422.66 4,800.00 70.44 176.55 3,802.37 3,743.67 260.06 1,195.25 6,028,155.05 535,037.59 4.25 -330.49 4,900.00 74.28 178.46 3,832.67 3,773.97 164.88 1,199.37 6,028,059.90 535,042.15 4.25 -235.72 5,000.00 78.13 180.30 3,856.51 3,797.81 67.79 1,200.40 6,027,962.82 535,043.63 4.25 -138.86 5,100.00 82.00 182.09 3,873.77 3,815.07 -30.67 1,198.34 6,027,864.37 535,042.01 4.25 -40.46 5,177.60 85.00 183.45 3,882.55 3,823.85 -107.67 1,194.61 6,027,787.36 535,038.63 4.25 36.63 End Dir : 5177.6' MD, 3882.55' TVD 5,200.00 85.00 183.45 3,884.51 3,825.81 -129.94 1,193.27 6,027,765.08 535,037.39 0.00 58.94 5,300.00 85.00 183.45 3,893.22 3,834.52 -229.38 1,187.27 6,027,665.63 535,031.85 0.00 158.56 5,400.00 85.00 183.45 3,901.94 3,843.24 -328.82 1,181.27 6,027,566.17 535,026.30 0.00 258.18 5,477.60 85.00 183.45 3,908.70 3,850.00 -405.98 1,176.62 6,027,489.00 535,022.00 0.00 335.49 Start Dir 401100' : 5477.6' MD, 3908.7'TVD - 9 5/8" z 12 1/4" 5,500.00 85.90 183.45 3,910.48 3,851.78 428.27 1,175.28 6,027,466.70 535,020.76 4.00 357.82 5,600.00 89.89 183.45 3,914.15 3,855.45 -528.00 1,169.26 6,027,366.96 535,015.20 4.00 457.73 5,645.71 91.72 183.45 3,913.51 3,854.81 -573.62 1,166.51 6,027,321.33 535,012.66 4.00 503.43 End Dir : 5645.71' MD, 3913.51' TVD 5,700.00 91.72 183.45 3,911.88 3,853.18 -627.79 1,163.25 6,027,267.15 535,009.64 0.00 557.70 5,800.00 91.72 183.45 3,908.88 3,850.18 -727.56 1,157.23 6,027,167.36 535,004.08 0.00 657.65 5,900.00 91.72 183.45 3,905.88 3,847.18 -827.34 1,151.22 6,027,067.57 534,998.52 0.00 757.61 6,000.00 91.72 183.45 3,902.87 3,844.17 -927.11 1,145.20 6,026,967.78 534,992.96 0.00 857.56 6,100.00 91.72 183.45 3,899.87 3,841.17 -1,026.89 1,139.19 6,026,867.99 534,987.39 0.00 957.52 6,200.00 91.72 183.45 3,896.87 3,838.17 -1,126.66 1,133.17 6,026,768.20 534,981.83 0.00 1,057.47 6,300.00 91.72 183.45 3,893.87 3,835.17 -1,226.43 1,127.16 6,026,668.41 534,976.27 0.00 1,157.43 6,400.00 91.72 183.45 3,890.87 3,832.17 -1,326.21 1,121.14 6,026,568.62 534,970.71 0.00 1,257.38 6,500.00 91.72 183.45 3,887.87 3,829.17 -1,425.98 1,115.13 6,026,468.83 534,965.15 0.00 1,357.34 6,600.00 91.72 183.45 3,884.87 3,826.17 -1,525.75 1,109.11 6,026,369.04 534,959.59 0.00 1,457.29 6,700.00 91.72 183.45 3,881.86 3,823.16 -1,625.53 1,103.10 6,026,269.25 534,954.03 0.00 1,557.25 6,800.00 91.72 183.45 3,878.86 3,820.16 -1,725.30 1,097.08 6,026,169.46 534,948.47 0.00 1,657.20 6,900.00 91.72 183.45 3,875.86 3,817.16 -1,825.08 1,091.07 6,026,069.67 534,942.91 0.00 1,757.16 7,000.00 91.72 183.45 3,872.86 3,814.16 -1,924.85 1,085.05 6,025,969.88 534,937.35 0.00 1,857.11 7,100.00 91.72 183.45 3,869.86 3,811.16 -2,024.62 1,079.04 6,025,870.09 534,931.79 0.00 1,957.07 7,200.00 91.72 183.45 3,866.86 3,808.16 -2,124.40 1,073.02 6,025,770.30 534,926.23 0.00 2,057.02 7,300.00 91.72 183.45 3,863.85 3,805.15 -2,224.17 1,067.01 6,025,670.51 534,920.67 0.00 2,156.98 7,400.00 91.72 183.45 3,860.85 3,802.15 -2,323.94 1,060.99 6,025,570.72 534,915.11 0.00 2,256.93 7,500.00 91.72 183.45 3,857.85 3,799.15 -2,423.72 1,054.98 6,025,470.93 534,909.55 0.00 2,356.89 7,600.00 91.72 183.45 3,854.85 3,796.15 -2,523.49 1,048.96 6,025,371.14 534,903.99 0.00 2,456.84 7,700.00 91.72 183.45 3,851.85 3,793.15 -2,623.27 1,042.95 6,025,271.35 534,898.43 0.00 2,556.80 5(162019 1:09:34PM Page 4 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US +CANADA Local Co-ordinate Reference: Well Plan: MPU M-20 Company: Hilcorp Alaska, LLC ND Reference: M-20 RKB @ 58.70usft Project: Milne Point MD Reference: M-20 RKB @ 58.70usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-20 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-20 Design: MPU M-20 wp04 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 3,790.15 7,800.00 91.72 183.45 3,848.85 3,790.15 -2,723.04 1,036.93 6,025,171.56 534,892.87 0.00 2,656.75 7,850.00 91.72 183.45 3,847.35 3,788.65 -2,772.93 1,033.92 6,025,121.66 534,890.09 0.00 2,706.73 Start Dir 4°1100' : 7850'13847.35'1 7,892.33 93.41 183.48 3,845.45 3,786.75 -2,815.14 1,031.37 6,025,079.44 534,887.72 4.00 2,749.01 End Dir : 7892.33' MD, 3845.45' TVD 7,900.00 93.41 183.48 3,844.99 3,786.29 -2,822.78 1,030.90 6,025,071.80 534,887.29 0.00 2,756.67 8,000.00 93.41 183.48 3,839.04 3,780.34 -2,922.42 1,024.84 6,024,972.15 534,881.68 0.00 2,856.49 8,100.00 93.41 183.48 3,833.09 3,774.39 -3,022.05 1,018.77 6,024,872.49 534,876.07 0.00 2,956.32 8,200.00 93.41 183.48 3,827.13 3,768.43 -3,121.69 1,012.71 6,024,772.84 534,870.47 0.00 3,056.14 8,300.00 93.41 183.48 3,821.18 3,762.48 -3,221.33 1,006.65 6,024,673.18 534,864.86 0.00 3,155.96 8,400.00 93.41 183.48 3,815.23 3,756.53 -3,320.97 1,000.58 6,024,573.53 534,859.25 0.00 3,255.78 8,500.00 93.41 183.48 3,809.27 3,750.57 -3,420.61 994.52 6,024,473.87 534,853.64 0.00 3,355.61 8,600.00 93.41 183.48 3,803.32 3,744.62 -3,520.25 988.46 6,024,374.22 534,848.03 0.00 3,455.43 8,700.00 93.41 183.48 3,797.37 3,738.67 -3,619.88 982.39 6,024,274.56 534,842.42 0.00 3,555.25 8,800.00 93.41 183.48 3,791.41 3,732.71 -3,719.52 976.33 6,024,174.91 534,836.81 0.00 3,655.07 8,900.00 93.41 183.48 3,785.46 3,726.76 -3,819.16 970.27 6,024,075.25 534,831.20 0.00 3,754.90 9,000.00 93.41 183.48 3,779.51 3,720.81 -3,918.80 964.20 6,023,975.60 534,825.59 0.00 3,854.72 9,100.00 93.41 183.48 3,773.55 3,714.85 -4,018.44 958.14 6,023,875.94 534,819.98 0.00 3,954.54 9,200.00 93.41 183.48 3,767.60 3,708.90 -4,118.08 952.08 6,023,776.29 534,814.37 0.00 4,054.36 9,300.00 93.41 183.48 3,761.65 3,702.95 -4,217.71 946.01 6,023,676.63 534,808.76 0.00 4,154.19 9,400.00 93.41 183.48 3,755.69 3,696.99 -4,317.35 939.95 6,023,576.98 534,803.15 0.00 4,254.01 9,500.00 93.41 183.48 3,749.74 3,691.04 4,416.99 933.89 6,023,477.32 534,797.54 0.00 4,353.83 9,600.00 93.41 183.48 3,743.79 3,685.09 -4,516.63 927.82 6,023,377.67 534,791.93 0.00 4,453.65 9,700.00 93.41 183.48 3,737.83 3,679.13 4,616.27 921.76 6,023,278.01 534,786.32 0.00 4,553.48 9,800.00 93.41 183.48 3,731.88 3,673.18 -4,715.91 915.70 6,023,178.36 534,780.72 0.00 4,653.30 9,900.00 93.41 183.48 3,725.93 3,667.23 -4,815.54 909.63 6,023,078.70 534,775.11 0.00 4,753.12 10,000.00 93.41 183.48 3,719.97 3,661.27 -4,915.18 903.57 6,022,979.05 534,769.50 0.00 4,852.94 10,100.00 93.41 183.48 3,714.02 3,655.32 -5,014.82 897.51 6,022,879.39 534,763.89 0.00 4,952.77 10,200.00 93.41 183.48 3,708.07 3,649.37 -5,114.46 891.44 6,022,779.74 534,758.28 0.00 5,052.59 10,300.00 93.41 183.48 3,702.11 3,643.41 -5,214.10 885.38 6,022,680.08 534,752.67 0.00 5,152.41 10,400.00 93.41 183.48 3,696.16 3,637.46 -5,313.74 879.32 6,022,580.43 534,747.06 0.00 5,252.23 10,500.00 93.41 183.48 3,690.21 3,631.51 -5,413.37 873.25 6,022,480.77 534,741.45 0.00 5,352.06 10,600.00 93.41 183.48 3,684.25 3,625.55 -5,513.01 867.19 6,022,381.12 534,735.84 0.00 5,451.88 10,700.00 93.41 183.48 3,678.30 3,619.60 -5,612.65 861.13 6,022,281.46 534,730.23 0.00 5,551.70 10,800.00 93.41 183.48 3,672.35 3,613.65 -5,712.29 855.06 6,022,181.81 534,724.62 0.00 5,651.52 10,900.00 93.41 183.48 3,666.39 3,607.69 -5,811.93 849,00 6,022,082.15 534,719.01 0.00 5,751.35 11,000.00 93.41 183.48 3,660.44 3,601.74 -5,911.57 842.93 6,021,982.50 534,713.40 0.00 5,851.17 11,100.00 93.41 183.48 3,654.49 3,595.79 -6,011.20 836.87 6,021,882.84 534,707.79 0.00 5,950.99 11,200.00 93.41 183.48 3,648.53 3,589.83 -6,110.84 830.81 6,021,783.19 534,702.18 0.00 6,050.81 11,300.00 93.41 183.48 3,642.58 3,583.88 -6,210.48 824.74 6,021,683.53 534,696.57 0.00 6,150.64 11,400.00 93.41 183.48 3,636.62 3,577.92 -6,310.12 818.68 6,021,583.88 534,690.96 0.00 6,250.46 11,500.00 93.41 183.48 3,630.67 3,571.97 -6,409.76 812.62 6,021,484.22 534,685.36 0.00 6,350.28 11,600.00 93.41 183.48 3,624.72 3,566.02 -6,509.39 806.55 6,021,384.56 534,679.75 0.00 6,450.10 11,700.00 93.41 183.48 3,618.76 3,560.06 -6,609.03 800.49 6,021,284.91 534,674.14 0.00 6,549.93 11,800.00 93.41 183.48 3,612.81 3,554.11 -6,708.67 794.43 6,021,185.25 534,668.53 0.00 6,649.75 5/16/2019 1:0934PM Page 5 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-20 Wellbore: MPU M-20 Design: MPU M-20 wp04 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-20 TVD Reference: M-20 RKB @ 58.70usft MD Reference: M-20 RKB @ 58.70usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Map Vertical Map Depth Inclination Azimuth Depth TVDss +N/ -S (usft) V) (1) (usft) usft (usft) 11,900.00 93.41 183.48 3,606.86 3,548.16 -6,808.31 11,969.84 93.41 183.48 3,602.70 3,544.00 -6,877.90 Start Dir 40N00' : 11969.84' MD, 3602.7'TVD 6,021,016.00 12,000.00 92.21 183.44 3,601.22 3,542.52 -6,907.97 12,031.93 90.93 183.40 3,600.35 3,541.65 -6,939.83 End Dir : 12031.93' MD, 3600.35' TVD 6,020,954.06 12,100.00 90.93 183.40 3,599.24 3,540.54 -7,007.77 12,200.00 90.93 183.40 3,597.62 3,538.92 -7,107.58 12,300.00 90.93 183.40 3,595.99 3,537.29 -7,207.39 12,400.00 90.93 183.40 3,594.37 3,535.67 -7,307.20 12,500.00 90.93 183.40 3,592.74 3,534.04 -7,407.01 12,600.00 90.93 183.40 3,591.12 3,532.42 -7,506.82 12,700.00 90.93 183.40 3,589.50 3,530.80 -7,606.63 12,800.00 90.93 183.40 3,587.87 3,529.17 -7,706.44 12,900.00 90.93 183.40 3,586.25 3,527.55 -7,806.25 13,000.00 90.93 183.40 3,584.62 3,525.92 -7,906.06 13,100.00 90.93 183.40 3,583.00 3,524.30 -8,005.87 13,200.00 90.93 183.40 3,581.37 3,522.67 -8,105.68 13,300.00 90.93 183.40 3,579.75 3,521.05 -8,205.50 13,400.00 90.93 183.40 3,578.13 3,519.43 -8,305.31 13,500.00 90.93 183.40 3,576.50 3,517.80 -8,405.12 13,600.00 90.93 183.40 3,574.88 3,516.18 -8,504.93 13,700.00 90.93 183.40 3,573.25 3,514.55 -8,604.74 13,800.00 90.93 183.40 3,571.63 3,512.93 -8,704.55 13,900.00 90.93 183.40 3,570.01 3,511.31 -8,804.36 14,000.00 90.93 183.40 3,568.38 3,509.68 -8,904.17 14,100.00 90.93 183.40 3,566.76 3,508.06 -9,003.98 14,200.00 90.93 183.40 3,565.13 3,506.43 -9,103.79 14,300.00 90.93 183.40 3,563.51 3,504.81 -9,203.60 14,400.00 90.93 183.40 3,561.88 3,503.18 -9,303.41 14,500.00 90.93 183.40 3,560.26 3,501.56 -9,403.22 14,600.00 90.93 183.40 3,558.64 3,499.94 -9,503.03 14,700.00 90.93 183.40 3,557.01 3,498.31 -9,602.84 14,780.75 90.93 183.40 3,555.70 3,497.00 -9,683.44 Total Depth : 14780.75' MD, 3555.7' TVD - 6 518" x 8112" 5/162019 1:09:34PM Page 6 COMPASS 5000.15 Build 91 Map Map +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) 3,548.16 788.36 6,021,085.60 534,662.92 0.00 6,749.57 784.13 6,021,016.00 534,659.00 0.00 6,819.29 782.31 6,020,985.93 534,657.32 4.00 6,849.41 780.40 6,020,954.06 534,655.56 4.00 6,881.33 776.37 6,020,886.11 534,651.83 0.00 6,949.39 770.43 6,020,786.28 534,646.35 0.00 7,049.38 764.50 6,020,686.46 534,640.88 0.00 7,149.36 758.57 6,020,586.63 534,635.40 0.00 7,249.35 752.64 6,020,486.80 534,629.92 0.00 7,349.34 746.71 6,020,386.98 534,624.44 0.00 7,449.32 740.77 6,020,287.15 534,618.97 0.00 7,549.31 734.84 6,020,187.32 534,613.49 0.00 7,649.30 728.91 6,020,087.50 534,608.01 0.00 7,749.28 722.98 6,019,987.67 534,602.53 0.00 7,849.27 717.05 6,019,887.84 534,597.06 0.00 7,949.26 711.12 6,019,788.02 534,591.58 0.00 8,049.24 705.18 6,019,688.19 534,586.10 0.00 8,149.23 699.25 6,019,588.36 534,580.63 0.00 8,249.22 693.32 6,019,488.53 534,575.15 0.00 8,349.20 687.39 6,019,388.71 534,569.67 0.00 8,449.19 681.46 6,019,288.88 534,564.19 0.00 8,549.18 675.52 6,019,189.05 534,558.72 0.00 8,649.16 669.59 6,019,089.23 534,553.24 0.00 8,749.15 663.66 6,018,989.40 534,547.76 0.00 8,849.14 657.73 6,018,889.57 534,542.29 0.00 8,949.12 651.80 6,018,789.75 534,536.81 0.00 9,049.11 645.86 6,018,689.92 534,531.33 0.00 9,149.10 639.93 6,018,590.09 534,525.85 0.00 9,249.09 634.00 6,018,490.27 534,520.38 0.00 9,349.07 628.07 6,018,390.44 534,514.90 0.00 9,449.06 622.14 6,018,290.61 534,509.42 0.00 9,549.05 617.35 6,018,210.00 534,505.00 0.00 9,629.78 5/162019 1:09:34PM Page 6 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Pfan: MPU M-20 Wellbore: MPU M-20 Design: MPU M-20 wp04 Targets Target Name Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-20 TVD Reference: M-20 IRKS Q 58.70usft MD Reference: M-20 IRKS @ 58.70usft North Reference: True Survey Calculation Method: Minimum Curvature -hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing -Shape (1) (1 (usft) (usft) (usft) (usft) M-20 Heel wp01 -1.66 183.45 3,908.70 -405.98 1,176.62 6,027,489.00 - plan hits target center - Circle (radius 50.00) MPU M-20 wp04 CP1 - plan hits target center - Point MPU M-20 wp04 Toe - plan hits target center - Point Easting (usft) 535,022.00 0.00 0.00 3,602.70 -6,877.90 784.13 6,021,016.00 534,659.00 0.00 0.00 3,555.70 -9,683.45 617.35 6,018,210.00 534,505.00 Casing Points Hole Measured Vertical Depth Depth (usft) (usft) Name 5,477.60 3,908.70 9 5/8" x 12 1/4" 14,780.75 3,555.70 6 5/8" x 8 1/2" Plan Annotations Comment Casing Hole Diameter Diameter 9-5/8 12-1/4 6-5/8 8-1/2 Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 400.00 400.00 0.00 0.00 Start Dir 30/100': 400' MD, 400'TVD 600.00 599.63 10.30 1.82 Start Dir 4.250/100': 600' MD, 599.63'1 VD 1,756.16 1,566.87 534.30 218.14 End Dir : 1756.16' MD, 1566.87' TVD 1,986.89 1,699.55 706.73 294.94 Start Dir4.25°/100' : 1986.89' MD, 1699.54'TVD 5,177.60 3,882.55 -107.67 1,194.61 End Dir : 5177.6' MD, 3882.55' TVD 5,477.60 3,908.70 -405.98 1,176,62 Start Dir 40/100': 5477.6' MD, 3908.7'TVD 5,645.71 3,913.51 -573.62 1,166.51 End Dir : 5645.71' MD, 3913.51' TVD 7,850.00 3,847.35 -2,772.93 1,033.92 Start Dir 4°/100' : 7850' MD, 3847.35'TVD 7,892.33 3,845.45 -2,815.14 1,031.37 End Dir : 7892.33' MD, 3845.45' TVD 11,969.84 3,602.70 -6,877.90 784.13 Start Dir40/100' : 11969.84' MD, 3602.7'TVD 12,031.93 3,600.35 -6,939.83 780.40 End Dir : 12031.93' MD, 3600.35' TVD 14,780.75 3,555.70 -9,683.44 617.35 Total Depth : 14780.75' MD, 3555.7' TVD 5/162019 1:09:34PM Page 7 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-20 MPU M-20 MPU M-20 wp04 Sperry Drilling Services Clearance Summary Anticollision Report 16 May, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference Reference Design: M Pt Moose Pad - Plan', MPU M-20 - MPU M-20 - MPU M-20 wp04 Well Coordinates: 6,027,889.50 N, 533,843.66 E (]0° 29' 14.00" N, 149° 43' 24.17' W) Datum Height: M-20 ERB @ 58.70usft Scan Range: 33.70 to 5,477.60 ash. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: Scan Type: 2500 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M-20 - MPU M-20 wp04 Hilcorp Alaska, LLC Milne Point Closest Approach 30 Proximity Scan on Current Survey Data (North Reference) Reference Design: MPt Moose Pad - Plan: MPU M -20 -MPU M-20- MPU M-20 wp04 Scan Range: 33.70 to 5,477.60 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation Is 1,500.00 ash, Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (".it) (usft) usft M Pt L Pad M Pt M Pad M Pt Moose Pad MPU M-11 - MPU M-11 - MPU M-11 540.69 175.21 540.69 171.04 539.58 41.953 Centre Distance Pass - MPU M-11 - MPU MAH - MPU M-11 558.70 175.25 558.70 170.95 556.65 40.775 Ellipse Separation Pass - MPU M-11 - MPU M-11 -MPU M-11 4,008.70 923.37 4,008.70 881.44 3,46221 22.022 Clearance Factor Pass - MPU M -I2- MPU M -I2- MPU M-12 406.95 87.62 406.95 83.58 407.45 21.652 Centre Distance Pass - MPU M -I2- MPU M -I2- MPU M-12 433.70 87,75 433.70 83.48 433.26 20.517 Ellipse Separation Pass - MPU M -I2- MPU M -I2- MPU M-12 4,883.70 242.67 4,883.70 203.11 3,980.00 6.134 Clearance Factor Pass- MPUM-I2- MPU M-12PB1- MPU M-12PB1 406.95 87.62 406.95 83.58 407.45 21.652 Centre Distance Pass - MPU M-12- MPU M-12PB1 -MPU M-12PB1 433.70 87.75 433.70 83.48 433.26 20.517 Ellipse Separation Pass - MPU M -I2- MPU M-12PB1-MPU M-12PB1 4,883.70 242.67 4,883.70 203.11 3,980.00 6.134 Clearance Factor Pass - MPU M -I2- MPU M-12PS2-MPU M-12PB2 406.95 87.62 406.95 83.58 407.45 21.652 Centre Distance Pass - MPU MA2- MPU M-12PB2- MPU M-12PB2 433.70 87.75 433.70 83.48 433.26 20.517 Ellipse Separation Pass - MPU M -I2- MPU M-12PB2- MPU M-12PB2 4,883.70 242.67 4,883.70 203.11 3,980.00 6.134 Clearance Factor Pass- MPU W14- MPU M -I4- MPU M-14 186.33 137.65 186.33 135.82 186.41 75.453 Centre Distance Pass - MPU M -I4- MPU M -I4- MPU M-14 308.70 137.93 308.70 135.24 308.02 51.133 Ellipse Separation Pass - MPU M -I4- MPU M -I4- MPU M-14 5,477.60 1,089.30 5,477.60 1,048.86 3,793.62 26.939 Clearance Factor Pass - MPU M-16- MPU M -I6- MPU M-16 58.70 172.47 58.70 17143 58.39 165.109 Ellipse Separation Pass - MPU M -I6- MPU M -I6- MPU M-16 733.70 213.86 733.70 208.34 715.19 38]65 Clearance Factor Pass- Option 41 Proposal KupS3-Slot 13-60deg Sail Doe! 261.42 380.34 261.42 377.81 261.42 150.741 Centre Distance pass - Option #1Proposal: KupS3-Slot 13-60deg Sail Doe: 358.70 38068 358.70 377.41 355.36 116.508 Ellipse Separation Pass - Option #1 Proposal: KupS3-Slot 13-60deg Sail Doe: 80.70 463.27 883.70 453.13 809.10 45.706 Clearance Factor Pass - Option #1 Proposal: MPUM-19i P2-SIot27-M-19iP 283.70 194.11 283.70 191.42 279.70 72.182 Centre Distance Pass - Option #1 Proposal: MPU M-1 9i P2- Slot 27-M-19iP 333.70 19431 333.70 191.28 328.08 64.089 Ellipse Separation Pass - Option #1 Proposal :MPU M -19i P2- Slot 27-M-19iP 708.70 237.23 708.70 231.58 676.28 41.945 Clearance Factor Pass - 16 May, 2019 - 13:04 Page 2 of 8 COMPASS HALLIBURTON Hllcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M-20 - MPU M-20 wp04 MPU M-12 P2 -M107 Phase 2-M-12 p2 wp02 333.70 120.35 Closest Approach 30 Proximity Scan on Current Survey Data (North Reference) 116.86 333.70 34.443 Centre Distance Pass - Reference Design: M Pt Moose Pad - Plan: MPU M-20 - MPU M-20 - MPU M-20 wp04 MPU M-12 P2 -M107 Phase 2-M-12 p2 wp02 358.70 12840 358.70 Scan Range: 33.70 to 5,477.60 usft. Measured Depth. 358.13 32.796 Ellipse Separation Pass - Plan: Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft M-12 P2 -M107 Phase 2-M-12 p2 wP02 5,183.70 502.74 5,183.70 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Plan :MPUM-13i-M-13i-M-131wp03 Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name- Wellbore Name -Design (u -ft) (usft) (usft) (usft) ..it Plan: MPU Option#1: MPU M -23i -Slot 22 - M -23i - M-231 wP03 383.70 239.68 383.70 236.48 383.70 74.741 Centre Distance Pass - Option #1: MPU M -23i -Slot 22 - M-231 - M -23i wp03 483.70 240.00 483.70 236.08 483.67 61.205 Ellipse Separation Pass - Option #1: MPU M -23i -Slot 22 - M -23i - M -23i wp03 908.70 280.28 908.70 27353 879.40 41.513 Clearance Factor Pass - Plan: MPU M-111 P2 - M1116 Phase2 - M -11i P2 op02 261.42 210.36 261.42 207.39 261.42 70.686 Centre Distance Pass - Plan :MPU M -11i P2 -M106 Phase2-MAN P2 wp02 308.70 210.46 308.70 207.15 307.21 63.600 Ellipse Separation Pass - Plan: MPU M -11i P2 -M106 Phase2-M-11i P2 wp02 5,4P.60 1,33263 5,477.60 1,287.73 3,740.31 29.680 Clearance Factor Pass - Plan: MPU M-12 P2 -M107 Phase 2-M-12 p2 wp02 333.70 120.35 333.70 116.86 333.70 34.443 Centre Distance Pass - Plan: MPU M-12 P2 -M107 Phase 2-M-12 p2 wp02 358.70 12840 358.70 116.73 358.13 32.796 Ellipse Separation Pass - Plan: MPU M-12 P2 -M107 Phase 2-M-12 p2 wP02 5,183.70 502.74 5,183.70 462.66 3,920.21 12.546 Clearance Factor Pass - Plan :MPUM-13i-M-13i-M-131wp03 383.70 194.70 383.70 190.91 383.40 51.386 Centre Distance Pass - Plan: MPU M -13i -M -131 -M -13i wp03 433.70 194.85 433.70 190.65 433.40 46.394 Ellipse Separation Pass - Plan: MPUM-13i-M-1N-M-131 wp03 5,477.60 496.35 5,477.60 464.61 3,900.00 15.638 Clearance Factor Pass - Plan: MPU M -13i P2 - M-13 Phase 2- M-1 3i P2 Wp02 383.70 172.51 383.70 168.66 383.70 44.776 Centre Distance Pass - Plan: MPU M-1 3i P2 -1-13 Phase 2, M-1 3i P2 wp02 433.70 172.68 433.70 168.47 433.70 41.010 Ellipse Separation Pass - Plan :MPUM-131P2-M-13Phase2-M-13i P2wp02 5,477.60 571.99 5,477.60 536.62 3,866.97 16.171 Clearance Factor Pass - Plan: MPU M-14 P2 -M-/4 Phase2-M-14 P2 wp02 261.42 153.09 261.42 150.12 261.42 51.443 Centre Distance Pass - Plan :MPU M-14 P2 -M-14 Phase2-M-14 P2 Wp02 283.70 153.10 283.70 149.96 283.45 48.846 Ellipse Separation Pass - Plan :MPU M-14 P2 -M-14 Phase2-M-14 P2 wp02 5,477.60 1,295.50 5,477.60 1,255.02 3,821.02 32.002 Clearance Factor Pass- Plan : MPU M -15i - M -15i - WIN wp04 383.70 127.43 383.70 123.80 383.40 35.100 Cenbe Distance Pass - Plan: MPU M -15i - M -15i - M -15i wp04 408.70 127.45 408.70 123.63 408.40 33.321 Ellipse Separation Pass - Plan: MPU M -15i - M -15i - M -15i wp04 658.70 14996 658]0 144.20 648.65 26.032 Clearance Factor Pass - Plan: MPU M -15i P2 - MA5 Phase 2 - W15i P2 wp02 361.42 123.59 361.42 119.90 361.42 33.467 Centre Distance Pass - Plan: MPU M-1 5i P2 - M-15 Phase 2 - M-1 5i P2 wp02 383.70 123.60 383.70 119.74 383.49 32.092 Ellipse Separation Pass - Plan :MPUM-151P2-M-15Phase2-M-151P2wp02 583.70 141.83 583.70 136.61 570.41 27.160 Clearance Factor Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 383.70 152Z9 383.70 148.84 383.70 39.633 Centre Distance Pass - Plan: MPU M-16 P2 -M-16 Phase 2- MPU M-16 P2 408.70 152.72 408.70 148.69 408.38 37.900 Ellipse Separation Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 658.70 178.66 658.70 172AI) 643.45 31.011 Clearance Factor Pass - Plan :MPUM-17i-MPUM-17i-MPUM-17wp04 383.70 243.68 383.70 240.26 383.70 71.245 Centre Distance Pass - Plan: MPU M-1 7i - MPU M-171 - MPU M-17 wp04 408.70 243.70 408.70 240.10 408.60 67.737 Ellipse Separation Pass - Plan: MPU M-1 7i - MPU M -17i - MPU M-17 wp04 808.70 293.10 808.70 286.72 781.66 45.933 Clearance Factor Pass - 16 May, 2019 - 13.04 Page 3 of a COMPASS Hilcorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU M-20 - MPU M-20 wp04 MPU M -19i P2 -M-191 P2 -M -19i P2 wpW 283.70 380.34 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 377.65 279.70 141.435 Centre Distance Pass - Reference Design: MPt Moose Pad - Plan: MPU M-20- MPU M-20- MPU M-20 wp04 M -19i P2 -M -19i P2 -M -19i P2 wp02 333.70 380.53 333.70 Scan Range: 33.70 W 5,477.60 usft. Measured Depth. 326.71 125.733 Ellipse Separation Pass - Plan: MPU M -19i P2-Wa P2 -M-191 P2 wp02 Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 462.38 800.00 69.291 Clearance Factor Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on 519.23 Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (.sit) (usft) (usft) (usft) usft Ellipse Separation Pass - Plan: MPU M-171 P2 -M112 Phase 2 -M -17i P2 Wp02 261.42 218.08 261.42 215.10 261.42 73.280 Centre Distance Paw - Plan :MPU M -17i P2 -M112 Phase 2 -M -17i P2 Wp02 333.70 218.26 333.70 214.78 332.22 62.756 Ellipse Separation Pass - Plan: MPU M -1 7i P2- M112 Phase 2- M-17iP2 Wp02 733.70 263.78 733.70 257.49 703.09 41.951 Clearance Factor Pass - Plan: MPU M -I8- MPU M -I8- MPU M-18 wp08 383.70 269.97 383.70 266.55 383.60 78.937 Centre Distance Pass - Plan :MPU M -I8- MPU M -I8- MPU M-18 wp08 433.70 270.15 433.70 266.37 433.60 71.507 Ellipse Separation Pass - Plan: MPU M -IB- MPU M -I8- MPU M-18 wp08 833.70 325.35 833.70 318.83 800.00 49.912 Clearance Factor Pass - Plan : MPU M-18 P2 -M-18 P2- M-18 P2 Wp03 283.70 296.66 283.70 293.97 279.70 110.318 Centre Distance Pass - Plan: MPU M-18 P2 -M-18 P2- M-18 P2 cp03 333.70 296.81 333.70 293.78 327.85 97.943 Ellipse Separation Pass - Plan:MPU M-18 P2 -M-18 P2 -M-18 P2 W903 833.70 369.05 833.70 362.56 773.17 56.806 Clearance Factor Pass - Plan: MPU M -19i- MPU M -19i -Jab Stuart - MPU M-1 383.70 352.42 383.70 349.02 379.70 103.470 Centre Distance Pass - Plan: MPU M -19i- MPU M -19i -Jab Stuart - MPU M-1 433.70 352.57 433.70 348.81 429.70 93.676 Ellipse Separation Pass - Plan :MPUM-19i-MPUM-19i-Jeb Stuart-MPUM-1 958.70 440.86 958.70 433.50 900.00 59.872 Clearance Factor Pass - PIan: MPU M -19i P2 -M-191 P2 -M -19i P2 wpW 283.70 380.34 283.70 377.65 279.70 141.435 Centre Distance Pass - Plan :MPU M -19i P2 -M -19i P2 -M -19i P2 wp02 333.70 380.53 333.70 377.51 326.71 125.733 Ellipse Separation Pass - Plan: MPU M -19i P2-Wa P2 -M-191 P2 wp02 883.70 469.15 883.70 462.38 800.00 69.291 Clearance Factor Paas - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 519.23 29.93 519.23 25.11 519.03 6.211 Centre Distance Pass - Plan :MPU M-20 P2 -M-20 Phase 2-M-20 P2 wp03 533.70 29.96 533.70 25.04 533.39 6.088 Ellipse Separation Pass - Plan :MPU M-20 P2 -M-20 Phase 2-M-20 P2 wp03 5,477.60 148.96 5,477.60 109.99 4,846.66 3.822 Clearance Factor Pass- Plan: MPU M -21i - M -21i - M -21i cP02 383.70 89.85 383.70 86.43 383.70 26.269 Centre Distance Few - Plan; MPU M -21i- Wit -W21i Wp02 633.70 91.00 633.70 85.79 636.44 17.482 Ellipse Separation Pass - Plan: MPU M -21i -M -211 -M -21i Wp02 1,058.70 111.84 1,05870 103.57 1,073.57 13.524 Clearance Factor Pass - Plan: MPU M -21i P2 -M -21i Phase 2 -M -21i P2 wp02 383.70 119.67 383.70 115.82 383.70 31.062 Centre Distance Pass - Plan: MPU W21i P2 - M-211 Phase 2-M-211 P2 Wp02 533.70 120.21 533.70 115.29 534.28 24.425 Ellipse Separation Pass - Plan :MPU M-211 P2 -M -21i Phase 2 -M -21i P2 wp02 1,158.70 16049 1,158.70 150.36 1,166.18 16.306 Clearance Factor Pass- Plan: MPU M -22 -M -22-M-22 wp02 383.70 179.73 383.70 176.15 383.70 50.248 Centre Distance Pass - Plan :MPU M -22 -M -22-M-22 wp02 433.70 179.83 433.70 175.85 433.14 45.131 Ellipse Separation Pass - Plan: MPU M-22 - M-22 - M-22 wp02 908.70 211.42 908.70 203.43 902.85 26.477 Clearance Factor Pass - Plan: MPU M-22 P2 -M-22 Phase 2-M-22 P2 wp02 335.92 209.68 335.92 206.17 335.92 59.736 Centre Distance Pass - Plan: MPU M-22 P2 -M-22 Phase 2-M-22 P2 Wp02 383.70 209.78 383.70 205.93 382.46 54.519 Ellipse Separation Pass - Plan: MPU M-22 P2 -M-22 Phase 2-M-22 P2 wp02 933.70 268.45 933.70 260.69 900.00 34.594 Clearance Factor Pass - 16 May, 2019 - 13:04 Page 4 of a COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M-20 - MPU M-20 wp04 383.70 149.68 383.70 146.25 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 43.760 Centre Distance Pass - Plan: MPU M-58(IRA)-Slot 28- IRA- M-XX-wp021R 483.70 149.99 Reference Design: M Pt Moose Pad- Plan: MPU M-20 -MPU M-20 -MPU M-20 wpal 145.86 483.67 36.276 Ellipse Separation Pass - Plan: MPU M-58(IRA)-Slot 28- IRA -M-XX-wp021R Scan Range: 33.70 to 5,477.60 usft. Measured Depth. 176.43 858.70 169.61 852.85 25.860 Clearance Factor Scan Radius is Unlimited, Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usfl Proposal: NlKuparukfrom Slot 34 -Slot 10-Kup N1 261.42 5967 261.42 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on 358.70 Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usftl usft 69.55 677.82 Plan: MPU M -27 -M -27-M-27"02 383.70 243,96 383.70 240.61 364.00 72.278 Centre Distance Pass - Plan: MPU M -27 -M -27-M-27 wp02 433.70 244.09 433.70 240.35 414.00 65.380 Ellipse Separation Pass - Plan :MPU M -27 -M -27-M-27 wp02 4,608.70 900.04 4,608.70 848.30 5,332.19 17.396 Clearance Factor Pass - Plan, MPU M-57(SMGO)Slot 36 -Slot 10-M-57 SMC 383.70 29.67 383.70 26.26 373.00 8.705 Centre Distance Pass - Plan: MPU M-57 (SMGO) Slot 36 - Slot 10 - M-57 SMC 458.70 29.82 458.70 25.88 447.99 7.561 Ellipse Separation Pass - Plan: MPU M-67(SMGO)Slot 36 -Slot 10-M-57 SMC 608.70 33.40 608.70 28.38 597.58 6.661 Clearance Factor Pass - Plan; MPU M-58(IRA) - Slot 28- IRA -M-XX-wp021R 383.70 149.68 383.70 146.25 383.70 43.760 Centre Distance Pass - Plan: MPU M-58(IRA)-Slot 28- IRA- M-XX-wp021R 483.70 149.99 483.70 145.86 483.67 36.276 Ellipse Separation Pass - Plan: MPU M-58(IRA)-Slot 28- IRA -M-XX-wp021R 858.70 176.43 858.70 169.61 852.85 25.860 Clearance Factor Pass - Proposal: NlKuparukfrom Slot 34 -Slot 10-Kup N1 261.42 5967 261.42 57.12 261.42 23.457 Centre Distance Pass - Proposal. NlKuparukfrom Slot 34 -Slot 10-Kup N1 358.70 59.99 358.70 56.75 358.20 18.528 Ellipse Separation Pass - Pmposal:NlKuparukfrom Slot 34 -Slot 10-Kup N1 683.70 75.08 683.70 69.55 677.82 13.580 Clearance Factor Pass- Slot 42-Placeholder-Slot 42-Placeholder-Slot 42- 591.99 59.59 591.99 54.69 553.96 12.155 Centre Distance Pass - Slot 42-Placeholtler-Slot 42-Placelwlder-Slot 42- 658.70 59.87 658.70 54.49 620.17 11.135 Ellipse Separation Pass - Slot 42-Placeholder-Slot 42-Placeholtler-Slot 42- 783.70 64.91 783.70 58.64 742.81 10.345 Clearance Factor Pass - Slot 46-Placeholtler-Slot 46-Placeholder-Slot 46- 760.18 117.23 760.18 111.13 719.91 19.221 Centre Distance Pass - Slot 46-Placeholder-Slot 46-Placeholder-Slot 46- 783.70 117.33 783.70 111.06 742.81 18.720 Ellipse Separation Pass - Slot 46-Placeholder-Slot 46-Placeholtler-Slot 46- 933.70 125.70 933.70 118.33 886.29 17.050 Clearance Factor Pass- Slot 52-Placeholder-Slot 52-Placeholtler-Slot 52- 894.58 202.09 894.58 195.01 849.35 28.555 Centre Distance Pass - Slot 52-Placeholder-Slot 52-Placeholder-Slot 52- 908.70 202.13 908.70 194.95 862.73 28.145 Ellipse Separation Pass - Slot 52-Placeholder-Slot 52-Placeholder-Slot 52- 1,058.70 210.27 1,058.70 201.95 1,000.00 25246 Clearance Factor Pass - Slot 58-Placeholder-Slot 58-Placeholder-Slot 58- 997.56 286.20 997.56 278.35 945.76 36.430 Centre Distance Pass - Slot 58-Placeholder-Slot 58-Placeholder-Slot 58- 1,008.70 286.23 1,008.70 278.29 956.01 36.035 Ellipse Separation Pass - Slot 58-Placeholder-Slot 58-Placeholder-Slot 58- 1,083.70 289.24 1,083.70 280.81 1,000.00 34.286 Clearance Factor Pa. - 16 May, 2019 - 13:04 Page 5 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-20 - MPU M-20 wp04 Survey fool matnam From To SurveylPlan Survey Tool (d -ft) (usfl) 33.80 5,477.60 MPU M-20 wp04 2_MWD+IFR2+MS+Sag 5,477.60 14,780.75 MPU M-20 wp04 2_MWD+IFR2+MS+Sa9 Ellipse error terms are correlated across survey tool fie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Belween centres is the straight line distance beNeen wellbore centres. Clearance Factor= Distance Between Profiles I (Distance Between Profiles- Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Alaska, LLC Milne Point 16 May, 2019 - 13:04 Page 6 o18 COMPASS MALLIBYFITON Pro ec,: Milne Point f REFERENCE INFORM4TIDN yy DEfALLS'PIau MPIIM-A NA[1193]N.1M'ONCO\LSI Aloka]<ne01 au lN�Pelanrvn'WeIl Plan: NPUM30,iu NOM µnkat punlRwrroa: M9]PkB®S4]pnM1 GrowPle�<1'. -490 Site: MPI Moose Pad sPe.•r a.�Ifin¢ Well : Plan: MPU M-20 wuurce�a i newb - nlre vmr.n s .v.w naw�s urons l,m. " to"PWue Wellbore: MPU M-20 aro .210as6 svMsea ]m,9ua9rN lavn'uleuw Plan: MPU M-20 wp04 suavFrP oG A NO GLOBAL FILTER: Uaing user tlefinea sok AGM 8 fi8eM9 vkesa Oek: POlee80ti00:00:aD vnllelm: vs version: ® 3380 To tO80.]5 D1,11 Fmm D10h To curve .n Tool CASMG DETAI[S Ladder/S.F. Plots 83.90 &76 MPU MRO uyW WPU M30I 2MWD�IFRNMS-Be 54]]60 14]80.]5 MPU M20 wy0A WPU AL M) 2 We. FR0aA6�5e ND ND35 IAD Si51 SH (1 of 2) 1908]0 3PSO.W 54]]70 9-SB,% 9518"x13V4" li5i]0 J49].W I<]90.]5 6-518 6519":BIn" T j i5a uo IVI 1i � 0120.00 ;I - o M-211 wy w 90.00 MP J 1-12 j N KUP 1 YOm S 34 � fi00D ! _ N, SIUI 2 -FlaceM199jjder III o M-ZO P3 wb09 m 30.00 _ ---- U M-57 SMI OIKWeN 7 -W1 o.00 0 300 600 900 1200 1500 1800 21M 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5]00 Measured Depth (600 usfUin) 4.00 u3,00 CDlllslon Risk Procedures Req. n Collision Avoidance Req. No-GO Zone -Stop Onlling: I '' 1.90 I NOERRORS ! One a 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700 Measured Depth (600 usfAin) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-20 MPU M-20 MPU M-20 wp04 Sperry Drilling Services Clearance Summary Anticollision Report 16 May, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-20 -MPU M-20 - MPU M-20 wp04 Well Coordinates: 6,027,889.58 N, 533,843.66 E (]0° 29' 14.00" N, 149" 43' 24.17' W) Datum Height: M-20 RKB @ 58.70usft Scan Range: 5,4]].60 to 14,]80.]5 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Scale Factor Applied Version : 5000.15 Build: 91 Scan Type: _ Scan Type: 2500 HALLIBURTON Sperry Orilling Services HALLIBURTON Anticollision Report for Plan: MPU M-20 - MPU M-20 wp04 Hilcorp Alaska, LLC Milne Point Closest Approach 30 Proximity Scan an Current Survey Data (North Reference) 1,086.36 7,902.60 Reference Design: M Pt Moose Pad - Plan: MPU M-20 -MPU M-20 -MPU M-20 wp04 13,616.21 8.118 Scan Range: 5,477.60 to 14,780.75 usft. Measured Depth. Pass - 8,427.60 Scan Radius Is Unlimited. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation Is 1,500.00 usft 870.13 Measured Minimum @Measuretl Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name -Wellbore Name - Design (usft) (usft) (usft) (usft) usft M Pt L Pad MPL-20 - MPL-20 - MPL-20 MPL-20 - MPL-20 - MPL-20 MPL-20 - MPL-20 - MPL-20 MPL-36 - MPL-36 - MPL-36 MPL36 - MPL-36 - MPL-36 MPL-36 - MPL-36 - MPL-36 MPL-36 - MPL-361-1 - MPL361-1 MPL36 - MPL-361-1 - MPL36L7 MPL-36 - MPL-36LI - MPL-361-1 MPL36 - MPL-361-1 PB1 - MPL361-1 Pat MPL-36 - MPL-361-1 PBI - MPL-36L1 Pat MPL-36 - MPL-361-1 Pat - MPL-36LI Pat MPL-36-MPL-36PB1-MPL36PB1 MPL-36-MPL-36PBI -MPL-WPB1 MPL-36-MPL36PB1 -MPL-36PBi M Pt M Pad M -Di - M41 - M -0I M-01 - M-01 - M-01 M-01 - M-01- M-01 M-01 - M -01A- M -01A M-01 - M -01A- M -01A M-01 - M41A - M -01A M Pt Moose Pad MPU M-11 - MPU M-11 - MPU M-11 MPU M-12 - MPU M-12 - MPU MA2 MPU M-12- MPU M-12PBI -MPU M-12PB1 7,902.60 1,086.36 7,902.60 952.55 13,616.21 8.118 Clearance Factor Pass - 8,427.60 974.26 8,427.60 870.13 13,935.83 9.356 Ellipse Separation Pass - 8,524.69 971.29 8.524,69 872.83 13,992.57 9.664 Centre Distance Pass - 9,277.60 1,288.61 9,277.60 1,109.90 14,763.13 7.211 Clearance Factor Pass - 9,952.60 1,130.48 9.952.60 1,001.87 15,229.14 8.789 Ellipse Separation Pass - 10,118.60 1,123.31 10,118.60 1,008.65 15,328.03 9.797 Centre Distance Pass - 9,252.60 1,297.44 9,252.60 1109.01 14,748.64 6.885 Clearance Factor Pass - 9,927.60 1,132.77 9,927.60 997.79 15,213.55 8.392 Ellipse Separation Pass - 10,118.60 1,123.31 10,118.60 1,006.27 15,328.03 9.598 Centre Distance Pass - 9,252.60 1,297.44 9,252.60 1,102.73 14,748.64 6.664 Clearance Factor Pass - 9,902.60 1,135.36 9,902.60 994.69 15,197.99 8.071 Ellipse Separation Pass - 10,118.60 1,123.31 10,118.60 1,004.48 15,328.03 9.453 Centre Distance Pass - 9,277.60 1,288.61 9,277.60 1,109.90 14,763.13 7.211 Clearance Factor Pass - 9,952.60 1,130.48 9,952.60 1,001.87 15,229.14 8.789 Ellipse Separation Pass - 10,118.60 1,123.31 10,118.60 1,008.65 15,328.03 9.797 Centre Distance Pass - 9,719.54 704.95 9,719.54 57059 4,293.24 5.247 Centre Distance Pass - 9,777.60 706.48 9,777.60 569.19 4,327.76 5.109 Ellipse Separation Pass - 9,952.60 728.79 9,952.60 58125 4,435.80 4.940 Clearance Factor Pass - 10,584.53 438.82 10,584.53 195.49 5,029.62 1.803 Centre Distance Pass - 10,627.60 439.76 10,627.60 193.49 5,058.92 1.786 Ellipse Separation Pass - 10,677.60 443.31 10,677.60 194.43 5,100.00 1.781 Clearance Factor Pass - 5,477.60 1,309.61 5,477.60 1,264.04 3,780.22 28.742 Clearance Factor Pass - 5,477.60 618.38 5,477.60 567.67 4,222.12 12.184 Clearance Factor Pass - 5,477.60 618.38 5,477.60 567.67 4,222.12 12.194 Clearance Factor Pass - 16 May, 2019 - 13:05 Page 2 of 7 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M-20 - MPU M-20 wp04 10.811.61 1,201.32 10,811.61 1,030.69 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 7.040 Centre Distance Pass - Option #1 Proposal: KupS3-Slot 13-60deg Sell Doe: 10,902.60 1,202.16 Reference Design: M Pt Moose Pad - Plan: MPU M-20 - MPU M-20 - MPU M-20 wp04 1,029.87 7,199.24 6.978 Ellipse Separation Pass - Option #1 Proposal: KupS3-Slot 13 -Sort Sail Doe: Scan Range: 5,477.60 W 14,780.75 usft. Measured Depth. 1,213.04 11,152.60 1,037.40 7,416.69 6.906 Clearance Factor Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Option #1 Proposal: MPU M -19i P2 -Slot 27-M-19iP 11,184.90 551:31 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Option #1 Proposal: MPU M-191 P2 -Slot 27-M-19iP Sae Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name -Wellbore Name -Design (usft) (usft) (usft) (usft) usft 11,477.60 379.71 MPU M -I2- MPU M-12PW-MPUM-12PB2 5,477.60 618.38 5,477.60 567.67 4,222.12 12.194 Clearance Factor pass - MPU M -I4- MPU M-I4-MPUM-14 6,671.62 222.43 6,671.62 177.97 4,271.29 5.003 Centre Distance Pass- MPUM-I4- MPU M -I4- MPU M-14 6,702.60 224.20 6,702.60 175.70 4,283.15 4.623 Ellipse Separation Pass - MPUM-I4-MPU M -I4- MPU M-14 6,777.60 242.34 6,777.60 185.42 4,312.27 4.257 Clearance Factor Paw - MPUM-I6- MPU M -I6- MPU M-16 8.562.20 539.13 8,562.20 438.76 5,473.41 5.371 Centre Distance Pass- MPUM-I6- MPU M -I6- MPU M-16 8,652.60 543.28 8,652.60 434.99 5,528.72 5.017 Ellipse Separation Paw - MPU M -I6- MPU M -I6- MPU M-16 8,802.60 568.83 8,802.60 450.62 5,607.89 4.812 Clearance Factor Pass - Option #1 Proposal: KupS3- Slot 13-60deg Sail Doe: 10.811.61 1,201.32 10,811.61 1,030.69 7,120.09 7.040 Centre Distance Pass - Option #1 Proposal: KupS3-Slot 13-60deg Sell Doe: 10,902.60 1,202.16 10.902.60 1,029.87 7,199.24 6.978 Ellipse Separation Pass - Option #1 Proposal: KupS3-Slot 13 -Sort Sail Doe: 11,152.60 1,213.04 11,152.60 1,037.40 7,416.69 6.906 Clearance Factor Pass - Option #1 Proposal: MPU M -19i P2 -Slot 27-M-19iP 11,184.90 551:31 11,184.90 381.89 7,519.46 3.254 Centre Distance Pass - Option #1 Proposal: MPU M-191 P2 -Slot 27-M-19iP 11,352.60 557.33 11,352.60 371.81 7,653.80 3.004 Ellipse Separation Pass - Option #1 Proposal: MPU M -19i P2 -Slot 27-M-19iP 11,477.60 574.06 11,477.60 379.71 7,733.07 2.954 Clearance Factor Pass- Plan: MPU M -11i P2 -M106 Phase2-M-11i P2 wp02 5,477.60 1,332.63 5,477.60 1,287.73 3,740.31 29.680 Clearance Factor Pass - Plan: MPU MA2 P2 -M107 Phase 2-MA2 p2 wp02 5,477.60 670.28 5,477.60 622.19 4,000.00 13.937 Clearance Factor Pass - Plan :MPU M -13i -M -131-M-131 wp03 5,838.09 367.11 5.838.09 331.10 3,990.51 10.193 Centre Distance Pass - Plan: MPU M -131 -M -131 -M -1N wp03 5,852.60 367.39 5,852.60 33021 4,000.00 9.881 Ellipse Separation Pass - Plan: MPU M -13i - M -13i - M -13i wp03 6,027.60 408.16 6,027.60 361.09 4,047.50 8.671 Clearance Factor Pass- Plan: MPU MAX P2 -M-13 Phase 2 -M -13i P2 n02 5,863.73 445.85 5,863.73 405.82 3,966.91 11.130 Centro Distance Pass - Plan :MPU M -13i P2 -M-13 Phase 2-M-131 P2 wp02 5,877.60 446.04 6.877.0 405.36 3,970.66 10.962 Ellipse Separation Pass - Plan :MPU M -13i P2 -M-13 Phase 2 -M -13i P2 wp02 6,07]60 489.96 6,077.60 439.73 4,027.49 9J53 Clearance Factor pass - Plan; MPUM-14 P2 -M-14 Phase2-M-14 P2 wp02 6,782.99 473.77 6,782.99 418.80 4,224.20 8.619 Centre Distance Pass - Plan: MPU M-14 P2 -M-14 Phase2-M-14 P2 wp02 6,827.60 475.51 6,827.60 417.33 4,239.63 8.172 Ellipse Separation Pass - Plan :MPUM-14P2-M-14Phase2-M-14P2wp02 6,977.60 505.93 6,977.60 438.11 4,300.00 7.460 Clearance Factor Pass- Plan : MPU M -151 -M -15i -M -15i wp04 7,602.90 367.24 7,602.90 298.27 4,773.70 5.325 Centre Distance Paw - Plan! MPU M -15i -M -15i -M -15i wp04 7,652.60 369.56 7,652.60 294.86 4,800.00 4.947 Ellipse Separation Pass - Plan :MPU M -15i -M -151 -M -15i wp04 7,777.60 394.98 7,777.60 309.22 4,859.87 4.606 Clearance Factor Pass - Plan: MPU M-151 P2 -M-15 Phase 2-M-151 P2 wp02 7,698.03 531.68 7,698.03 454.04 4,770.72 6.848 Centre Distance Paw - Plan :MPU M -15i P2 -M-15 Phase 2 -M -15i P2 wp02 7,752.60 533.80 7,752.60 451.33 4,800.00 6.473 Ellipse Separation Pass - Plan: MPU M-1 5i P2 - M-15 Phase 2 - M-1 5i P2 wp02 7,9]7.60 582.17 7,977.60 485.19 4,900.0 6.003 Clearance Factor Pass - 16 May, 2019 - 13:05 Page 3 of 7 COMPASS NALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M-20 - MPU M-20 wp04 9,459.78 652.84 9,459.78 529.37 Closest Approach 3D Proximity Scan an Current Survey Data (North Reference) 5.288 Centre Distance Pass - Plan: MPU M -17i P2 -M112 Phase 2 -M -17i P2 wp02 9,602.60 658.66 Reference Design: M Pt Moose Pad - Plan: MPU M-20 - MPU M-20 - MPU M-20 wp04 521.90 6,162.90 4.816 Ellipse Separation Pass - Plan:MPU M-17iP2-M112 Phase 2 -M -17i P2 wp02 Scan Range: 5,477.60 to 14,780.75 usft. Measured Depth. 697.56 9,852.60 543.67 6,329.33 4.533 Clearance Factor Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Plan: MPU M -I8 -MPU M -I8 -MPU M-18 W08 10,309.02 391.12 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Plan: MPUM-18-MPU M -I8 -MPU M-18 woos site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name -Wellbore Name - Design (usft) lush) (usft) (usft) ..it 10,47].60 252.16 Plan, MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 8,613.73 619.41 8,613.73 518.32 5,436.30 6.127 Centre Distance Pass - Plan :MPUM-16P2-M-16Phase2-MPUM-16P2w 8,702.60 623,38 8,702.60 514.96 5,481.75 5.750 Ellipse Separation Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 8,927.60 667.77 8,927.60 544.75 5,600.00 5.428 Clearance Factor Pass - Plan: MPU M -17i -MPU WIT -MPU M-17 wp04 9,401.84 490.41 9,401.84 369.54 6,107.46 4.057 Centre Distance Pass - Plan: MPU M -17i - MPU M -17i - MPU M-17 wp04 9,527.60 496.38 9,527.60 362.05 6,200.00 3.695 Ellipse Separation Pass - Plan: MPUM-17i-MPU MATT -MPU M-17 wp04 9,6]].60 523.47 9,677.60 377.07 6.300.00 3.576 Clearance Factor Pass - Plan: MPU M -17i P2 - M112 Phase 2 - M -17i P2 wp02 9,459.78 652.84 9,459.78 529.37 6,049.95 5.288 Centre Distance Pass - Plan: MPU M -17i P2 -M112 Phase 2 -M -17i P2 wp02 9,602.60 658.66 9,602.60 521.90 6,162.90 4.816 Ellipse Separation Pass - Plan:MPU M-17iP2-M112 Phase 2 -M -17i P2 wp02 9,852.60 697.56 9,852.60 543.67 6,329.33 4.533 Clearance Factor Pass - Plan: MPU M -I8 -MPU M -I8 -MPU M-18 W08 10,309.02 391.12 10,309.02 256.80 6,878A7 2.912 Centre Distance Pass - Plan: MPUM-18-MPU M -I8 -MPU M-18 woos 10,402.60 395.76 10,402.60 250.01 6,941.68 2.715 Ellipse Separation Pass - Plan: MPUM-i8-MPU M -I8 -MPU M-18 wp08 10,477.60 406.29 10,47].60 252.16 7,000.00 2.636 Clearance Factor Pass- Plan: MPU M-18 P2 -M-18 P2 -M-18 P2 n03 10,363.96 634.09 10.363.96 493.57 6,802.46 4.512 Centre Distance Pass - Plan: MPU M-18 P2 -M-18 P2-MA8 P2 xp03 10,552.60 642.18 10,552.60 482.76 6.956.0 4.028 Ellipse Separation Pass - Plan: MPU M-18 P2 -M-18 P2 -M-18 P2 wp03 10,77].60 682.04 10,777.60 506.63 7,10000 3888 Clearance Factor Pass - Plan: MPU M -19i -MPU M49i-Jab Stuart - MPU M-1 11,280.67 295.47 11,280.67 153.64 7,754.21 2.083 Centre Distance Pass - Plan :MPUM-19i-MPUM-191-Jeb Stuart-MPUM-1 11,402.60 304.07 11,402.60 140.77 7,844.51 1.862 Ellipse Separation Pass - Plan: MPU M -19i -MPU M -19i -Jet, Stuart - MPU M-1 11,477.60 317.96 11,477.60 144.22 7,900.00 1.830 Clearance Factor Pass - Plan: MPU M-1 9i P2 - M-1 9i P2 - M-1 9i P2 wp02 11,230g0 501.80 11,230.90 341.37 7,587.14 3.128 Centre Distance Pass - Plan: MPU M49i P2 -M -/9i P2 -M -19i P2 wp02 11,452.60 513.61 11,452.60 325.99 7,779.90 2.738 Ellipse Separation Pass - Plan: MPU M -19i P2 -M -19i P2 -M -19i P2 wp02 11,652.60 543.32 11,652.60 337.45 7,953.80 2.639 Clearance Factor Pass - Plan :MPUM-21i-M-2li-M-21iwp02 9,506.53 791.27 9,506.53 659.77 8,652.55 6.017 Centre Distance Pass - Plan: MPU M-21 i - M-21 i - M-211 wp02 14,780.75 791.38 14,780.75 512.81 13,925.32 2.841 Clearance Factor Pass- Plan :MPUM-2li P2-M-211Phase2-M-21i P2wp02 14,780.75 711.05 14,780.75 422.74 13,735.14 2.466 Clearance Factor Pass - Plan: MPU M -27 -M -27-M-27 wp02 5,477.60 1,097.30 5,477.60 1,048.79 4,163.60 22.620 Clearance Factor Pass - Plan: MPU M-57(SMGO)Slot 36 -Slot 10-M-57 SM( 5,477.60 955.72 5,477.60 915.31 4,016.36 23.652 Clearance Factor Pass - 16 May, 2019 - 13:05 Page 4 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-20 - MPU M-20 wp04 From To Survey/Plan Survey Tool (usfl) (usR) 33.80 5,4]].60 MPU M-20 wp04 2 MWD+IFR2+MS+Sag 5,4]/.60 14,]80.]5 MPU M-20 wp04 2_MWD+IFR2+MS+Sag Ellipse error terms are wnamted across survey tool tie -on points. Calwlaled ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres Is Me shmight line distance between wellbore centres. Clearance Factor = Distance Belween Proflas / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Alaska, LLC Milne Point 16 May, 2019 - 13:05 Page 5 o 7 COMPASS REFERENCE INFORMATON _LF DEI 11.: MR, M311 NAOIJ:](:JppCON WNUS AIu4s L-neW MALLIBUFiTON Project: Milne Point' , Site: M Pt Moose Pad c°^°'""° `oI I , e"": ww PNNa*.RNo Tia. Noti, lFe ]J 90 N...N..N N,o.Ka®.0. . E Lvi,NN bepoWe .: Rse aPe.ry oam^a Well: Plan: MPU M-20 MsurMeope. +.o -u.. Nonnn�s aed�s ue see — Wellbore: MPU M-20 cxm'uon wom: MNmun a�,or,. P.ua O.m 6o_1EE,n nnnEN 7n 2v I44012N M9•4Ym.1.1 Plan: MPU M-20 wPO4 PROGRAM NO GLOBAL FILTER: Using user defined selection Afilson'q u6ena DaM:2olsaa.Dn6o:ao:3:0000 0g v46aalea: v« venian: 33.80 To 14780 ]s ® Ladder/S.F. Plots DePIN Rom oeamID sunrylPmTool CASD+O nETAILS 33.80 .d Eo MPU M-20Z"(MPUn420) 2 MNDNFR2+MS+Sa PH(2of2) 5477,60 1478075 MPUM-20¢y04(MPUM20) 2 MNSNFR2+MS*SRU TVD INDSS MD 9'. Namc 1908.10 ls5000 547].60 45,8 95B"x CIH' 1555.70 3497.00 14780.75 6-58 65:8"a81R" -T—r ...............T I _ olzo.ao 90.00 .-i.._ _. __.. t—. I i m 60.09 ----� so U I I t5 30.00 —� 0.00 5500 woo 6500 7000 7500. 8000 8500 9000 8500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000 Measured Depth (1000 usttlin) 4.06 I I t5 ii3.00 Imo- I LL Collision Risk Procedures Req. @2.00 , soCollision Awidance Req. - y 1.00 Na -Go Zone -Stop Drilling NOERRORS 00—- ------- 05500 T, EE, a6000 6500 7000 7500 6000 8500 9000 8500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000 Measured Depth (1000 usit/in) STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES DIVISION OF OIL AND GAS 550 W. 7th Ave, Suite 1100, Anchorage, AK 99501-3563 Phone: 907-269-8800 Fax: 907-269-8943 Permitting Email: dog. perm itting(5alaska.aov Easement Application AS 38.05.850 Non-refundable application fee: $1200 ADL# 421155 /In hn filed in by sWw l SECTION I. APPLICANT INFORMATION Applicant Name: Jim Shine Title: Landman - Sr. Company: Hilcorp Alaska, LLC Mailing 3800 Centerpoint Drive, Suite 1400 Address: City/State/Zip Code: Anchorage, Alaska 99503 Phone: 907-777-8341 Email:jshine@hilcorp.com SECTION 11. PROJECT LOCATION/LAND STATUS State of Alaska Surface Lands: Subsurface Wellbore Easement - T.013N, R.009E, Sec. 11, Umiat Meridian Are supplemental pages for Land Status included in Appendix A? Yes No Ml Meridian, Township, Range, and Section(s): T.013N, R.009E, Section 11, Umiat Meridian, Alaska SE 1/4 of Section 11, 160 acres; SE 1/4 of SW 1/4 of Section 11, 40 acres; SW 1/4 of SW 1/4 of Section 11, 40 acres Is there an Oil and Gas Mineral Estate Lease? If yes, list ADL(s) Yes, ADL 355023 Other Considerations: None SECTION III. PROJECT INFORMATION 1. Project Name: Moose Pad Subsurface Wellbore Easement 2. Proposed Start Date: June 1, 2019 Proposed Easement Duration• 35 years 3. Project Activities Subsurface wellbore easement A. Project Description: The purpose of the subsurface easement is to allow wellbores drilled from the Moose Pad in the Milne Point Unit (located on ADL 025514) to cross the unit boundary and travel underneath Section 11 of T.01 3N, R.009E, which is in the Kuparuk River Unit. This easement will not require surface use or access. The first wells are planned to be spudded in mid-June 2019. The Moose Pad wellswill not be producing hydrocarbons from the Kuparuk River Unit and no pay zone will be open within 500 feet of the Milne Point Unit boundary in compliance with Alaska Oil and Gas Conservation Commission (AOGCC) rules and regulations. Once all wellbores that have the potential to cross the unit boundary are completed, Hilcorp Alaska, LLC will apply to revise and reduce the easement to encompass only that area covering the wellbore paths, approximately 50 feet in width. Rev. 0212019 Eesemew Application B. Easement Parameters: Total length of applied -for Total width applied -for easement (feet): easement (feet): Construction acreage Estimated operational acreage encompassed b easement: encompassed b easement: 240 acres C. Waste Management: Located on Moose Pad, Milne Point Unit D. Staging and Storage Areas: Located on Moose Pad, Milne Pant Unit E. Airstrips and Landing Zones: Deadhorse, Alaska airport F. Historical Properties and Cultural Resources: None known. Easement is for subsurface access only. G. Anadromous Fish Streams and Other Streams: Not applicable. Easement is for subsurface access only. 4. Associated Structures: Moose Pad, within the Milne Point Unit, is where each wellbore will be spudded. 5. State briefly the standards and methods of construction: No surface facilities will be constructed, nor will there be any surface access. 6. Is this an existing use?: Yes No If Yes, provide documentation verifying existing use, such as easement atlas, affidavits attestin o use and axis once ictures etc. 7. Other permits or authorizations applied in conjunction with this proposed project: Each well drilled from Moose Pad will require a Permit to Drill from the AOGCC; each well will be covered by Hilcorp Alaska, LLC's statewide AOGCC bond. SECTION IV, PERFORMANCE GUARANTY Bonded Company: Type: Bond Number: Amount: Bonding Company: Mailing Address: Phone: Fax: Email: %SECTION V.;QYStOliAl s Comprehensive General Liability Insurance: Amount of Insurance: Insurance will be in place before Entry Authorization and Director's Decision is issued. Insurer Name: Mailing Address: Phone: Fax: Email: Rev. 0212019 E"Ynmt Apprtwflan if this authorization is granted, I agree to construct and maintain the improvements authorized in a workmanlike manner, and to keep the area in a neat and sanitary condition; to comply with all the laws, rules, and regulations pertaining thereto; and provided further that upon termination of the easement for which application is being made, I agree to remove or relocate the improvements and restore the area without the cost to the state and to the satisfaction of the Director of the Division of Oil and gas. ol-I (u Itu( Applicant's sig i at a Date INSTRUCTIONS: Attach a USGS map (scale of 1:63,360) or a state status plat showing the location of the proposed easement. The final granting of easement will be contingent upon our receipt of as -built depicting the post construction location of the improvements. If your application is approved, instructions for the completion of the as -built will be provided by the Survey Section in the Division of Mining, Land, and Water. AS 38.05.035 (a) authorizes the director to decide what information is needed to process an application for the sale or use of state land and resources. This information is made a part of the state public land records and becomes public information under AS 40.25.110 and 40.25.120 (unless the information qualities for confidentiality under AS 38.05.035(a)(9) and confidentiality is requested). Public information is open to inspection by you or any member of the public. A person who is subject of the information may challenge its accuracy or completeness under AS 44.99.310, by giving a written description of the challenged Information, the changes needed to correct it, and a name and address where the person can be reached. False statements made in an application for a benefit are punishable under AS 11.56.210, Rev. 02,7019 Easement Appflmtion 149.48'0-W 149'44'0'W 149.40'0N 28 is tI8'98D•W 14B•320'W O 27 26 25 30 a 29 28 27_ U~ W o w1. eS C ZZ 2 V 3 34 35 36—`1' V37 32 3 34 33 ADtauoie U014N009E aoL155019 AD1.355017 Uo14N010E ADL355017 AD 30131.101 IN009E ADLO25509 AD3015509 UO13NO10E 101,04 S ripson La oon Mad —4— —3— 3 °a DS DS 3R l.11c 12 ��0 4 (MPU• , / tig� —s o i �,. aouea23 & y9 — / �% 0 Moose Pad Subsurface It 9 Well Bore Easement Area ! 0 D ° �9° P . t gDL355023 ADL355033 MPU 1 1 ADL025509 i ADLO47434 Staging Ar aA0L025513 ISi gOt025514 6a 8 p Ll' ADL025515 -- •' 0 ° LL f a ? ADL02$51 oc KUPARUK L p5a oon �`'t1 9 16 RIVER UNIT 4_ PU , Memo- tj [ 15 MILNE POINT UNIT is tR bG CYu S 30 ta yb Mine Ie E, 27 22 3, 24-�—m �' o�!9--20— 15531 , ADL025514 �2 Z` M AUL023515 AD1315049 A0102551 `L025610 1 ` ADLO25519 E ADL0255371 /6 ADLO25906 AD 2590 Q ul Pm nl PadA/f�LMp d 1. 28 _ f .7 Si 26', 29 o 28f a 7 N ada. tiWest .^. .^• /F-. ii 1 �", �<i I'd ' A. Sak 17 1V 5 b '11v t P FI s r ) C2V 3 9 @ est KUPARUJG R .43 D 3335 -RIVER ",NIT 36 MILNE_P_OIN7 UNIT �p 32' R' 3. U e, o 34 MPIU " ;i_ .j�� �` �', J adrr�. ,J17 �• + ii P, ' L U013NO09E DS 3 l U4.�i >r I UO13NO09E U013 O'IOE 1 I� -U012N009E `U012N610 9 2 " MI _.4 U012NOt0E �2T 1 i5° 6 ( 4�� 3 a V- 6 Project Location: Mine Point Unit Moose Pad' Muctice well flora Ea,,mamt Latitude (Decimal Degrees): 70.481789 NAD 1983 Longitude (Decimal Degrees): -149.67299 NAD 1983 Alaska Slate Plane Zone 4, NAD 1983 X=1680434.282 (feet) Y=6025790.696 (feet) W13NO09E 11 SE U013N009E 11 SW SW U013NOWE 11 SE SW ADL 355023 Adjacent Property Owner: Slate of Alaska Milne Point Unit Moose Pad Subsurface Well Bore Easement Vicinity Map - Figure 1 Legend --Existing Roads —Existing Pipeline (About: Ground) I Moose Pad Location Qat and Gas Unit Boundary Moose Pad Subsurface RZ Well Bore Easement Area Map Scale 1:63,360 1 inch equals 1 miles Naske SabPlare Zone 4 NAD"I IF.[) sk 0 1 1 --flemeter5 0 1 2 Miles Transform Points X Source coordinate system { I =V� Target coordinate system State Plane 1927 - Alaska Zone 4 .Abers Equal Area ¢154] Datum: Datum: NAD 192+7 - North America Datum of 1927 (Mean] NAD 1927- North America Datum of 1927 (Mean) Type values into the spreadsheet or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctrl.0 to copy and CHWto paste. Then click on the appropriate arrow button to transform the points to the desired coordinate system. t Back Finish Cancel Help TRANSMITTAL LETTER CHECKLIST WELL NAME: H P U-, M —; n PTD: ;_ Iq—©s�j __V Development _ Service Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: 1j i l Irl!? PD1 h -i— POOL: SGytV'Q4QI,�— BhAf /-' 0 -d - Check Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- -_ (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50-_- from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company -Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Companv Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 Well Name: MILNE PT UNIT M-20 Program DEV _ _ Well bore seg ❑ PTD#: 2190830 Company HILCORP ALASKA LLC Initial Class/Type DEV / PEND GeoArea 890 Unit 1128 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached ............NA 2 Lease number appropriate- - - Yes 3 Unique well. name and number _ _ _ _ Yes 4 Well located in a. defined pool. _ ......... Yes 5 Well located proper distance from drilling unit _boundary ...... _ _ - - - - _ _ - - Yes 6 Well located proper distance from other wells. .. _ Yes 7 Sufficient acreage available in drilling unit _ _ _ _ _ _ _ _ _ _ _ Yes Appr Date DLB 5/28/2019 8 9 10 11 12 13 14 15 16 17 18 If deviated, is wellbore plat. included ......... Operator only affected park'...... ..... - - - - - - - - - - Operator hasappropriate bond in force _ ....... Permit can be issued without conservation order _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Permit can be issued without administrative approval _ _ _ _ _ _ _ _ _ _ _ _ _ _ Can permit be approved before 15 -day wait.. .... .... ... ...... Well located within area and strata authorized by -Injection Order # (put 10# in comments) (For All wells within 1/4, mile area of review identified (For service well only). ...... _ Pre -produced injector: duration of pre -production less than 3 months (For service welt only) - - Nonconven. gas conforms to AS81.05.030(l. 1.A),G..2.A-D) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Conductor string.provided....................................... Yes Yes Yes Yes Yes Yes ........ NA _ NA . NA _ NA Yes - - - - - - - - - - - - - - - - - - - ---- - - - - -------------- - - 20 inch conductor set at_113ft Engineering 19 Surface casingprotects all known USDWs . ........ . .. . ....... . .... NA NO groundwater.,. permafrost area.. _ 20 CMT.vpl adequate to circulate on conductor & surf.csg ..... . .... . . . . . Yes _ _ using ES cementer for 2 stage on 9 518" casing , ...... . 21 CMT vol adequate to fie -In long string to surf cs9- - - - - - - - - - - - - - - - - - - - - - - - - Yes 22 CMT will cover all known productive horizons _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes . lateral will have slotted liner, 23 Casing designs adequate for CJ, B A. permafrost..... ..... _ ......... Yes 24 Adequate. tankage. or reserve pit _ _ _ _ _ _ _ .... _ Yes _ Rig has steel pits_ 25 If a_re-drill, has a 107403 for abandonment been approved _ _ _ _ _ _ _ _ _ _ _ _ NA.... _ _ Grassroots well. 26 Adequate wellbore separation proposed. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ No issues with close wells... Easement. needed to cross KRU 27 If diverter required, does it meet regulations.. _ _ _ _ .... Yes Appr Date 28 Arilling fluid, program schematic &. equip list adequate, ... .... _ _ Yes _ _ Max form pressure =_1715 psi (8,5. ppg EMW) Will drill with 8,910 9.5 ppg mud GLS 5/29/2019 29 BOPEs, do they meet regulation _ _ _ _ _ . . ... . ......... Yes. 30 ROPE press rating appropriate; test to -(put psig in comments) _ _ _ _ _ _ _ _ _ _ _ Yes _ _ MPSP = 1329_psi_ W'If test BOPE to 3000 psi . _ ..... 31 Choke manifold complies w/API. RP -53 (May 84)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 32 Work will occur without operation shutdown. - _ _ _ Yes 33 Is presence of H2S gas probable . . . . ... . . ...... . . ... . ......... . . No.... H2S not expected. 34 Mechanical_ condition of wells within AOR verified (For service well only) .............. NA 35 Pennitcan be issued w/o. hydrogensulfide measures ................ . . . . . Yes . _ _ _ H2S not anticipated from drilling of offset wells; however, dg will have H2$ sensors and alarms.. Geology 136 Date. presented on potential overpressure zones .... _ _ _ _ _ _ Yes Appr Date 37 Seismic analysis of shallow gas zones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ NA DLB 5/28/2019 38 Seabed condition survey.(if off -shore) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA 39 Contact name/phone for weekly progress reports_ [exploratory only] _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA Geologic Engineering Date Date Public Easement required to Cross KRU with the surface section of the wellbore approx( 1000-1500 ft ). 9 5/8" casing will be fully Date: Commissioner: Commissioner: _ Commissioner cemented across this interval. Reverse jet pump completion will be used. GIs 'D� ��
