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Home My WebLink About226-001Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Prudhoe Bay Field, Prudhoe Oil Pool, PBU 18-16C Hilcorp Alaska, LLC Permit to Drill Number: 226-001 Surface Location: 697' FNL, 281' FWL, Sec. 19, T11N, R15E, UM, AK Bottomhole Location: 138' FNL, 986' FEL, Sec. 20, T11N, R15E, UM, AK Dear Mr. McLaughlin: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 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, . Commissioner DATED this 22nd day of January 2026. Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2026.01.08 09:09:04 - 09'00' Sean McLaughlin (4311) 630' 226-001 By Grace Christianson at 7:45 am, Jan 09, 2026 *AOGCC witnessed BOP test to 3500 psi, Annular test to 3500 psi. *Email digital data of casing test, cementing summary, and FIT to AOGCC upon completion of FIT A.Dewhurst 14JAN26 22224484 DSR-1/22/26J.Lau 1.16.25 50-029-21749-03-00 JLC 1/22/2026 01/22/26 01/22/26 07 January 2026 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Permit to Drill Hilcorp North Slope, LLC 18-16C Dear Sir/Madam, Hilcorp North Slope , LLC hereby applies for a Permit to Drill an onshore development well from the Drillsite 18 in Prudhoe Bay, Alaska. 18-16C is planned to be a horizontal producer targeting the Ivishak sands. The parent bore, 18-16B will be reservoir abandoned on a prior sundry. The approximate spud date is anticipated to be Jan 29th, 2026, pending rig schedule. The Innovation rig will be used to drill this well. The directional plan is two-hole section sidetrack. An 8-1/2 x 9-7/8 intermediate hole exiting the 9-5/8 casing at ~3000 MD drilled into the top of the Sag River, with 7 casing ran and cemented. A 6-1/8 lateral will be drilled in the Ivishak. A 4-1/2 cemented liner will be run in the open hole section, followed by 4-1/2 tubing. Please find enclosed for your review Form 10-401 Permit to Drill with information as required by 20 AAC 25.005. If there are any questions, please contact me at (907)777-8395 or jengel@hilcorp.com. Respectfully, Joe Engel Senior Drilling Engineer Hilcorp North Slope, LLC Enclosures: Form 10-401 Permit to Drill Application for Permit to Drill Prudhoe Bay East (PBU) 18-16C Version 1 1/3/2026 Prudhoe Bay East 18-16C Table of Contents 1. Well Name .................................................................................................................. .................... 3 2. Location Summary ........................................................................................................... ............... 3 3. Blowout Prevention Equipment Information ................................................................................. 4 4. Drilling Hazards Information........................................................................................................... 5 5. Procedure for Conducting Formation Integrity Tests ..................................................................... 6 6. Casing and Cementing Program ..................................................................................................... 6 7. Diverter System Information .......................................................................................................... 7 8. Drilling Fluid Program ..................................................................................................................... 7 9. Abnormally Pressured Formation Information .............................................................................. 8 10. Seismic Analysis ............................................................................................................................ 8 11. Seabed Condition Analysis............................................................................................................ 8 12. Evidence of Bonding ..................................................................................................................... 8 13. Proposed Drilling Program ........................................................................................................... 9 14. Discussion of Mud and Cuttings Disposal and Annular Disposal ................................................ 12 15. Proposed Variance Request........................................................................................................ 12 Attachment 1: Location & GIS Maps ................................................................................................ 13 Attachment 2: BOPE Equipment ...................................................................................................... 15 Attachment 3: Hole Section Hazards ................................................................................................ 17 Attachment 4: LOT / FIT Test Procedure .......................................................................................... 20 Attachment 5: Cement Summary ..................................................................................................... 21 Attachment 6: Prognosed Formation Tops ...................................................................................... 22 Attachment 7: Well Schematic ......................................................................................................... 23 Attachment 8: Formation Evaluation Program ................................................................................ 25 Attachment 9: Wellhead Diagram .................................................................................................... 26 Attachment 10: Management of Change ......................................................................................... 27 Attachment 11: Drill Pipe Specs ....................................................................................................... 28 Attachment 12: Kick Tolerance Calculations .................................................................................... 30 Attachment 13: Directional Plan ...................................................................................................... 32 Attachment 14: Pre Rig Casing Test ................................................................................................. 33 Prudhoe Bay East 18-16C As per 20 AAC 25.005 (c), an application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application. 1. Well Name 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this application for a Permit to Drill is submitted is designated as 18-16C. This will be a development production well. 2. Location Summary 20 AAC 25.005 (c) (2) A plat identifying the property and the property's owners and showing: (A) the coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at total depth, referenced to governmental section lines; (B) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth Location at Surface Reference to Government Section Lines 697' FNL, 281' FWL, Sec 19, T11N, R15E, UM, AK NAD 27 Coordinate System X: 692,034.1 Y: 5,961,178.5 Innovation Rig KB Elevation 26.5 above GL Ground Level 17.6 above MSL Location at Top of Productive Interval Reference to Government Section Lines 999' FNL, 2206' FWL, Sec 19, T11N, R15E, UM, AK NAD 27 Coordinate System X: 693,966 Y: 5,960,925 Measured Depth, Rig KB (MD) 8,100 Total Vertical Depth, Rig KB (TVD) 7,705.7 Total vertical Depth, Subsea (TVDSS) 7,661.6 Location at Bottom of Productive Interval Reference to Government Section Lines 138' FNL, 986' FEL, Sec 20, T11N, R15E, UM, AK NAD 27 Coordinate System X: 700,980 Y: 5,961,971 Measured Depth, Rig KB (MD) 15,744 Total Vertical Depth, Rig KB (TVD) 8,629 Total Vertical Depth, Subsea (TVDSS) 8,585 Prudhoe Bay East 18-16C (D) other information required by 20 AAC 25.050(b); 20 AAC 25.050 (b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form 10-401) must: (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed well; and Please refer to Attachment 1: Location Maps, Attachment 6: Formation Tops and Attachment 13: Directional Plan for further details. (2) for all wells within 200 feet of the proposed wellbore: (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) state that the applicant is the only affected owner. The applicant is the only affected owner. 3. Blowout Prevention Equipment Information 20 AAC 25.005 (c) (3) A diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable; BOP test frequency for 18-16C will be 7 days until window milling is initiated, afterwards 14- days. Except in the event of a significant operational issue that may affect well integrity, an extension to the 14-day BOP test period should not be requested. Summary of Innovation BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2 x 9-7/8 & 6-1/8 13-5/8 x 5M Control Technology Inc Annular BOP 13-5/8 x 5M Control Technology Inc Double Gate o Blind ram in bottom cavity Mud cross w/ 3 x 5M side outlets 13-5/8 x 5M Control Technology Single ram 3-1/8 x 5M Choke Line 3-1/8 x 5M Kill line 3-1/8 x 5M Choke manifold Standpipe, floor valves, etc. Initial Test: 250/3500 (Annular 2500 psi) Subsequent Tests: 250/3500 (Annular 2500 psi) Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are in the doghouse and on accumulator unit. Please refer to Attachment 2: BOPE Equipment for further details. Prudhoe Bay East 18-16C 4. Drilling Hazards Information 20 AAC 25.005 (c) (4) Information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a pressure gradient to surface of 0.1 psi per foot of true vertical depth, unless the commission approves a different pressure gradient that provides a more accurate means of determining the maximum potential surface pressure; 8-1/2 x 9-7/8 Intermediate Hole Pressure Data Maximum anticipated BHP 3,341 psi in the top Sag River at 8,185 TVD Maximum surface pressure 2,524 psi from the Sag River (0.10 psi/ft gas gradient to surface) Planned BOP test pressure Rams test to 3,500 psi / 250 psi Annular test to 2,500 psi / 250 psi Formation Integrity Test 8-1/2 x 9-7/8 11.8 ppg EMW FIT after drilling 20 of new hole outside of 9- 5/8 window 11.8 provides greater than 25bbl KT based on 9.5ppg MW 9-5/8 Casing Test 9-5/8 casing tested pre rig 12/2/2025, 2750 psi 30min AOGCC Witnessed, See Attachment 14 6-1/8 Production Hole Pressure Data Maximum anticipated BHP 3,351 psi in the Ivishak at 8,282 TVD Maximum surface pressure 2,523 psi from the Ivishak (0.10 psi/ft gas gradient to surface) Planned BOP test pressure Rams test to 3,500 psi / 250 psi Annular test to 2,500 psi / 250 psi Formation Integrity Test 6-1/8 hole 10.5 ppg EMW FIT after drilling 20 of new hole outside of 7 10.5 provides greater than 25 bbl based on 9.0 ppg MW, 7.78 ppg pore pressure 9.5 ppg minimum to drill ahead, 10.5 EMW for drilling ECDs 7 Casing Test 3,500 psi , chart for 30 min (B) data on potential gas zones; and (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please refer to Attachment 3: Hole Section Hazards Prudhoe Bay East 18-16C 5. Procedure for Conducting Formation Integrity Tests 20 AAC 25.005 (c) (5) A description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f); Please refer to Attachment 4: LOT / FIT Test Procedure 6. Casing and Cementing Program 20 AAC 25.005 (c) (6) A complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre-perforated liner, or screen to be installed; Casing/Tubing Program Hole Size Tubular O.D. Tubular ID (in)Wt/Ft Grade Conn Length Top MD Bottom MD / TVD 8-1/2 x 9-7/87 (Special Drift)6.125 29# L-80 VAMTOP 8,676 Surface 8,676 / 8,185 6-1/84-1/2 Solid 3.958 12.6# 13Cr80 VAMTOP ~7,294 ~8,450 15,744 / 8,629 Tubing 4-1/2 Solid 3.958 12.6# 13Cr80 VAMTOP ~8,450 Surface ~8,450 / 8,000 Please refer to Attachment 5: Cement Summary for further details. Prudhoe Bay East 18-16C 7. Diverter System Information 20 AAC 25.005 (c) (7) A diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Diverter system is not applicable to a sidetrack well below the surface casing. 8. Drilling Fluid Program 20 AAC 25.005 (c) (8) A drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling Fluid Program Summary Intermediate Hole Production Hole Mud Type 6% KCl LSND 3% KCl BaraDril-N Mud Properties: Mud Weight PV YP HPHT Fluid Loss pH MBT 9.5-10.8 ppg 15-25 15-25 < 11.0 9-10 < 12 8.8 9.5 ppg 15-25 15-25 < 11 9-10 <7 A diagram of drilling fluid system on Innovation is on file with AOGCC. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033 Prudhoe Bay East 18-16C 9. Abnormally Pressured Formation Information 20 AAC 25.005 (c) (9) For an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); N/A Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis 20 AAC 25.005 (c) (10) For an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a); N/A Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis 20 AAC 25.005 (c) (11) For a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b); The 18-16C is to be drilled from an onshore location. 12. Evidence of Bonding 20 AAC 25.005 (c) (12) Evidence showing that the requirements of 20 AAC 25.025 have been met; Evidence of bonding for Hilcorp North Slope, LLC is on file with the Commission. Prudhoe Bay East 18-16C 13. Proposed Drilling Program 20 AAC 25.005 (c) (13) A copy of the proposed drilling program; the drilling program must indicate if a well is proposed for hydraulic fracturing as defined in 20 AAC 25.283(m); to seek approval to perform hydraulic fracturing, a person must make a separate request by submitting an Application for Sundry Approvals (Form 10-403) with the information required under 20 AAC 25.280 and 20 AAC 25.283; The proposed drilling program to 18-16C is listed below. Please refer to Attachments for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Completed Pre Rig Work 1. Reservoir was abandoned as per prior approved separate sundry (325-451) 2. 4-1/2 x 9-5/8 TxIA Tested to 2,500 Psi 3. 4-1/2 tubing cut at ~3,200 MD Proposed Drilling Program 18-16C 1. MIRU Innovation Rig 2. Verify well is dead. Circulate KWF if needed 3. Set BPV, ND Tree, NU BOPE, test as per PTD a. AOGCC opportunity to witness, 3500psi, annular 2500psi 4. Pull BPV, MU landing joint and BOLDS 5. Pull 4-1/2 tubing, pre rig cut ~ 3,200 MD, confirm with OE 6. MU Mill BHA and perform scraper/cleanout run to top of 4-1/2 tubing stub. 7. Displace well to 9.5 ppg milling fluid 8. ND BOPE and tubing spool and install 13-5/8 x 13-5/8 tubing spool. NU and shell test same. a. Barriers: i. Tested cement plug and IA, 2750 psi 30 min See Attachment 14 ii. KWF 9. MU Whipstock and Mill assembly and RIH to ~3,000 MD 10. Orient whipstock to ~ 120* azimuth with GWD, set anchor and shear off 11. Ensure wellbore 9.5ppg milling fluid in wellbore 12. Note: 9-5/8 casing tested pre rig 12/1/2025, 2750 psi 30min AOGCC Witnessed a. See Attachment 14 13. Mill 9-5/8 window & 20 of new hole 14. Pull milling assembly back into casing, RU and perform FIT to 11.8 ppg EMW 15. POOH and LD milling assembly, gauge mills a. If mills are under gauge, PU back up mills and dress of window 16. MU motor BHA, RIH, trip through window with pumps off and no rotary, drill to ~4000MD to bury 8-1/2 x 9-7/8 RSS BHA. POOH. 17. MU 8-1/2 x 9-7/8 RSS BHA, TIH, trip through window with no pumps or rotary, trip to bottom. Displace well to drilling fluid, 9.5 ppg Prudhoe Bay East 18-16C a. Install MPD RCD, to be used to monitor well conditions and provide constant bottomhole pressure for shale stabilization 18. Drill 8-1/2 x 9-7/8 hole to ~200 MD above HRZ 19. CBU and perform short trip to window 20. TIH to bottom, add black product to mud for shale stability, and drill ahead to TD a. Hold constant bottom hole pressure of ~10.5 11.0 ppg EMW for shale stability 21. At TD CBU, and increase MW t/ 10.5 for shale stability 22. POOH to window offsetting swab with MPD, pull BHA through window with no pumps or rotary, POOH and LD BHA 23. Run 7 long string to TD a. Circulate casing every ~ 2000MD while RIH, max rate 4 bpm to not exceed drilling ECDs 24. Cement 7 casing as per cement program 25. Freeze protect 9-5/8 x 7 annulus 26. Laydown 5 DP and PU 4 DP 27. MU 6-1/8 cleanout assembly, TIH top of 7 shoe track 28. PT 7 casing to 3500 psi, chart test 29. Drill out 7 shoe track & 20 of new hole 30. Pull back into 7 shoe, perform FIT t/ 10.5 ppg EMW 31. POOH, LD Cleanout BHA 32. MU 6-1/8 RSS BHA, RIH to bottom 33. Drill 6-1/8 lateral as per directional plan to TD a. Install MPD RCD to be used to monitor wellbore conditions during connections 34. CBU, and POOH to 7 shoe 35. POOH and LD BHA 36. RU and run 4-1/2 Liner on 4 DP to TD 37. Set liner hanger, release running tool and reengage 38. Cement 4-1/2 Liner as per plan 39. Set liner top packer, release running tool 40. CBU to remove any cement above liner top packer 41. RU and PT liner to packer / 7 annulus t. 1500 psi f/ 10 min, charted 42. POOH LD running tool 43. Run 4-1/2 tubing as per tally 44. Land Hanger, RILDS 45. Install TWC, ND BOPE, NU Tree 46. PT tubing hanger void 500/5000 psi, PT tree to 250/5000psi 47. Spot CI Brine 48. Drop Ball & Rod, set tubing packer 49. PT Tubing 3500 psi, bleed tubing to 1000 psi & PT IA to 3500 psi a. All tests 30 min, charted 50. Bleed Pressure on tubing to 0 psi, shear SOV, spot freeze protect 51. RU jumper to allowed freeze protect to swap Prudhoe Bay East 18-16C 52. RDMO Post Rig Work 1. Wireline: Pull ball and rod, RHC Plug 2. Service Coil: Perforate Well 3. Well Tie In 4. Put Well on Production Note: This well will not be fracture stimulated Prudhoe Bay East 18-16C 14. Discussion of Mud and Cuttings Disposal and Annular Disposal 20 AAC 25.005 (c) (14) A general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well. All cuttings and mud generated during drilling operations will be hauled to Prudhoe G&I on Pad 4. Drilling mud and cuttings will be hauled offsite as it is generated via truck. There is no intention to request authorization under 20 AAC 25.080 for any annular disposal operation in the well. 15. Proposed Variance Request There are no variance requests for this well at this time. Prudhoe Bay East 18-16C Attachment 1: Location & GIS Maps Prudhoe Bay East 18-16C Prudhoe Bay East 18-16C Attachment 2: BOPE Equipment Innovation Rig BOPE Schematic Per 20 AAC 25.035(e)1.A For an operation with a maximum potential surface pressure of 3,000 psi or less, BOPE must have at least three preventers, including (i) one equipped with pipe rams that fit the size of drill pipe, tubing, or casing being used, except that pipe rams need not be sized to bottom-hole assemblies (BHAs) and drill collars; (ii) (ii) one with blind rams, except that a subsea BOPE assembly must have blind/shear rams in place of blind rams; and (iii) (iii) one annular type Prudhoe Bay East 18-16C BOPE Configuration for each operation: Decomplete / Mill Window / Drill Intermediate / Run 7 Casing: 13-5/8 Annular UPR: 2-7/8 x 5-1/2 VBR Blind Rams LPR: 7 Solid Body Drill Production / Run 4-1/2 Liner & Completion: 13-5/8 Annular UPR: 2-7/8 x 5-1/2 VBR Blind Rams LPR: 2-7/8 x 5-1/2 VBR Innovation Rig Choke Manifold Schematic Prudhoe Bay East 18-16C Attachment 3: Hole Section Hazards 8-1/2 x 9-7/8 Intermediate Hole Section Hazard Mitigations Overpressure SV1 & Ugnu Due to offset cretaceous injection, there may be higher than normal pressure in the SV1, Ugnu and Schrader Sands, ML PP 9.3ppg. MW will be increased accordingly. Utilize MPD to monitor for pressure on connections. Hole Cleaning Maintain rheology of mud system, 6 rpm value greater than hole diameter. Maintain flow rates of 200 ft/min AV, 120 rpm. Do not out drill our ability to clean the hole. Pump sweeps as needed. Monitor ECDs Lost Circulation / Breathing Monitor ECD with MWD tools.Monitor active mud system. Pump LCM as needed. Ensure adequate LCM is available, follow lost circulation decision tree, Do not drill into sag any further than necessary. Breathing has been seen, treat all flow at wellbore influx until proven otherwise. Casing run Underreamed hole section, sufficient wellbore clean up, pinned float shoe, circulation schedule while RIH, monitor drag trends, watch casing circulation rates and ECDs Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight / back- pressure to hold back formations MPD to maintain CBHP Shale Stability Hole section will cross multiple shale formations. Directional plan and MW have been chosen based upon historical stability window. Ensure black product has been added to the mud system, MPD to maintain CBHP to minimize pressure cycling, swab pressures. Ensure sufficient MW is left in the well at TD. Pack Off During Cementing Clean up well bore at TD, and prior to running casing. Stage circulation rates up following circulation schedule Circulate bottoms up at multiple depths to condition mud the way in the hole. Circulate at TD to planned cementing rates and ensure hole is clean. Keep circulation rates below drilling ECDS, model accordingly, low displacement rates Gas Cut Mud Gas cut mud as been seen. Ensure sufficient MW is used during hole section. Monitor wells and MPD while drilling and on connections. Ensure gas detectors are tested and functioning. Watch swab effect while TOOH Intermediate Casing Pick Due to MW required for shale stability and low sag PP, we want to call intermediate casing point with the least bout of sag open as possible. Follow geologist for casing pick depth and procedure, scratch and sniff. Offset Injection Offset injection does exist, ensure all previously listed wells have been shut in a minimum of 2 days prior to beginning to drill the production section Prudhoe Bay East 18-16C 6-1/8 Production Hole Section Hazard Mitigations Offset Injection Offset injection does exist, ensure all previously listed wells have been shut in a minimum of 2 days prior to beginning to drill the production section Lost Returns / Breathing Monitor ECD with MWD tools. Have adequate LCM available. Breathing has been seen, treat all flow as influx until proven otherwise. Have sufficient fluid available. Faulting Be prepared for faulting, known and unknown. Losses can occur after faults, if losses are extreme consider suspending well operations. Hole Swabbing Reduce tripping speed, lower mud rheology, offset swab with MPD, pump out of the hole if required. Abnormal Pressures Lower than normal pressures in the target reservoir. Ensure LCM in the mud systems and monitor fluid systems. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight / back- pressure to hold back formations. Anti Collision See Close Approaches in Directional Plan attachment. Continually monitor surveys for magnetic interference. Shale / Wellbore Instability Maintain adequate mud weight / back-pressure for wellbore stability. Monitor cuttings returns, LWD logs, and drilling. Production hole could cross multiple shale formations. MPD to minimize pressure cycles on formation. See attached emails for anticipated fault crossings. -A.Dewhurst 14JAN26 Prudhoe Bay East 18-16C DS 18 has a history of H2S. Ensure detectors are tested and functioning. AOGCC to be notified withing 24 hours if H2S is encountered more than 20 ppm during drilling operations Rig will have fully functional automatic H2S detection equipment meeting the requirements of 20 AAC 25.066 In the event H2S is detected, well work will be suspended and personnel evacuated until a detailed mitigation procured can be developed. DS 18 H2S History: Wells with over 100ppm H2S readings: There are no wells with H2S 100ppm or greater Prudhoe Bay East 18-16C Attachment 4: LOT / FIT Test Procedure Prudhoe Bay East 18-16C Attachment 5: Cement Summary 7 Intermediate Casing Cement OH x CSG 8.5 x 9-7/8 OH x 7 Casing Basis Cement Vol Open hole volume + excess + 120 ft shoe track TOC 500 MD above Sag (Top Sag: 8,676 MD, TOC 8176 MD) Total Cement Volume Spacer 60 bbls of 11.0 ppg Tuned Spacer Cement 30% Open Hole Excess 15.8ppg:31.4 bbls, 176.2 ft3, 151.9 sks HalCem Class G 1.16 cuft/sk BHST 165 deg F Displacement (8676 120) * .0371bpf =317.4 bbl 4-1/2 Liner Cement OH x CSG 6-1/8 OH x 4-1/2 Liner Basis Cement Vol CH volume (215 7 Liner Lap) + (OH volume x 30%) + 120 ft shoe track TOC 7 x 5 Liner Top, ~ 8,450 MD Total Cement Volume Spacer 30 bbls of 11.0 ppg Tuned Spacer Cement 30% Open Hole Excess 15.8ppg: 160.2 bbls, 898.7 ft3, 774.8 sks HalCem Class G 1.16 cuft/sk BHST 170 -180 deg F Displacement (15744 8450 120) * .0152bpf (4-1/2 capacity) + 8450 * .0103 bpf (4 dp capacity) 109.1 + 87.1 = 196.2 bbl Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 8.5" Pilot Hole x 7" (120') (8676 - 8556)' x 0.0226 bpf x 1.3 = 3.6 20.2 9.875" OH x 7" (8556 - 8176) x .0471bpf x 1.3 = 23.3 130.7 7" Shoetrack 120' x 0.0372 bpf = 4.5 25.2 Total Tail 31.4 176.2 151.9 Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 6-1/8" OH x 4-1/2" (15,744 - 8,676)' x 0.0168 bpf x 1.3 = 154.4 866.2 7" CH x 4-1/2" (8,676 - 8,450) x .0175 bpf = 4.0 22.4 4-1/2" Shoetrack 120' x 0.0152 bpf = 1.8 10.1 Total Tail 160.2 898.7 774.8 Density Yield Mix Water 15.8 ppg 1.16 ft3 / sk 5.08 gal/sk Cement Slurry 200.7 bbls - J.Lau .0108 bpf91.6 bbls Prudhoe Bay East 18-16C Attachment 6: Prognosed Formation Tops 18-16C wp05 SV4 SV (Sand) Water 8.40 1393 0.44 SV3 SV (Sand) Water 8.40 1604 0.44 SV2 SV (Sand) Water 8.40 1683 0.44 SV1 SV (Sand) Water 8.40 1859 0.44 UG4A Ugnu (Sand) Water 8.40 2100 0.44 UG3 Ugnu (Sand) Water 9.30 2413 0.48 UG1 Ugnu (Sand) Water 9.90 2853 0.51 WS2 Schrader (Sand) Water 9.30 2947 0.48 WS1 Schrader (Sand) Water 9.30 3047 0.48 CM3 Colville (Shale) CM2 Colville (Shale) CM1 Colville (Shale) THRZ HRZ (Shale) Put River (Sand) Gas 7.92 3339 0.41 Kingak (Shale) TSGR Sag River (Sand) Gas 7.85 3341 0.41 TSHU Shublik (Shale / Carbonate) TSAD Ivishak (Sand/Shale) Gas 7.78 3351 0.40 TCGL Ivishak (Conglomerate) Water 7.72 3371 0.40 TZ1B Ivishak (Sand/Shale) Water 7.54 3386 0.39 T1A (TDF)Ivishak (Sand/Shale) Oil 7.40 3338 0.38 BSAD Shale/thin siltstones ANTICIPATED FORMATION TOPS & GEOHAZARDS TOP NAME LITHOLOGY EXPECTED FLUID MD (FT) TVD (FT) TVDSS (FT)PP (ppg)PP psi Gradient 3887 4931 See corrected prognosed formation tops table in attached emails. -A.Dewhurst 14JAN26 4329 3189 3691 Prudhoe Bay East 18-16C Attachment 7: Well Schematic Post Sundry Schematic, Well Status When Rig Arrives Prudhoe Bay East 18-16C Prudhoe Bay East 18-16C Attachment 8: Formation Evaluation Program 8-1/2 x 9-7/8 Intermediate Hole LWD Gamma Ray (including at-bit Gamma) Resistivity 6-1/8 Production Hole LWD Gamma Ray Resistivity Azimuthal Resistivity Density Neutron Mudlogging No mudlogging is planned. Prudhoe Bay East 18-16C Attachment 9: Wellhead Diagram Prudhoe Bay East 18-16C Attachment 10: Management of Change Prudhoe Bay East 18-16C Attachment 11: Drill Pipe Specs Prudhoe Bay East 18-16C Prudhoe Bay East 18-16C Attachment 12: Kick Tolerance Calculations Intermediate Hole: Prudhoe Bay East 18-16C Production Hole: Prudhoe Bay East 18-16C Attachment 13: Directional Plan Intermediate Section Offset Wells with CF < 1.0: 18-16 / 18-16A/ 18-16B This is the parent well of the sidetrack that fails AC at the whipstock. Production Section Offset Wells with CF < 1.0: 18-32: Is an abandoned well bore that has been sidetracked. The only risk is damage to the bit. Prudhoe Bay East 18-16C Attachment 14: Pre Rig Casing Test 9-5/8 x 4-1/2 CMT-TxIA 2500 psi, 30 min, AOGCC Witnessed 12/1/2025 1 Dewhurst, Andrew D (OGC) From:Dewhurst, Andrew D (OGC) Sent:Wednesday, 14 January, 2026 16:08 To:'Joseph Engel' Cc:Lau, Jack J (OGC); Joseph Lastufka Subject:RE: [EXTERNAL] PBU 18-16C PTD (226-001) Joe, Thanks. And yes, PBU 18-16C. Andy From: Joseph Engel <jengel@hilcorp.com> Sent: Wednesday, 14 January, 2026 15:59 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] PBU 18-16C PTD (226-001) Andy Attached is the updated formation table with correct depths for 18-16C (18-26 was written in your email, wanted to make sure we are talking about the same parent bore) . CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Below are the estimate fault crossings. And the correct operator name and bond number is below. Hilcorp Alaska, LLC Bond No: 22224484 Apologies for those. Please let me know if you have any other questions. Joe 3 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Wednesday, January 14, 2026 10:46 AM To: Joseph Engel <jengel@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: [EXTERNAL] PBU 18-26C PTD (226-001) Joe, I am completing my review of the PBU 18-26C PTD and have a couple questions: The table of prognosed tops appears to have TVD values greater than MD values for some of the shallow formations. Would you please check those and send an updated table if needed? Is this well anticipated to cross any faults? If so, would you provide details? Id like you to con rm that this permit will be processed with the new expanded Hilcorp Alaska, LLC operator name. The 10-401 form is using the bond number from the Hilcorp North Slope operator name. I will change that. Thanks, Andy Andrew Dewhurst CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 4 Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. 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. Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements 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 the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. PRUDHOE BAY 226-001 PBU 18-16C PRUDHOE OIL WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name: PRUDHOE BAY UNIT 18-16CInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgram DEVWell bore segAnnular DisposalPTD#:2260010Field & Pool:PRUDHOE BAY, PRUDHOE OIL - 640150NA1 Permit fee attachedYes ADL0283212 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, PRUDHOE OIL - 640150 - governed by CO 341J4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For sNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes 5K30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes 19 ppm on 2/6/1833 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)No DS 18 wells are H2S-bearing. H2S measures are required.35 Permit can be issued w/o hydrogen sulfide measuresYes Maximum pressure gradient of 9.9 ppg EMW in Ugnu with Ivishak reservoir anticipated at 7.4 ppg EMW.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate1/14/2026ApprJJLDate1/16/2026ApprADDDate1/14/2026AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 1/22/2026