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Home My WebLink About225-046MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, November 14, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC J-49 MILNE PT UNIT J-49 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 11/14/2025 J-49 50-029-23818-00-00 225-046-0 W SPT 3928 2250460 2000 347 347 347 347 INITAL P Adam Earl 10/6/2025 MIT-IA tested as per PTD 2250460 (conditions of approval) to 2000psi post injection. MONO-BORE well. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT J-49 Inspection Date: Tubing OA Packer Depth 5 2200 2089 2055IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE251008115816 BBL Pumped:4 BBL Returned:4 Friday, November 14, 2025 Page 1 of 1           CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Brooks, Phoebe L (OGC) To:Scott Heim - (C) Cc:Regg, James B (OGC) Subject:RE: [EXTERNAL] FW: MIT test Date:Tuesday, October 21, 2025 3:22:12 PM Attachments:MIT MPU J-49 07-29-25 Revised.xlsx Scott, Attached is a revised report changing the well name to J-49 based on PTD #2250460 and moving the Waived by verbiage to the Notes. Please update your copy or let me know if you disagree. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Scott Heim - (C) <scott.heim@hilcorp.com> Sent: Monday, September 22, 2025 5:21 PM To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: RE: [EXTERNAL] FW: MIT test Lets try this Phoebe, Thank you, Scott From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Sent: Monday, September 22, 2025 3:23 PM To: Scott Heim - (C) <scott.heim@hilcorp.com> Cc: jim.regg <jim.regg@alaska.gov> Subject: [EXTERNAL] FW: MIT test Importance: High Scott, 0LOQH3RLQW8QLW- 37' I was following up on this email. I would like to close out July reporting. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Brooks, Phoebe L (OGC) Sent: Tuesday, September 2, 2025 12:34 PM To: Scott Heim - (C) <scott.heim@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: MIT test Scott, The Pretest and 15 Min. pressures are listed as N/A (also no BBL Pump/Return info); please advise. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Scott Heim - (C) <scott.heim@hilcorp.com> Sent: Tuesday, July 29, 2025 7:23 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; 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. Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Brad Gorham <Brad.Gorham@hilcorp.com>; Ian Toomey - (C) <itoomey@hilcorp.com>; Jeremiah Vanderpool - (C) <jvanderpool@hilcorp.com>; Scott Heim - (C) <Scott.Heim@hilcorp.com> Subject: MIT test FYI, Regards, Scott 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. 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. Submit to: OOPERATOR: FIELDD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2250460 Type Inj W Tubing 0 0 0 0 Type Test P Packer TVD 3927 BBL Pump 5.0 IA 0 3750 3610 3590 Interval O Test psi 3500 BBL Return 4.5 OA Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hilcorp Alaska, LLC Milne Point Unit, J-Pad. MPU_J-49 Scott Heim 07/29/25 Notes:MIT-IA per PTD 225-046 prior to injection. Witness waived by Sean Sullivan. OA - N/A Notes: Notes: Notes: J-49 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanicall Integrityy Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Form 10-426 (Revised 01/2017)2025-0729_MIT_MPU_J-49 9 9 9 9 999 99 9 9 5HJJ Witness waived by Sean Sullivan 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. From:Brooks, Phoebe L (OGC) To:Scott Heim - (C) Cc:Regg, James B (OGC) Subject:RE: MIT test Date:Tuesday, September 2, 2025 12:34:22 PM Attachments:MPU_J-49_MIT-IA_7-29-25.xlsx Scott, The Pretest and 15 Min. pressures are listed as N/A (also no BBL Pump/Return info); please advise. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Scott Heim - (C) <scott.heim@hilcorp.com> Sent: Tuesday, July 29, 2025 7:23 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Brad Gorham <Brad.Gorham@hilcorp.com>; Ian Toomey - (C) <itoomey@hilcorp.com>; Jeremiah Vanderpool - (C) <jvanderpool@hilcorp.com>; Scott Heim - (C) <Scott.Heim@hilcorp.com> Subject: MIT test FYI, Regards, Scott 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 0LOQH3RLQW8QLW- 37' 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. Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 225-046 Type Inj W Tubing 0 0 0 0 Type Test P Packer TVD 3927 BBL Pump IA 0 3750 3610 3590 Interval O Test psi 3500 BBL Return OA N/A 5.0 N/A 4.5 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hilcorp Alaska, LLC Milne Point Unit, J-Pad. MPU_J-49 Witness waived by Sean Sullivan Scott Heim 07/29/25 Notes:MIT-IA per PTD 225-046 prior to injection. Notes: Notes: Notes: I-23 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Form 10-426 (Revised 01/2017)2025-0729_MIT_MPU_J-49 9 9 9 9 999 99 99 9 9 -5HJJ David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/19/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: MPU J-49 + PB1 + PB2 + PB2 + PB3 PTD: 225-046 API: 50-029-23818-00-00 (MPU J-49) API: 50-029-23818-70-00 (MPU J-49PB1) API: 50-029-23818-71-00 (MPU J-49PB2) API: 50-029-23818-72-00 (MPU J-49PB3) FINAL LWD FORMATION EVALUATION + GEOSTEERING (06/28/2025 to 07/22/2025) x ROP, AGR, DGR, ABG, EWR-M5, ADR Horizontal Presentation (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey x Final Geosteering and EOW Report/Plots SFTP Transfer – Main Folders: FINAL LWD Subfolders: FINAL Geosteering Subfolder: Please include current contact information if different from above. T40789 T40790 T40791 T40792 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.20 08:16:54 -08'00' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________MILNE PT UNIT J-49 JBR 09/08/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:2 Slow test long shell test, FP on upper and lower IBOP replaced both after trying grease and service passed after replacment. TJ's used 3-1/2", 4-1/2", 5", 5-1/2". Accumulator bottles 18 with 1018 psi precharge Avg. Test Results TEST DATA Rig Rep:S.Tower/. HamiltonOperator:Hilcorp Alaska, LLC Operator Rep:M. Brouillet/ I. Toomey Rig Owner/Rig No.:Doyon 14 PTD#:2250460 DATE:7/17/2025 Type Operation:DRILL Annular: 250/3000Type Test:BIWKLY Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopKPS250717222356 Inspector Kam StJohn Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 14 MASP: 1329 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 FP Lower Kelly 1 FP Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 14 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8"P #1 Rams 1 4-1/2" x 7"P #2 Rams 1 Blinds P #3 Rams 1 2-7/8" x 5"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 3-1/8"P Kill Line Valves 2 3-1/8'P Check Valve 0 NA BOP Misc 0 NA System Pressure P3050 Pressure After Closure P1750 200 PSI Attained P39 Full Pressure Attained P180 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6 @ 2066 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P15 #1 Rams P6 #2 Rams P6 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1          Attachment - IBOP Valves retests chart BOPE Test Chart – Doyon 14 Retest of Upper and Lower Inside BOP Valves MPU J-49 (PTD 2250460) AOGCC Inspection # bopKPS250717222356 7/17/2025 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Unmanned Flowback 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): ±16381 N/A Casing Collapse Conductor N/A Surface 6,620psi Surface 3,090psi Liner 6,390psi Liner 8,540psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Hayden Moser Contact Email:Hayden.Moser@hilcorp.com Contact Phone:907-793-1231 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ±4272 ±16381 ±4272 1,329 N/A Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MPU J-49 Milne Point Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 7/28/2025 Subsequent Form Required: Suspension Expiration Date: 225-046 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23818-00-00 Hilcorp Alaska LLC C.O. 477b TVD Burst AOGCC USE ONLY 13.5# / L-80 / EUE 8rd ±50153-1/2" 9,020psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025906 & 25518 TBD ±2500 ±5165 Length Size Proposed Pools: ±124 TBD Schrader Bluff Oil N/A MD N/A 7,740psi 7,930psi 5,750psi TBD TBD TBD37,347' ±124 20" 9-5/8" 9-5/8" ±2500 5-1/2"±1866 ±2665 HES MatchSet & N/a ѷ5,019 MD / ±16381 Perforation Depth MD (ft): ±6881 See Schematic ±9500 See Schematic No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Wells Manager 325-386 By Gavin Gluyas at 2:06 pm, Jun 26, 2025 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2025.06.26 07:43:46 - 08'00' Taylor Wellman (2143) DSR-6/30/25 10-404 10-JULY-2025 SFD 7/21/2025 Mel Rixse - Senior Petroleum Engineer YES MGR27JUN25 * Approved for 30 day flow back on reverse circulating jet pump. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.21 14:50:38 -08'00'07/21/25 RBDMS JSB 072425 New Drill Injector Well: MPU J-49 Date: 06/24/2025 Well Name: MPU J-49 API Number: 50-029-23818-00-00 Current Status: Drilling Rig: N/A Estimated Start Date: 07/28/2025 Estimated Duration: 1 day Reg.Approval Req’d? Yes Date Reg. Approval Rec’vd: TBD Regulatory Contact: Tom Fouts Permit to Drill Number: 225-046 First Call Engineer: Hayden Moser 479-899-8940 Second Call Engineer: Taylor Wellman 907-947-9533 Current Bottom Hole Pressure: N/A Max. Proposed Surface Pressure: 1329 psig Min ID: 2.790” @ ~4,550’ XN Nipple Brief Well Summary and Objective MPU J-49 is currently on the schedule to be drilled as a lateral injector in the Schrader Bluff NB Sand. It is currently approved for a 30 day flowback. With the recent approval from the AOGCC on unmanned flowbacks, we would like to obtain approval for this well. Note that the proposed schematic has been updated to include a screened liner versus slotted liner. Notes on Well Condition x SSV Pilot Settings: o Production SSV low pressure trip will be set to 25% of FTP or 50% of inlet separator pressure. o Production SSV high pressure trip will be set at 1150 psig. o Power fluid XV low pressure trip will be set to 50% of header pressure. o Power Fluid XV to be actuated if vertical run tubing SSV is actuated (within 2 minutes). x AOGCC will be notified for opportunity to witness before production begins. x Visual leak check by pad operator performed at least once per tower (i.e. ~ every 12 hours). x SCADA screen available in control room for pressure and flow sensors on injection line and well’s flow line. x Pilot trip pressures, both high and low, documented in permitting documents for Hilcorp pad operators and AOGCC inspectors. Post-Rig Work (Sundried Step): 1. MU surface lines from power fluid header to the tubing. Rig up piping and instrumentation per Unmanned Injector Flowback Diagram. a. Pressure test lines at existing power fluid head pressure (3,500 psi) 2. Rig up piping and instrumentation to the production header per Unmanned Injector Flowback Diagram. Pressure test to 3,500 psi. Attachments: 1. Unmanned Injector Flowback Diagram 2. Updated Proposed Schematic New Drill Injector Well: MPU J-49 Date: 06/24/2025 _____________________________________________________________________________________ Revised By: TCS 6/25/2025 PROPOSED SCHEMATIC Milne Point Unit Well: MPU J-49 Last Completed:TBD PTD: TBD 5-1/2” x 4-1/2” SCREENED LINER DETAIL Size Top (MD) Top (TVD) Btm (MD) Btm (TVD) CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"Conductor 129.5 / X-52 / Weld N/A Surface 124’N/A 9-5/8"Surface 47 / L-80 / TXP 8.525”Surface 2,500’0.0732 9-5/8"Surface 40 / L-80 / TXP 8.679”2,500’5,165’0.0758 5-1/2”Liner 250ђ Screens 17 / L-80 / JFE Bear 4.892”5,015’6,881’0.0232 4-1/2”Liner 150ђ Screens 13.5 / L-80 / JFE Bear 3.920”6,881’16,381’0.0149 TUBING DETAIL 3-1/2"Tubing 9.3 / L-80 / EUE 8RD 2.992”Surface 5,015’0.0087 OPEN HOLE / CEMENT DETAIL 24” x Driven 7 yds Concrete 12-1/4"Stg 1 –Lead 288 sx / Tail 395 sx Stg 2 –Lead 673 sx / Tail 268 sx 8-1/2”Uncemented Slotted Liner TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 11” x 4-1/2” Tubing Hanger, 4-1/2” TCII GENERAL WELL INFO API#: TBD Completion Date: TBD WELL INCLINATION DETAIL KOP @ 300’ 90° Hole Angle = 5,500’ MD JEWELRY DETAIL No Top MD Item ID Upper Completion 1 ~4,430’Viking Sliding Sleeve 2.813” X Profile (Opens Down)2.810” 2 ~4,490’Zenith Gauge Carrier 2.992” 3 ~4,550’XN Nipple, 2.813”, 2.75” No-Go 2.750” 4 ~5,019’Locater Sub, 8.25” No Go (bottom of locator spaced out 3.52’)6.261” 5 ~5,019’Bullet Seals – TXP Top Box Up x Mule Shoe (Bottom @ ~4,675’)6.261” Lower Completion 6 5,015’HES MatchSet Liner Top Packer 6.300” 7 16,381’Shoe Alaska 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: Milne Point Unit Field, Schrader Bluff Oil, MPU J-49 Hilcorp Alaska, LLC Permit to Drill Number: 225-046 Surface Location: 2506' FSL, 3313' FEL, Sec. 28, T13N, R10E, UM, AK Bottomhole Location: 2149' FSL, 1779' FWL, Sec. 26, T13N, R10E, 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, Jessie L. Chmielowski Commissioner DATED this 12th day of June 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.12 11:47:57 -08'00' By Grace Christianson at 7:44 am, Apr 29, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.04.28 16:09:11 - 08'00' Sean McLaughlin (4311) 50-029-23818-00-00 A.Dewhurst 11JUN25 552,005' 225-046 * BOPE test to 3000 psi. Annular to 2500 psi. * 24 hour notice to AOGCC for opportunity to witness MIT-IA to 3500 psi after packer set. * AOGG to witness MIT-IA to 2000 psi after within 10 days of stabilized injection. * Approved to pre-produce for 30 days via a reverse circulating jet pump w/24/7 man watch. * Offset well E-28 to have reservoir plug in place prior to spud of MPU J-49. 1,749 MGR06MAY2025 DSR-4/29/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.12 11:48:10 -08'00' 06/12/25 06/12/25 RBDMS JSB 061625 8 2321 26272 353433 I J H G A A-01 A-02 A-02A A-03 CFP-1 B-07 E-02 B-22A G-02G-01 G-04 G-03 G-03A J-05 J-07 C-22 C-22A J-06 J-09 J-09A J-08 J-08A J-10 J-11 J-12 J-13 E-13 E-13B E-20A E-20AL1 H-05H-06 I-05 E-18 G-09 G-10 G-11 G-13 G-12 H-10 H-14 H-11 H-12 H-08 H-08A H-13 H-13A -17 -20 -18 B-25 J-22 E-33 J-15 E-25 E-25A E-25L1 E-26 C-41L1 G-14G-14L1 I-15 I-15L1 S-29L1 S-19A G-16 G-16L1 G-17 G-18 G-18L1J-26 J-26L2 J-25 I-19 I-19L1 H-18 H-18L1 H-18L2 H-16 H-16L1 G-19 E-28 H-15 H-17 H-19 H-19L1 E-03 H-01 H-02 H-03 H-04 I-02 I-03 I-04 I-04A I-04AL1 J-01 J-01A J-01AL1 J-02 J-03 J-04 G-05 G-06 G-07 G-08 G-08A I-07 -19 J-19A J-16 E-14 E-19 B-22APB1 E-13APB1 E-20AL1PB1 H-14PB1 E-25PB1 I-15PB1 S-19APB1 G-16PB1 G-18PB1 J-26PB1 J-25PB1 I-19PB1 H-16PB1I-04PB1 E-13APB2 E-25PB2 C-41PB2 G-16PB2J-26PB2 I-19PB2 H-16PB2 I-04APB1 E-25PB3H-16PB3 E-25L1PB1 I-02LS I-02SS E-37 E-38 E-37PB1 E-36 E-36PB1 E-42 E-38 PB1 E-38 PB2 I-35 I-20 I-36PB1 I-36PB2 -26 I-37PB1 8PB2 I-28 I-07A E-35PB1 H-17PB1 S-44 I-28PB1 I-07APB1 I-27 S-56PB1 I-30 B-40PB1 I-31 I-33 I-2526 J-43 J-42 J-42PB1J-41 J-41PB1 J-44 J-45 J-44PB1 J-40 J-47 J-46 J-32 HILCORP ALASKA LLC MILNE POINT FIELD J-47 AOR Schrader Bluff Nb Drill Well FEET 0 500 1,000 1,500 POSTED WELL DATA Well Number WELL SYMBOLSOi l D&A Location Shut In Oil INJ Well (Water Flood) P&A Oil P&A Oil/Gas Abandoned Injector SWD J&A Temporarily Abandoned Plug Back Pilot Well Injector Loc ation Producer Location Inj ector Gas Shut In INJ WATER SOURCE LEAD REMARKSPosting all wells that penetrate the Schrader BluffFormation.Nb Penetration Points labelled with well symbols atTop Nb.Other Schrader Bluff wells that never penetrated the Nb(mostly sidetracked wells) are labelled at TDDashed black circles and red outline illustrates 1/4 Mileradii from proposed well By: K. Cunha April 10, 2025 PETRA 4/10/2025 5:09:02 PM J-49 AOR Map •All wells that penetrate the Schrader Bluff Nb labelled at top Nb intersection point •Green lines represent the footage in wells that are within the Schrader Bluff Nb sand inside the ¼ mile radius of proposed injector, J-49 •Note: Future new drill well, E-48, shown in dark green J-49expected TD location E-48 (not drilled yet) Expected Top Nb intersection point J-49 expected Top Nb intersection point J-49 Proposed Well Future E-48 ProducerJ- 47 (Nb horizontal) passes into ¼ mile radius I-35 (Nb horizontal) passes into ¼ mil e r adiu s I-20 (OBa horizontal) I-27 (Oa horizontal) PTD API WELL STATUS Top of SB NB (MD) Top of SB NB (TVD) Top of Cement (MD) Top of Cement (TVD) Schrader NB status Zonal Isolation 220-049 50-029-23679-00-00 MPU I-20 SB OBa Producer- Active 4066 3810 Surface Surface Closed 9-5/8" Cemented to surface via 2 stage cement jobs with 226 bbls returned to surface. 221-013 50-029-23692-00-00 MPU I-27 SB OA Producer- Active 4124 3784 Surface Surface Closed 9-5/8" Cemented to surface via 2 stage cement jobs with 255 bbls returned to surface. 220-034 50-029-23675-00-00 MPU I-35 SB NB Injector- Active 4842 3812 Surface Surface Open 9-5/8" Cemented to surface via 2 stage cement jobs with 200 bbls returned to surface. 190-095 50-029-22070-00-00 MPU J-01 SB N Sands/Oa/OBa Producer-P&A'd 4041 3878 2810 2729 Closed The 7" was cemented with 293 sx Class G cement. Assuming 20% washout TOC is at 2810'. No losses noted on daily report. 199-111 50-029-22070-01-00 MPU J-01A SB N Sands/Oa/(OBa lateral)Producer- Reservoir P&A'd 4149 3886 2810 2729 Closed The 7" was cemented with 293 sx Class G cement. Assuming 20% washout TOC is at 2810'. No losses noted on daily report. 201-021 20-029-22070-60-00 MPU J-01AL1 SB N Sands/Oa/OBa (Oa Lateral) Producer-Reservoir P&A'd 4149 3886 2810 2729 Closed The 7" was cemented with 293 sx Class G cement. Assuming 20% washout TOC is at 2810'. No losses noted on daily report. 191-095 50-029-22196-00-00 MPU J-05 SB N Sands/OA/OBA Injector- Shut In 4424 3977 3004 2902 Open The 9-5/8" was cemented with 634 sx class G cement. Assuming 20% washout, TOC is 3,004' MD. No losses are noted on the daily report. 204-013 50-029-23192-00-00 MPU G-17 SB /OA/OBA Injector- Shut in 6178 3973 5256 3284 N/A The 7" was cemented with 226 sx class G cement. Assuming 20% washout, TOC is 4950' MD. No losses are noted on the daily report. A CBL was run on 2/12/2004 and TOC was picked at 5256' MD. 190-096 50-029-22071-00-00 MPU J-02 Prince Creek Water Source Well- Active (Res abandoned SB Injector)5611 3997 3580 2740 Closed The 7" was cemented with 306 sx class G cement. Assuming 20% washout, TOC is 3936' MD. No losses are noted on the daily report. A CBL was run on 10/31/2016 and TOC was picked at 3,580' MD. 194-110 50-029-22500-00-00 MPU J-10 Kuparuk Producer- Active 4512 3977 4001 3521 N/A The 7" was cemented with 110 sx class G cement. Assuming 20% washout, TOC is 4001' MD. No losses are noted on the daily report. 194-118 50-029-22506-00-00 MPU J-12 SB Oa/OBa Injector- Shut in 4287 3893 4322 3923 Open TOC at 4322' MD on CBL from Oct 14, 1994 (Western Atlas; CBL/GR/CCL) 194-126 50-029-22508-00-00 MPU J-13 Kuparuk Injector- Active 4988 3971 4352 3518 N/A The 7" was cemented with 163 sx class G cement. Assuming 20% washout, TOC is 4352' MD. No losses are noted on the daily report. 189-046 50-029-21942-00-00 MPU G-03 SB N Sands/Oa/OBa Injector-P&A'd 5367 4139 2583 2286 Closed The 7" was cemented with 87 bbls class G dement. Assuming 20% washout, TOC is at 2583' MD. Full returns were reported during job. 204-219 50-029-21942-01-00 MPU G-03A SB N Sands/Oa/OBa Injector-Shut in 5935 4179 3670 2943 Closed TOC at 3670' per CBL logged 11-26-2004 189-045 50-029-21941-00-00 MPU G-04 SB N Sands/Oa/OBa Producer-Shut In 4344 4017 3061 2862 Closed The 7" was cemented with 51 bbls class G dement. Assuming 20% washout, TOC is at 3061' MD. No losses are noted on the daily report. 191-026 50-029-22141-00-00 MPU G-08 SB N Sands/Oa/OBa Producer-P&A'd 5097 4018 3045 2575 Closed The 7" was cemented with 53 bbls class G dement. Assuming 20% washout, TOC is at 3045' MD. No losses are noted on the daily report. 193-048 50-029-22141-01-00 MPU G-08A SB N Sands/Oa/OBa Producer-Shut In 4916 4001 3045 2575 Open The 7" was cemented with 53 bbls class G dement. Assuming 20% washout, TOC is at 3045' MD. No losses are noted on the daily report. 197-119 50-029-22781-00-00 MPU G-11 SB Oa/OBa Injector- Shut in 6889 4190 885 883 N/A 7" casing cememted with 1185 sx PF 'E' followed by 130 sx class G. TOC at 885' per CBL dated13-Jun-2015. 197-142 50-029-22792-00-00 MPU G-12 SB N Sands/OA/OBA Producer- Shut in 4079 3986 Surface Surface Open The 9-5/8" was cemented to surface via a 2 stage cement job with 110 bbls to surface. 201-133 50-029-23031-00-00 MPU G-14 SB N sand and dual-lat (OBa lat) Producer- Active 6109 3992 Surface Surface Open 7" casing cemented with 860 sx class L followed by 515 sx class G. Full returns throughout job with 300 bbls cement to surface. 201-133 50-029-23031-60-00 MPU G-14L1 SB N sand and dual-lat (Oa lat) Producer- Active 6109 3992 Surface Surface Open 7" casing cemented with 860 sx class L followed by 515 sx class G. Full returns throughout job with 300 bbls cement to surface. 204-020 50-029-23194-00-00 MPU G-18 SB dual-lat (OBa lat) Producer- Active 5170 4045 3730 2849 N/A The 7-5/8" was cemented with 420 sx of Class G cement in 9-7/8" hole. Assuming 20% washout, TOC is 3730' MD. The daily drilling report says they had "full returns and good pressure increase". 204-021 50-029-23194-60-00 MPU G-18L1 SB dual-lat (Oa lat) Producer- Active 5170 4045 3730 2849 N/A The 7-5/8" was cemented with 420 sx of Class G cement in 9-7/8" hole. Assuming 20% washout, TOC is 3730' MD. The daily drilling report says they had "full returns and good pressure increase". 204-020 50-029-23194-70-00 MPU G-18PB1 SB OBa plugback 5170 4045 3730 2849 N/A The 7-5/8" was cemented with 420 sx of Class G cement in 9-7/8" hole. Assuming 20% washout, TOC is 3730' MD. The daily drilling report says they had "full returns and good pressure increase". 191-024 50-029-22139-00-00 MPU G-06 SB Nb Producer- P&A'd 5181 4144 3900 3237 Closed The 7" was cemented with 82 bbls class G cement in 8-1/2" hole. Assuming 20% washout, TOC is 2854' MD. A drilling summary page says "bumped plug at 1000 psig over circulating pressure. Floats held." A sundry on the AOGCC website estimates TOC at 3900'. 203-210 50-029-23189-00-00 MPU G-16 SB dual-lat (OBa lat) Producer- Active 5299 4136 3295 3109 N/A The 7-5/8" was cemented with 670 sx of Class G cement in 9-7/8" hole. Assuming 20% washout, TOC is 3295' MD. The cement reports says "floats held, full returns throughout job." 203-211 50-029-23189-60-00 MPU G-16L1 SB dual-lat (Oa lat) Producer- Active 5299 4136 3295 3109 N/A The 7-5/8" was cemented with 670 sx of Class G cement in 9-7/8" hole. Assuming 20% washout, TOC is 3295' MD. The cement reports says "floats held, full returns throughout job." 203-210 50-029-23189-70-00 MPU G-16PB1 SB OBa plugback 5299 4136 3295 3109 N/A The 7-5/8" was cemented with 670 sx of Class G cement in 9-7/8" hole. Assuming 20% washout, TOC is 3295' MD. The cement reports says "floats held, full returns throughout job." 203-210 50-029-23189-71-00 MPU G-16PB2 SB OBa plugback 5299 4136 3295 3109 N/A The 7-5/8" was cemented with 670 sx of Class G cement in 9-7/8" hole. Assuming 20% washout, TOC is 3295' MD. The cement reports says "floats held, full returns throughout job." 204-192 50-029-23228-00-00 MPU G-19 SB N Sands/OA/OBA Injector- Shut In 7635 4229 4480 3093 Closed 7" casing cemented with 108 bbls class G cement. TOC located at 4480' MD with USIT log dated 11/24/04. 205-055 50-029-23259-00-00 MPU E-28 SB Nb Producer-Suspended 7673 4251 5200 3312 Open The 7-5/8" was cemented with 487 sx of Class G cement in 9-7/8" hole. Assuming 20% washout, TOC is 5539' MD. A CBL was run on 5/13/2011 and TOC was 5200' MD. TBD TBD MPU E-48 Future NB Horizontal Producer TBD TBD TBD TBD Will be Open Not drilled yet Area of Review MPU J-49 Schrader Bluff (SB) NB Sand Milne Point Unit MPU J-49 Drilling Program Version 1 04/23/2025 Table of Contents 1.0 Well Summary .......................................................................................................................... 2 2.0 Management of Change Information ....................................................................................... 3 3.0 Tubular Program:..................................................................................................................... 4 4.0 Drill Pipe Information: ............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................ 5 6.0 Planned Wellbore Schematic .................................................................................................... 6 7.0 Drilling / Completion Summary ............................................................................................... 7 8.0 Mandatory Regulatory Compliance / Notifications ................................................................. 8 9.0 R/U and Preparatory Work .................................................................................................... 11 10.0 N/U 21-1/4” 2M Diverter System ............................................................................................ 12 11.0 Drill 12-1/4” Hole Section ....................................................................................................... 14 12.0 Run 9-5/8” Surface Casing ..................................................................................................... 17 13.0 Cement 9-5/8” Surface Casing ................................................................................................ 23 14.0 BOP N/U and Test................................................................................................................... 28 15.0 Drill 8-1/2” Hole Section ......................................................................................................... 29 16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion) ..................................................... 34 17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................ 39 18.0 RDMO ..................................................................................................................................... 40 19.0 Post-Rig Work ........................................................................................................................ 41 20.0 D-14 Diverter Schematic ......................................................................................................... 42 21.0 D-14 BOP Schematic ............................................................................................................... 43 22.0 Wellhead Schematic ................................................................................................................ 44 23.0 Days Vs Depth ......................................................................................................................... 45 24.0 Formation Tops & Information.............................................................................................. 46 25.0 Anticipated Drilling Hazards ................................................................................................. 47 26.0 D-14 Layout ............................................................................................................................ 49 27.0 FIT Procedure ......................................................................................................................... 51 28.0 D-14 Choke Manifold Schematic ............................................................................................ 52 29.0 Casing Design .......................................................................................................................... 53 30.0 8-1/2” Hole Section MASP ...................................................................................................... 54 31.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 55 32.0 Surface Plat (As-Built) (NAD 27) ........................................................................................... 56 Page 2 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 1.0 Well Summary Well MPU J-49 Pad Milne Point "J" Pad Planned Completion Type 3-1/2” Injection Tubing Target Reservoir(s)Schrader Bluff NB Sand Planned Well TD, MD / TVD 16,381' MD / 4,272' TVD PBTD, MD / TVD 16,381' MD / 4,272' TVD Surface Location (Governmental) 2506' FSL, 3313' FEL, Sec 28, T13N, R10E, UM, AK Surface Location (NAD 27) X= 552005 Y= 6014904 Top of Productive Horizon (Governmental)1476' FNL, 2188' FEL, Sec 28, T13N, R10E, UM, AK TPH Location (NAD 27) X= 553118 Y= 6016209 BHL (Governmental) 2149' FSL, 1779' FEL, Sec 26, T13N, R10E, UM, AK BHL (NAD 27) X= 564102 Y= 6014641 AFE Drilling Days 16 days AFE Completion Days 3 days Maximum Anticipated Pressure (Surface) 1329 Maximum Anticipated Pressure (Downhole/Reservoir) 1329 Work String 5” 19.5# S-135 NC 50 KB Elevation above MSL: 31.2 ft + 33.7 ft = 64.90 ft GL Elevation above MSL: 31.2 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25” - - - X-52 Weld 12-1/4”9-5/8” 8.681” 8.525” 10.625” 47 L-80 TXP 6,870 4,750 1,086 9-5/8” 8.835” 8.679”10.625”40 L-80 TXP 5,750 3,090 916 8-1/2”5-1/2” 4.892” 4.767” 6.050” 17 L-80 JFE Bear 7,740 6,290 397 4-1/2” 3.960”3.795” 4.714” 13.5 L-80 H625 9020 8540 279 Tubing 3-1/2” 2.992” 2.867” 4.500” 9.3 L-80 EUE 8RD 9289 7399 163 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Production 5”4.276” 3.25” 6.625” 19.5 S-135 GPDS50 36,100 43,100 560 5”4.276” 3.25” 6.625” 19.5 S-135 NC50 31,032 34,136 560 All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x 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. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each workday to sean.mclaughlin@hilcorp.com, Brad.Gorham@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to Brad.Gorham@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com,, Brad.Gorham@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Sean Mclaughlin 907.777.8300 907.223.6784 sean.mclaughlin@hilcorp.com, Drilling Engineer Brad Gorham 907-263-3917 907-250-3209 Brad.Gorham@hilcorp.com Operations Engineer Todd Sidoti 907-777-8443 907-632-4113 Todd.sidoti@hilcorp.com Geologist Katie Cunha 907.564.4786 907.802.0078 katharine.cunha@hilcorp.com Drilling Env. Coordinator Adrian Kersten 907.564.4820 907.891.0640 Adrian.kersten@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 joseph.lastufka@hilcorp.com _____________________________________________________________________________________ Revised By: JNL 4/22/2025 PROPOSED SCHEMATIC Milne Point Unit Well: MPU J-49 Last Completed:TBD PTD: TBD 5-1/2” x 4-1/2”SLOTTED LINER DETAIL Size Top (MD) Top (TVD) Btm (MD) Btm (TVD) CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"Conductor 129.5 / X-52 / Weld N/A Surface 124’N/A 9-5/8"Surface 47 / L-80 / TXP 8.525”Surface 2,500’0.0732 9-5/8"Surface 40 / L-80 / TXP 8.679”2,500’5,165’0.0758 5-1/2”Liner 250ђ Screens 17 / L-80 / JFE Bear 4.892”5,015’6,881’0.0232 4-1/2”Liner 150ђ Screens 13.5 / L-80 / Hyd 625 3.920”6,881’16,381’0.0149 TUBING DETAIL 3-1/2"Tubing 9.3 / L-80 / EUE 8RD 2.992”Surface 5,015’0.0087 OPEN HOLE / CEMENT DETAIL 24” x Driven 7 yds Concrete 12-1/4"Stg 1 –Lead 288 sx / Tail 395 sx Stg 2 –Lead 673 sx / Tail 268 sx 8-1/2”Uncemented Slotted Liner TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 11” x 4-1/2” Tubing Hanger, 4-1/2” TCII GENERAL WELL INFO API#:TBD Completion Date: TBD WELL INCLINATION DETAIL KOP @ 300’ 90° Hole Angle = 5,500’ MD JEWELRY DETAIL No Top MD Item ID Upper Completion 1 ~4,430’Viking Sliding Sleeve 2.813” X Profile (Opens Down)2.810” 2 ~4,490’Zenith Gauge Carrier 2.992” 3 ~4,550’XN Nipple, 2.813”, 2.75” No-Go 2.750” 4 ~5,019’Locater Sub, 8.25” No Go (bottom of locator spaced out 3.52’)6.261” 5 ~5,019’Bullet Seals – TXP Top Box Up x Mule Shoe (Bottom @ ~4,675’)6.261” Lower Completion 6 5,015’HES MatchSet Liner Top Packer 6.300” 7 16,381’Shoe Page 7 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 7.0 Drilling / Completion Summary MPU J-49 is a grassroots Injector planned to be drilled in the Schrader Bluff NB Sand. MPU J-49 is part of a multi well re-development program targeting the Schrader Bluff sand on Milne Point "J" Pad. MPU J-49 will be pre-produced for 30 days. The directional plan is a horizontal well with 12-1/4” surface hole with 9-5/8” surface casing set into the top of the Schrader Bluff NB Sand. An 8-1/2” lateral section will be drilled. An injection liner will be run in the open hole section. The D-14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately July 13th, 2025, pending rig schedule. Surface casing will be run to 5,165’ MD / 3,974’ 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 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 D-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. Install MPD Riser 5. Drill 8-1/2” lateral to well TD. 6. Run 4-1/2” injection liner. 7. Run 3-1/2” tubing. 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 8 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that all drilling and completion operations comply with all applicable AOGCC regulations. Operations stated in this PTD application may be altered based on sound engineering judgement as wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU J-49. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x 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. x If the BOP is used to shut in on the well in a well control situation or control fluid flow from 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. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x 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 x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. Page 9 Milne Point Unit MPU J-49 SB Injector Drilling Procedure AOGCC Regulation Variance Requests: 1) Hilcorp is requesting approval for a test period of pre-producing for up to 30 days via a reverse circulating jet pump completion. This will allow us to measure skin and evaluate the benefits of pre-producing our injectors in the future. During flow back, Hilcorp will have a 24/7 man watch while the well is online and producing. Section 19 details the steps required to make this happen. Note also that the MIT-IA has been changed from 2,500 psi to 3,500 psi. Page 10 Milne Point Unit MPU J-49 SB Injector Drilling Procedure Summary of BOP Equipment & Notifications Hole Section Equipment Test Pressure (psi) 12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only 8-1/2” x 13-5/8” x 5M Hydril “GK” Annular BOP x 13-5/8” x 5M Hydril MPL Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Hydril MPL Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 Subsequent Tests: 250/3000 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: x Well control event (BOP’s utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in PTD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 11 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 9.0 R/U and Preparatory Work 9.1 MPU J-49 will utilize a newly set 20” conductor on J 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 R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU D-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 (<80qF). 9.10 Ensure 6” liners in mud pumps. x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 12 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 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). x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source x Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID greater than 20”) 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: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 13 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 14 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 P/U 12-1/4” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Use GWD until MWD surveys are clean. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5” 19.5# S-135. x 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. x 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 NB sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoff’s, increase in pump pressure, or changes in hookload are seen x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x 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. x 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). x Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when MWD surveys clean up. x Gas hydrates have not been seen on J Pad. However, be prepared for them. In MPU they have been encountered typically around 2100’-2400’ TVD (just below permafrost). Be prepared for hydrates: Page 15 Milne Point Unit MPU J-49 SB Injector Drilling Procedure x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x 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. x 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. x AC: x There are no wells with a clearance factor of <1.0 in this interval. 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+ ppg. Depth Interval MW (ppg) Surface – Base Permafrost 8.9+ Base Permafrost - TD 9.2+ 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) 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. 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). Page 16 Milne Point Unit MPU J-49 SB Injector Drilling Procedure System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.4 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.5 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 gpm), and maximize rotation. x Pull slowly, 5 – 10 ft / minute. x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.6 TOOH and LD BHA Page 17 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8-1/2” on the location prior to running. x Note that 47# drift is 8.525” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.2 P/U shoe joint, visually verify no debris inside joint. 12.3 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 x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 18 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 12.4 Float equipment and Stage tool equipment drawings: Page 19 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 12.5 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to ~ 1000’ MD from shoe x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu) x Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x 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. 12.6 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below the permafrost. x Install centralizers over couplings on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damage to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 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 9-5/8” 47# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs Page 20 Milne Point Unit MPU J-49 SB Injector Drilling Procedure Page 21 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 12.7 Continue running 9-5/8” surface casing x Centralizers: 1 centralizer every 3rd joint to 200’ from surface x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: o 1 centralizer every 2 joints to base of conductor Page 22 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 12.8 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to surface x Ensure drifted to 8.525” 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 all 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. Page 23 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 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. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x 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 x Review test reports and ensure pump times are acceptable. x 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/U 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. Page 24 Milne Point Unit MPU J-49 SB Injector Drilling Procedure Estimated 1st Stage Total Cement Volume: Cement Slurry Design (1st Stage Cement Job): 13.9 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. 13.10 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. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be bumped. 13.12 Displacement calculation is in the Stage 1 Table shown above. 80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the ES cementer is tuned spacer to minimize the risk of flash setting cement 13.13 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. 13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting 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. Section Calculation Vol (bbl) Vol (ft3) Sacks 12-1/4" OH x 9-5/8" Csg (5165' - 1000' - 2500') x 0.0558 bpf X 1.3 =120.7 677.4 Total Lead 120.7 677.4 288 12-1/4" OH x 9-5/8" Csg (1000') x 0.0558 bpf X 1.3 = 72.5 406.8 9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.0 Total Tail 81.6 457.8 395 Displacement 2500' x 0.0732 bpf + (5165' - 1000' - 2500') x 0.0558 bpf X 1.3 =376.0Tail Lead Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 25 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 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 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. 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 26 Milne Point Unit MPU J-49 SB Injector Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre-job safety meeting. 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 cmt per below recipe for the 2 nd 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 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): 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 is in the Stage 2 table above. Section Calculation Vol (bbl) Vol (ft3) Sacks 20# Conductor x 9-5/8" Csg 124' x 0.23 bpf = 31.0 173.7 12-1/4" OH x 9-5/8" Csg (2000' - 124') x 0.0558 bpf X 3 = 314.0 1761.8 Total Lead 345.0 1935.5 673 12-1/4" OH x 9-5/8" Csg (2500' - 2000') x 0.0558 bpf X 2 = 55.8 312.9 Total Tail 55.8 312.9 268 Displacement 2500' x 0.0732 bpf =183.0Tail Lead Lead Slurry Tail Slurry System ArcticCem HalCem Density 10.7 lb/gal 15.8 lb/gal Yield 2.88 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk Page 27 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 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 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 13.29 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: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x 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 brad.gorham@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 28 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 14.0 BOP N/U and Test 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: x 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 x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5” VBRs x N/U bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 Run 5” BOP test plug 14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Test 4-1/2” x 7” rams with the 4-1/2” and 5” test joints x Test 2-7/8” x 5” rams with the 3-1/2” and 5” test joints x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&J Pad for injection. 14.7 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.8 Set wearbushing in wellhead. 14.9 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6” liners in mud pumps. Page 29 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 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 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC 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 pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.9 ppg FIT is the minimum required to drill ahead x 9.9 ppg provides >25 bbls based on 9.2 ppg MW, 8.46 ppg PP (swabbed kick at 9.2 ppg BHP) 15.8 POOH & LD Cleanout BHA 15.9 P/U 8-1/2” RSS directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is R/U and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5” 19.5# S-135 DS50 & NC50. x Run a ported float in the production hole section. * Email digital casing test and FIT to AOGCC upon completion of FIT. - mgr Page 30 Milne Point Unit MPU J-49 SB Injector Drilling Procedure Schrader Bluff Bit Jetting Guidelines Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 15.10 8-1/2” hole section mud program summary: x 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. x 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. x 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 cleaning x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x 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 FloPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <7 <11.0 <100 Page 31 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 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 FLO-VIS 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-CARB 10 (verify)50 lb sx 10 SAFE-CARB 20 (verify)50 lb sx 10 Soda Ash 50 lb sx 0.5 15.11 TIH with 8-1/2” directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg FloPro drilling fluid 15.13 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x 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 0.5% lubes 15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm x RPM: 120+ x 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. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every stand (confirm frequency with co man) x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Surveys can be taken more frequently if deemed necessary. x 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. x Use ADR to stay in section. x 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. Page 32 Milne Point Unit MPU J-49 SB Injector Drilling Procedure x Target ROP is as fast as we can clean the hole (under 250 fph) without having to backream connections x Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up on connections x 8-1/2” Lateral A/C: x E-28 has a 0.032 CF. The E-28 lateral will be completely cemented prior to drilling the J-49 production interval. x Schrader Bluff NB Concretions: 3-4 % Historically 15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x 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. x Attempt to sidetrack low and right in a fast drilling interval where the wellbore is headed up. x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. x 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 (minimum 4X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed x Rack back a stand at each bottoms up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. x Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg 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. x 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 viscosified brine. x Proposed brine blend (aiming for an 8 on the 6 RPM reading) - KCl: 7.1bbp for 2% NaCl: 60.9 ppg for 9.4 ppg Lotorq: 1.5% Lube 776: 1.5% Page 33 Milne Point Unit MPU J-49 SB Injector Drilling Procedure Soda Ash: as needed for 9.5pH Busan 1060: 0.42 ppb Flo-Vis Plus: 1.25 ppb x 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. Note: PST test is NOT required. x Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses) x Rotate at maximum rpm that can be sustained. x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but adjust as hole conditions dictate. x When pulling across any OHST depths, turn pumps off and rotary off to minimize disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct hole section, check with ABI compared to as drilled surveys 15.20 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.21 Monitor well for flow. Increase mud weight if necessary x 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 x If necessary, increase MW at shoe for any higher than expected pressure seen x Ensure fluid coming out of hole has passed a PST at the possum belly 15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Page 34 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion) NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and run them slick. 16.1.Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” injection liner with slotted liner, the following well control response procedure will be followed: x With a 5-1/2” joint across the BOP: P/U & M/U the 5” safety joint (with 5-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 5-1/2” liner. x With 4-1/2” joint across BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” liner. 16.2. Confirm VBR’s have been tested to cover 3-1/2” and 5” pipe sizes to 250 psi low/3000 psi high. 16.3. R/U 5-1/2” and 4-1/2” liner running equipment. x Ensure 5-1/2” and 4-1/2” Hydril 625 x DS-50 crossovers are on rig floor and M/U to FOSV. x Ensure the liner has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.4. Run 5-1/2” x 4-1/2” injection liner. x Injection liner will be a combination of slotted and solid joints. Every third joint in the open hole is to be a slotted joint. Confirm with OE. x Uppermost 3,000’ will be 5-1/2”. x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each jt outside of the surface shoe. This is to mitigate sticking risk while running inner string. x Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm Page 35 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 5-1/2” 17# L-80 JFE Bear Casing OD Minimum Optimum Maximum Operating Torque 5.5” 6,660 ft-lbs 7,400 ft-lbs 8,140 ft-lbs Page 36 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 4-1/2” 13.5# L-80 H625 Casing OD Minimum Optimum Maximum Operating Torque 4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 37 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection. 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 4-1/2” liner. 16.9. Note: PU, SO, 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 with liner 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. x Ensure 5” DP/HWDP has been drifted x 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 + SO 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 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 down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Page 38 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. 16.20. Bleed DP pressure to 0 psi. 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 1,500 psi for 10 minutes charted. 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. PU 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. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 39 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 17.0 Run 3-1/2” Tubing (Upper Completion) 17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). 17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. x Ensure wear bushing is pulled. x Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. x Monitor displacement from wellbore while RIH. 3-1/2” 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs 3-½” Upper Completion Running Order x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle) x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” “XN” nipple at TBD (Set below 70 degrees) x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” SGM-FS XDPG Gauge at TBD x 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing x Tubing hanger with 3-1/2” EUE 8RD pin down 17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals engaged. 17.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all space out pups below the first full joint of the completion. Page 40 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 17.5 Makeup the tubing hanger and landing joint. 17.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 17.7 Reverse circulate the well with brine and 1% corrosion inhibitor. 17.8 Freeze protect the tubing and IA to ~2500’ MD. 17.9 Land hanger. RILDs and test hanger. 17.10 Continue pressurizing the annulus to 3500 psi and test for 30 charted minutes. i. Note this test must be witnessed by the AOGCC representative. 17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 17.12 Pull BPV. Set TWC. Test tree to 5000 psi. 17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect. 17.14 Secure the tree and cellar. 18.0 RDMO 18. RDMO D-14 Page 41 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 19.0 Post-Rig Work Operations-Convert well on surface with hard line to a jet pump producer. 19.1 MU surface lines from power fluid header to existing IA. a. Pressure test lines at existing power fluid header pressure (3,600 psi) 19.2 Rig up hardline to neighboring wells production header and test header. Pressure test to 3600 psi. 19.3 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi. 19.4 Shift Sliding sleeve open 19.5 Set 12B jet pump 19.6 RDMO SL/FB- After 30 days of production 19.7 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi. 19.8 FB circ IA with corrosion inhibited brine down to SS with a FP cap down to 2000’ on IA 19.9 Pull Jet Pump 19.10 Shift SS closed 19.11 MIT-IA test to 2000 psi 19.12 POI 19.13 After 5 days of stabilized injection MIT-IA to 2000 psi (Charted and state witnessed) Page 42 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 20.0 D-14 Diverter Schematic Page 43 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 21.0 D-14 BOP Schematic 2-7/8” x 5” VBR Page 44 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 22.0 Wellhead Schematic Page 45 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 23.0 Days Vs Depth Page 46 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 24.0 Formation Tops & Information MPU J-49 Formations TVD (ft) TVDss (ft) MD (ft) Formation Pressure (psi) EMW (ppg) SV6 892 892 902 392 8.46 Base Permafrost 1938 1938 2044 853 8.46 SV1 2131 2131 2258 937 8.46 UG_LA3 3359 3359 3660 1478 8.46 UG_MB 3599 3599 4003 1583 8.46 SB_NA 3945 3945 4865 1735 8.46 SB_NB 3976 3976 5186 1749 8.46 J Pad Data Sheet Formation Description Page 47 Milne Point Unit MPU J-49 SB Injector 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. 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 a number of wells in close 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. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well specific A/C: x There are no wells with a clearance factor of < 1.0. 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 H2S. I-04A had 36ppm H2S (2012). Page 48 Milne Point Unit MPU J-49 SB Injector 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 49 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up appropriately 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 (5) faults 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 H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal 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. Well specific AC: 8-1/2” Lateral A/C: x E-28 has a 0.032 CF. The E-28 lateral will be completely cemented prior to drilling the J-49 production interval. Page 50 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 26.0 D-14 Layout Page 51 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 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 52 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 28.0 D-14 Choke Manifold Schematic Page 53 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 29.0 Casing Design Page 54 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 30.0 8-1/2” Hole Section MASP Page 55 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 31.0 Spider Plot (NAD 27) (Governmental Sections) Page 56 Milne Point Unit MPU J-49 SB Injector Drilling Procedure 32.0 Surface Plat (As-Built) (NAD 27) Standard Proposal Report 09 April, 2025 Plan: MPU J-49 wp03 Hilcorp Alaska, LLC Milne Point M Pt J Pad Plan: MPU J-49 MPU J-49 07501500225030003750True Vertical Depth (1500 usft/in)-1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500Vertical Section at 99.00° (1500 usft/in)MPU J-49 wp02 tgt01.5MPU J-49 wp01 tgt12MPU J-49 wp01 tgt01MPU J-49 wp01 tgt10MPU J-49 wp01 tgt11MPU J-49 wp03 tgt04MPU J-49 wp01 tgt14MPU J-49 wp01 tgt07MPU J-49 wp01 tgt05MPU J-49 wp01 tgt06MPU J-49 wp03 tgt03MPU J-49 wp01 tgt13MPU J-49 wp01 tgt15MPU J-49 wp01 tgt08MPU J-49 wp03 tgt02MPU J-49 wp02 tgt04.5MPU J-49 wp01 tgt099-5/8" Surface Casing4-1/2" Production Casin5001000150020002500300035004000450050005500600065007000750080008500900095001000010500110001150012000125001300013500140001450015000155001600016381MPU J-49 wp03Start Dir 3º/100' : 300' MD, 300'TVDStart Dir 4º/100' : 1050' MD, 1030.94'TVDEnd Dir : 1614.54' MD, 1552.27' TVDStart Dir 4º/100' : 2672.62' MD, 2503.03'TVDEnd Dir : 4964.31' MD, 3956.67' TVDBegin GeosteeringTotal Depth : 16381.35' MD, 4271.9' TVDSV6Base PermafrostSV1UG_LA3UG_MBSB_NASB_NBHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU J-4931.20+N/-S+E/-WNorthingEastingLatittudeLongitude0.000.006014903.60552005.45 70° 27' 5.2470 N 149° 34' 32.4491 WSURVEY PROGRAMDate: 2025-03-20T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.70 1500.00 MPU J-49 wp03 (MPU J-49) GYD_Quest GWD1500.00 5165.00 MPU J-49 wp03 (MPU J-49) 3_MWD+IFR2+MS+Sag5165.00 16381.35 MPU J-49 wp03 (MPU J-49) GYD_Quest GWDFORMATION TOP DETAILSTVDPathTVDssPath MDPath Formation891.90 827.00 901.80 SV61937.90 1873.00 2043.70 Base Permafrost2130.90 2066.00 2258.49 SV13358.90 3294.00 3660.25 UG_LA33598.90 3534.00 4002.86 UG_MB3944.90 3880.00 4864.88 SB_NA3975.90 3911.00 5185.59 SB_NBREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-49, True NorthVertical (TVD) Reference:J-49 as staked @ 64.90usft (Original Well Elev)Measured Depth Reference:J-49 as staked @ 64.90usft (Original Well Elev)Calculation Method:Minimum CurvatureProject:Milne PointSite:M Pt J PadWell:Plan: MPU J-49Wellbore:MPU J-49Design:MPU J-49 wp03CASING DETAILSTVD TVDSS MD SizeName3974.16 3909.26 5165.00 9-5/8 9-5/8" Surface Casing4271.90 4207.00 16381.35 4-1/2 4-1/2" Production CasingSECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.002 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD3 800.00 15.00 285.00 794.31 16.84 -62.86 3.00 285.00 -64.724 1050.00 22.42 288.41 1030.94 40.31 -139.46 3.00 10.00 -144.05 Start Dir 4º/100' : 1050' MD, 1030.94'TVD5 1614.54 26.03 344.78 1552.27 195.85 -275.92 4.00 107.91 -303.16 End Dir : 1614.54' MD, 1552.27' TVD6 2672.62 26.03 344.78 2503.03 643.88 -397.84 0.00 0.00 -493.67 Start Dir 4º/100' : 2672.62' MD, 2503.03'TVD7 4964.31 85.00 89.00 3956.67 1293.96 901.09 4.00 104.97 687.58 End Dir : 4964.31' MD, 3956.67' TVD8 5164.31 85.00 89.00 3974.10 1297.44 1100.30 0.00 0.00 883.79 Begin Geosteering9 5539.13 90.22 94.39 3989.73 1286.35 1474.37 2.00 46.00 1254.9910 5700.00 90.22 94.39 3989.11 1274.05 1634.76 0.00 0.00 1415.33 MPU J-49 wp02 tgt01.511 6130.51 90.38 82.55 3986.82 1285.55 2064.35 2.75 -89.18 1837.8312 6209.29 90.38 82.55 3986.29 1295.77 2142.46 0.00 0.00 1913.3813 6518.53 89.45 91.00 3986.74 1313.16 2450.93 2.75 96.31 2215.3314 7368.53 89.45 91.00 3994.90 1298.32 3300.76 0.00 0.00 3057.02 MPU J-49 wp03 tgt0315 8267.92 88.62 117.97 4010.34 1075.47 4163.40 3.00 91.96 3943.9016 8374.29 88.62 117.97 4012.90 1025.59 4257.32 0.00 0.00 4044.47 MPU J-49 wp03 tgt0417 8429.02 89.28 119.48 4013.90 999.30 4305.30 3.00 66.21 4095.9718 8576.82 89.28 119.48 4015.75 926.58 4433.96 0.00 0.00 4234.4319 9099.29 89.19 103.80 4022.76 734.54 4918.06 3.00 -90.44 4742.6120 9389.29 89.19 103.80 4026.86 665.37 5199.66 0.00 0.00 5031.5621 9602.60 89.18 97.40 4029.90 626.16 5409.21 3.00 -90.14 5244.66 MPU J-49 wp01 tgt0522 9806.91 84.07 97.40 4041.92 599.89 5611.39 2.50 179.95 5448.4623 9868.38 84.07 97.40 4048.27 592.01 5672.03 0.00 0.00 5509.5824 10039.89 88.36 97.43 4059.58 569.92 5841.69 2.50 0.34 5680.6125 10679.89 88.36 97.43 4077.90 487.20 6476.06 0.00 0.00 6320.11 MPU J-49 wp01 tgt0726 10716.09 89.27 97.42 4078.65 482.52 6511.95 2.50 -0.72 6356.2927 11359.23 89.27 97.42 4086.90 399.49 7149.64 0.00 0.00 6999.13 MPU J-49 wp01 tgt0828 11568.51 84.08 96.71 4099.04 373.80 7356.92 2.50 -172.25 7207.8729 11708.25 84.08 96.71 4113.45 357.55 7494.96 0.00 0.00 7346.7530 11850.74 86.46 94.05 4125.20 344.25 7636.31 2.50 -48.21 7488.4431 12250.74 86.46 94.05 4149.90 316.05 8034.55 0.00 0.00 7886.19 MPU J-49 wp01 tgt1032 12334.30 88.54 93.82 4153.55 310.32 8117.84 2.50 -6.32 7969.3533 13170.33 88.54 93.82 4174.90 254.64 8951.73 0.00 0.00 8801.69 MPU J-49 wp01 tgt1134 13229.61 88.23 92.37 4176.57 251.44 9010.90 2.50 -101.85 8860.6335 13681.11 88.23 92.37 4190.50 232.79 9461.80 0.00 0.00 9308.9036 13986.21 88.24 100.00 4199.90 199.96 9764.76 2.50 90.06 9613.26 MPU J-49 wp01 tgt1237 14058.26 88.35 101.80 4202.04 186.35 9835.47 2.50 86.42 9685.2338 14575.28 88.35 101.80 4216.90 80.67 10341.37 0.00 0.00 10201.43 MPU J-49 wp01 tgt1339 14585.38 88.29 102.04 4217.20 78.59 10351.24 2.50 103.70 10211.5140 14911.25 88.29 102.04 4226.90 10.62 10669.80 0.00 0.00 10536.77 MPU J-49 wp01 tgt1441 14994.69 88.24 104.13 4229.42 -8.26 10751.02 2.50 91.38 10619.9542 16381.35 88.24 104.13 4271.90 -346.62 12095.10 0.00 0.00 12000.41 MPU J-49 wp01 tgt15 Total Depth : 16381.35' MD, 4271.9' TVD -4500-3750-3000-2250-1500-7500750150022503000375045005250South(-)/North(+) (1500 usft/in)-1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750West(-)/East(+) (1500 usft/in)MPU J-49 wp01 tgt09MPU J-49 wp02 tgt04.5MPU J-49 wp03 tgt02MPU J-49 wp01 tgt08MPU J-49 wp01 tgt15MPU J-49 wp01 tgt13MPU J-49 wp03 tgt03MPU J-49 wp01 tgt06MPU J-49 wp01 tgt05MPU J-49 wp01 tgt07MPU J-49 wp01 tgt14MPU J-49 wp03 tgt04MPU J-49 wp01 tgt11MPU J-49 wp01 tgt10MPU J-49 wp01 tgt01MPU J-49 wp01 tgt12MPU J-49 wp02 tgt01.59-5/8" Surface Casing4-1/2" Production Casing500150022503 5 00 3 7 504000 42504272MPU J-49 wp03Start Dir 3º/100' : 300' MD, 300'TVDStart Dir 4º/100' : 1050' MD, 1030.94'TVDEnd Dir : 1614.54' MD, 1552.27' TVDStart Dir 4º/100' : 2672.62' MD, 2503.03'TVDEnd Dir : 4964.31' MD, 3956.67' TVDBegin GeosteeringTotal Depth : 16381.35' MD, 4271.9' TVDCASING DETAILSTVDTVDSS MDSize Name3974.16 3909.26 5165.00 9-5/8 9-5/8" Surface Casing4271.90 4207.00 16381.35 4-1/2 4-1/2" Production CasingProject: Milne PointSite: M Pt J PadWell: Plan: MPU J-49Wellbore: MPU J-49Plan: MPU J-49 wp03WELL DETAILS: Plan: MPU J-4931.20+N/-S +E/-W Northing Easting Latittude Longitude0.00 0.006014903.60 552005.45 70° 27' 5.2470 N149° 34' 32.4491 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-49, True NorthVertical (TVD) Reference:J-49 as staked @ 64.90usft (Original Well Elev)Measured Depth Reference:J-49 as staked @ 64.90usft (Original Well Elev)Calculation Method:Minimum Curvature Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Standard Proposal Report Well: Wellbore: Plan: MPU J-49 MPU J-49 Survey Calculation Method:Minimum Curvature J-49 as staked @ 64.90usft (Original Well Elev) Design:MPU J-49 wp03 Database:Alaska MD Reference:J-49 as staked @ 64.90usft (Original Well Elev) North Reference: Well Plan: MPU J-49 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: Grid Convergence: M Pt J Pad, TR-13-10 usft Map usft usft °0.40Slot Radius:"0 6,013,415.23 551,435.10 5.00 70° 26' 50.6471 N 149° 34' 49.5031 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Plan: MPU J-49 usft usft 0.00 0.00 6,014,903.60 552,005.45 31.20Wellhead Elevation:usft0.50 70° 27' 5.2470 N 149° 34' 32.4491 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU J-49 Model NameMagnetics BGGM2024 6/20/2025 13.71 80.69 57,200.33048735 Phase:Version: Audit Notes: Design MPU J-49 wp03 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:33.70 99.000.000.0033.70 4/9/2025 3:40:23PM COMPASS 5000.17 Build 04 Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Standard Proposal Report Well: Wellbore: Plan: MPU J-49 MPU J-49 Survey Calculation Method:Minimum Curvature J-49 as staked @ 64.90usft (Original Well Elev) Design:MPU J-49 wp03 Database:Alaska MD Reference:J-49 as staked @ 64.90usft (Original Well Elev) North Reference: Well Plan: MPU J-49 True Inclination (°) Azimuth (°) +E/-W (usft) Tool Face (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections TVD System usft 0.000.000.000.000.000.0033.700.000.0033.70 -31.20 0.000.000.000.000.000.00300.000.000.00300.00 235.10 285.000.003.003.00-62.8616.84794.31285.0015.00800.00 729.41 10.001.362.973.00-139.4640.311,030.94288.4122.421,050.00 966.04 107.919.990.644.00-275.92195.851,552.27344.7826.031,614.54 1,487.37 0.000.000.000.00-397.84643.882,503.03344.7826.032,672.62 2,438.13 104.974.552.574.00901.091,293.963,956.6789.0085.004,964.31 3,891.77 0.000.000.000.001,100.301,297.443,974.1089.0085.005,164.31 3,909.20 46.001.441.392.001,474.371,286.353,989.7394.3990.225,539.13 3,924.83 0.000.000.000.001,634.761,274.053,989.1194.3990.225,700.00 3,924.21 -89.18-2.750.042.752,064.351,285.553,986.8282.5590.386,130.51 3,921.92 0.000.000.000.002,142.461,295.773,986.2982.5590.386,209.29 3,921.39 96.312.73-0.302.752,450.931,313.163,986.7491.0089.456,518.53 3,921.84 0.000.000.000.003,300.761,298.323,994.9091.0089.457,368.53 3,930.00 91.963.00-0.093.004,163.401,075.474,010.34117.9788.628,267.92 3,945.44 0.000.000.000.004,257.321,025.594,012.90117.9788.628,374.29 3,948.00 66.212.751.213.004,305.30999.304,013.90119.4889.288,429.02 3,949.00 0.000.000.000.004,433.96926.584,015.75119.4889.288,576.82 3,950.85 -90.44-3.00-0.023.004,918.06734.544,022.76103.8089.199,099.29 3,957.86 0.000.000.000.005,199.66665.374,026.86103.8089.199,389.29 3,961.96 -90.14-3.000.003.005,409.21626.164,029.9097.4089.189,602.60 3,965.00 179.950.00-2.502.505,611.39599.894,041.9297.4084.079,806.91 3,977.02 0.000.000.000.005,672.03592.014,048.2797.4084.079,868.38 3,983.37 0.340.012.502.505,841.69569.924,059.5897.4388.3610,039.89 3,994.68 0.000.000.000.006,476.06487.204,077.9097.4388.3610,679.89 4,013.00 -0.72-0.032.502.506,511.95482.524,078.6597.4289.2710,716.09 4,013.75 0.000.000.000.007,149.64399.494,086.9097.4289.2711,359.23 4,022.00 -172.25-0.34-2.482.507,356.92373.804,099.0496.7184.0811,568.51 4,034.14 0.000.000.000.007,494.96357.554,113.4596.7184.0811,708.25 4,048.55 -48.21-1.871.672.507,636.31344.254,125.2094.0586.4611,850.74 4,060.30 0.000.000.000.008,034.55316.054,149.9094.0586.4612,250.74 4,085.00 -6.32-0.282.482.508,117.84310.324,153.5593.8288.5412,334.30 4,088.65 0.000.000.000.008,951.73254.644,174.9093.8288.5413,170.33 4,110.00 -101.85-2.45-0.512.509,010.90251.444,176.5792.3788.2313,229.61 4,111.67 0.000.000.000.009,461.80232.794,190.5092.3788.2313,681.11 4,125.60 90.062.500.002.509,764.76199.964,199.90100.0088.2413,986.21 4,135.00 86.422.500.162.509,835.47186.354,202.04101.8088.3514,058.26 4,137.14 0.000.000.000.0010,341.3780.674,216.90101.8088.3514,575.28 4,152.00 103.702.43-0.592.5010,351.2478.594,217.20102.0488.2914,585.38 4,152.30 0.000.000.000.0010,669.8010.624,226.90102.0488.2914,911.25 4,162.00 91.382.50-0.062.5010,751.02-8.264,229.42104.1388.2414,994.69 4,164.52 0.000.000.000.0012,095.10-346.624,271.90104.1388.2416,381.35 4,207.00 4/9/2025 3:40:23PM COMPASS 5000.17 Build 04 Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Standard Proposal Report Well: Wellbore: Plan: MPU J-49 MPU J-49 Survey Calculation Method:Minimum Curvature J-49 as staked @ 64.90usft (Original Well Elev) Design:MPU J-49 wp03 Database:Alaska MD Reference:J-49 as staked @ 64.90usft (Original Well Elev) North Reference: Well Plan: MPU J-49 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS -31.20 Vert Section 33.70 0.00 33.70 0.00 0.000.00 552,005.456,014,903.60-31.20 0.00 0.00 100.00 0.00 100.00 0.00 0.000.00 552,005.456,014,903.6035.10 0.00 0.00 200.00 0.00 200.00 0.00 0.000.00 552,005.456,014,903.60135.10 0.00 0.00 300.00 0.00 300.00 0.00 0.000.00 552,005.456,014,903.60235.10 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 400.00 3.00 399.95 0.68 -2.53285.00 552,002.926,014,904.26335.05 3.00 -2.60 500.00 6.00 499.63 2.71 -10.11285.00 551,995.336,014,906.24434.73 3.00 -10.41 600.00 9.00 598.77 6.09 -22.71285.00 551,982.706,014,909.53533.87 3.00 -23.38 700.00 12.00 697.08 10.80 -40.31285.00 551,965.076,014,914.12632.18 3.00 -41.51 800.00 15.00 794.31 16.84 -62.86285.00 551,942.486,014,920.00729.41 3.00 -64.72 900.00 17.96 890.19 24.62 -90.14286.69 551,915.156,014,927.59825.29 3.00 -92.88 901.80 18.02 891.90 24.78 -90.67286.71 551,914.626,014,927.75827.00 3.00 -93.43 SV6 1,000.00 20.93 984.47 34.55 -121.91287.91 551,883.316,014,937.29919.57 3.00 -125.81 1,050.00 22.42 1,030.94 40.31 -139.46288.41 551,865.736,014,942.93966.04 3.00 -144.05 Start Dir 4º/100' : 1050' MD, 1030.94'TVD 1,100.00 21.89 1,077.25 47.04 -157.05293.52 551,848.096,014,949.531,012.35 4.00 -162.48 1,200.00 21.32 1,170.26 64.72 -189.18304.29 551,815.856,014,966.991,105.36 4.00 -196.97 1,300.00 21.45 1,263.42 87.96 -217.08315.26 551,787.796,014,990.031,198.52 4.00 -228.16 1,400.00 22.28 1,356.25 116.64 -240.62325.78 551,764.056,015,018.551,291.35 4.00 -255.90 1,500.00 23.74 1,448.33 150.62 -259.69335.33 551,744.746,015,052.391,383.43 4.00 -280.05 1,600.00 25.71 1,539.19 189.74 -274.19343.67 551,729.976,015,091.401,474.29 4.00 -300.50 1,614.54 26.03 1,552.27 195.85 -275.92344.78 551,728.206,015,097.501,487.37 4.00 -303.16 End Dir : 1614.54' MD, 1552.27' TVD 1,700.00 26.03 1,629.06 232.03 -285.77344.78 551,718.106,015,133.611,564.16 0.00 -318.55 1,800.00 26.03 1,718.92 274.38 -297.29344.78 551,706.286,015,175.871,654.02 0.00 -336.55 1,900.00 26.03 1,808.77 316.72 -308.81344.78 551,694.476,015,218.131,743.87 0.00 -354.56 2,000.00 26.03 1,898.63 359.06 -320.33344.78 551,682.656,015,260.391,833.73 0.00 -372.56 2,043.70 26.03 1,937.90 377.57 -325.37344.78 551,677.486,015,278.851,873.00 0.00 -380.43 Base Permafrost 2,100.00 26.03 1,988.49 401.41 -331.86344.78 551,670.836,015,302.641,923.59 0.00 -390.57 2,200.00 26.03 2,078.34 443.75 -343.38344.78 551,659.016,015,344.902,013.44 0.00 -408.57 2,258.49 26.03 2,130.90 468.52 -350.12344.78 551,652.106,015,369.622,066.00 0.00 -419.10 SV1 2,300.00 26.03 2,168.20 486.10 -354.90344.78 551,647.206,015,387.162,103.30 0.00 -426.58 2,400.00 26.03 2,258.06 528.44 -366.43344.78 551,635.386,015,429.422,193.16 0.00 -444.58 2,500.00 26.03 2,347.91 570.78 -377.95344.78 551,623.566,015,471.682,283.01 0.00 -462.59 2,600.00 26.03 2,437.77 613.13 -389.47344.78 551,611.756,015,513.942,372.87 0.00 -480.59 2,672.62 26.03 2,503.02 643.88 -397.84344.78 551,603.166,015,544.622,438.12 0.00 -493.67 Start Dir 4º/100' : 2672.62' MD, 2503.03'TVD 2,700.00 25.77 2,527.65 655.48 -400.74347.21 551,600.196,015,556.202,462.75 4.00 -498.34 2,800.00 25.17 2,617.97 697.91 -406.88356.42 551,593.756,015,598.592,553.07 4.00 -511.05 2,900.00 25.15 2,708.52 740.29 -406.055.83 551,594.296,015,640.972,643.62 4.00 -516.85 3,000.00 25.73 2,798.86 782.41 -398.2415.06 551,601.796,015,683.132,733.96 4.00 -515.74 3,100.00 26.85 2,888.55 824.05 -383.5123.73 551,616.246,015,724.882,823.65 4.00 -507.70 4/9/2025 3:40:23PM COMPASS 5000.17 Build 04 Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Standard Proposal Report Well: Wellbore: Plan: MPU J-49 MPU J-49 Survey Calculation Method:Minimum Curvature J-49 as staked @ 64.90usft (Original Well Elev) Design:MPU J-49 wp03 Database:Alaska MD Reference:J-49 as staked @ 64.90usft (Original Well Elev) North Reference: Well Plan: MPU J-49 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 2,912.26 Vert Section 3,200.00 28.46 2,977.16 865.03 -361.9231.63 551,637.546,015,766.002,912.26 4.00 -492.78 3,300.00 30.48 3,064.24 905.14 -333.5738.66 551,665.616,015,806.302,999.34 4.00 -471.05 3,400.00 32.83 3,149.38 944.18 -298.6044.83 551,700.306,015,845.583,084.48 4.00 -442.62 3,500.00 35.44 3,232.16 981.97 -257.1850.23 551,741.456,015,883.663,167.26 4.00 -407.63 3,600.00 38.27 3,312.18 1,018.32 -209.5254.95 551,788.856,015,920.333,247.28 4.00 -366.24 3,660.25 40.06 3,358.90 1,039.45 -177.8957.52 551,820.336,015,941.683,294.00 4.00 -338.31 UG_LA3 3,700.00 41.26 3,389.05 1,053.05 -155.8559.10 551,842.276,015,955.433,324.15 4.00 -318.67 3,800.00 44.39 3,462.40 1,085.99 -96.4362.78 551,901.466,015,988.793,397.50 4.00 -265.13 3,900.00 47.62 3,531.86 1,116.99 -31.5466.06 551,966.126,016,020.233,466.96 4.00 -205.89 4,000.00 50.93 3,597.10 1,145.89 38.4969.02 552,035.946,016,049.623,532.20 4.00 -141.24 4,002.86 51.03 3,598.90 1,146.68 40.5669.10 552,038.016,016,050.433,534.00 4.00 -139.32 UG_MB 4,100.00 54.32 3,657.80 1,172.55 113.3371.70 552,110.586,016,076.803,592.90 4.00 -71.50 4,200.00 57.75 3,713.67 1,196.84 192.6074.17 552,189.686,016,101.643,648.77 4.00 3.00 4,300.00 61.24 3,764.43 1,218.65 275.9376.46 552,272.856,016,124.033,699.53 4.00 81.90 4,400.00 64.75 3,809.83 1,237.87 362.9178.60 552,359.686,016,143.853,744.93 4.00 164.80 4,500.00 68.30 3,849.66 1,254.39 453.1180.61 552,449.756,016,161.003,784.76 4.00 251.30 4,600.00 71.87 3,883.72 1,268.15 546.1082.53 552,542.636,016,175.413,818.82 4.00 340.99 4,700.00 75.46 3,911.84 1,279.08 641.4284.37 552,637.866,016,187.003,846.94 4.00 433.43 4,800.00 79.06 3,933.89 1,287.12 738.6086.16 552,734.986,016,195.723,868.99 4.00 528.16 4,864.88 81.40 3,944.90 1,290.77 802.4387.29 552,798.786,016,199.823,880.00 4.00 590.63 SB_NA 4,900.00 82.67 3,949.76 1,292.23 837.1887.90 552,833.516,016,201.523,884.86 4.00 624.73 4,964.31 85.00 3,956.67 1,293.96 901.0989.00 552,897.406,016,203.693,891.77 4.00 687.58 End Dir : 4964.31' MD, 3956.67' TVD 5,000.00 85.00 3,959.78 1,294.58 936.6489.00 552,932.946,016,204.563,894.88 0.00 722.59 5,100.00 85.00 3,968.50 1,296.32 1,036.2589.00 553,032.526,016,207.003,903.60 0.00 820.70 5,164.31 85.00 3,974.10 1,297.44 1,100.3089.00 553,096.566,016,208.563,909.20 0.00 883.79 5,165.00 85.01 3,974.16 1,297.45 1,100.9989.01 553,097.256,016,208.583,909.26 2.00 884.47 9-5/8" Surface Casing 5,165.10 85.01 3,974.17 1,297.45 1,101.0989.01 553,097.356,016,208.583,909.27 2.00 884.57 Begin Geosteering 5,185.59 85.30 3,975.90 1,297.75 1,121.5089.31 553,117.766,016,209.023,911.00 2.00 904.68 SB_NB 5,200.00 85.50 3,977.06 1,297.90 1,135.8789.52 553,132.126,016,209.273,912.16 2.00 918.85 5,300.00 86.89 3,983.70 1,297.49 1,235.6490.95 553,231.886,016,209.563,918.80 2.00 1,017.45 5,400.00 88.28 3,987.91 1,294.57 1,335.5092.39 553,331.766,016,207.343,923.01 2.00 1,116.54 5,500.00 89.68 3,989.70 1,289.15 1,435.3393.82 553,431.616,016,202.613,924.80 2.00 1,216.00 5,539.13 90.22 3,989.73 1,286.35 1,474.3794.39 553,470.666,016,200.083,924.83 2.00 1,254.99 5,600.00 90.22 3,989.50 1,281.70 1,535.0694.39 553,531.376,016,195.853,924.60 0.00 1,315.65 5,700.00 90.22 3,989.11 1,274.05 1,634.7694.39 553,631.126,016,188.903,924.21 0.00 1,415.33 5,800.00 90.26 3,988.69 1,268.80 1,734.6191.64 553,731.006,016,184.353,923.79 2.75 1,514.77 5,900.00 90.30 3,988.20 1,268.34 1,834.6088.89 553,830.986,016,184.593,923.30 2.75 1,613.60 6,000.00 90.34 3,987.65 1,272.69 1,934.5086.14 553,930.836,016,189.633,922.75 2.75 1,711.59 4/9/2025 3:40:23PM COMPASS 5000.17 Build 04 Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Standard Proposal Report Well: Wellbore: Plan: MPU J-49 MPU J-49 Survey Calculation Method:Minimum Curvature J-49 as staked @ 64.90usft (Original Well Elev) Design:MPU J-49 wp03 Database:Alaska MD Reference:J-49 as staked @ 64.90usft (Original Well Elev) North Reference: Well Plan: MPU J-49 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,922.13 Vert Section 6,100.00 90.37 3,987.03 1,281.82 2,034.0783.39 554,030.336,016,199.453,922.13 2.75 1,808.50 6,130.51 90.38 3,986.82 1,285.55 2,064.3582.55 554,060.586,016,203.403,921.92 2.75 1,837.83 6,209.29 90.38 3,986.29 1,295.77 2,142.4682.55 554,138.616,016,214.163,921.39 0.00 1,913.38 6,300.00 90.11 3,985.90 1,305.58 2,232.6385.03 554,228.706,016,224.613,921.00 2.75 2,000.90 6,400.00 89.81 3,985.97 1,311.88 2,332.4287.76 554,328.436,016,231.593,921.07 2.75 2,098.48 6,500.00 89.51 3,986.57 1,313.40 2,432.4090.49 554,428.396,016,233.813,921.67 2.75 2,196.99 6,518.53 89.45 3,986.74 1,313.16 2,450.9391.00 554,446.926,016,233.703,921.84 2.75 2,215.33 6,600.00 89.45 3,987.52 1,311.74 2,532.3891.00 554,528.376,016,232.853,922.62 0.00 2,296.00 6,700.00 89.45 3,988.48 1,309.99 2,632.3691.00 554,628.356,016,231.803,923.58 0.00 2,395.02 6,800.00 89.45 3,989.44 1,308.25 2,732.3491.00 554,728.336,016,230.753,924.54 0.00 2,494.04 6,900.00 89.45 3,990.40 1,306.50 2,832.3291.00 554,828.316,016,229.713,925.50 0.00 2,593.07 7,000.00 89.45 3,991.36 1,304.76 2,932.3091.00 554,928.296,016,228.663,926.46 0.00 2,692.09 7,100.00 89.45 3,992.32 1,303.01 3,032.2891.00 555,028.276,016,227.613,927.42 0.00 2,791.11 7,200.00 89.45 3,993.28 1,301.26 3,132.2691.00 555,128.256,016,226.563,928.38 0.00 2,890.13 7,300.00 89.45 3,994.24 1,299.52 3,232.2491.00 555,228.236,016,225.523,929.34 0.00 2,989.16 7,368.53 89.45 3,994.90 1,298.32 3,300.7691.00 555,296.756,016,224.803,930.00 0.00 3,057.02 7,400.00 89.42 3,995.21 1,297.52 3,332.2191.94 555,328.216,016,224.213,930.31 3.00 3,088.21 7,500.00 89.32 3,996.32 1,291.51 3,432.0294.94 555,428.046,016,218.903,931.42 3.00 3,187.73 7,600.00 89.22 3,997.60 1,280.30 3,531.3797.94 555,527.456,016,208.383,932.70 3.00 3,287.61 7,700.00 89.12 3,999.05 1,263.90 3,629.99100.94 555,626.186,016,192.683,934.15 3.00 3,387.58 7,800.00 89.02 4,000.67 1,242.36 3,727.62103.94 555,723.956,016,171.833,935.77 3.00 3,487.38 7,900.00 88.93 4,002.45 1,215.75 3,823.98106.94 555,820.496,016,145.893,937.55 3.00 3,586.72 8,000.00 88.84 4,004.39 1,184.14 3,918.82109.94 555,915.536,016,114.943,939.49 3.00 3,685.34 8,100.00 88.76 4,006.49 1,147.60 4,011.87112.94 556,008.836,016,079.063,941.59 3.00 3,782.96 8,200.00 88.67 4,008.73 1,106.25 4,102.88115.94 556,100.126,016,038.353,943.83 3.00 3,879.31 8,267.92 88.62 4,010.34 1,075.47 4,163.40117.97 556,160.846,016,008.003,945.44 3.00 3,943.90 8,300.00 88.62 4,011.11 1,060.43 4,191.73117.97 556,189.276,015,993.153,946.21 0.00 3,974.23 8,374.29 88.62 4,012.90 1,025.59 4,257.32117.97 556,255.106,015,958.783,948.00 0.00 4,044.47 8,400.00 88.93 4,013.45 1,013.40 4,279.95118.68 556,277.816,015,946.743,948.55 3.00 4,068.72 8,429.02 89.28 4,013.90 999.30 4,305.30119.48 556,303.266,015,932.823,949.00 3.00 4,095.97 8,500.00 89.28 4,014.79 964.37 4,367.09119.48 556,365.286,015,898.333,949.89 0.00 4,162.47 8,576.82 89.28 4,015.75 926.58 4,433.96119.48 556,432.416,015,861.013,950.85 0.00 4,234.43 8,600.00 89.28 4,016.05 915.30 4,454.21118.78 556,452.746,015,849.873,951.15 3.00 4,256.19 8,700.00 89.26 4,017.33 869.47 4,543.07115.78 556,541.906,015,804.673,952.43 3.00 4,351.13 8,800.00 89.24 4,018.64 828.36 4,634.21112.78 556,633.326,015,764.203,953.74 3.00 4,447.57 8,900.00 89.22 4,019.99 792.08 4,727.37109.78 556,726.726,015,728.573,955.09 3.00 4,545.26 9,000.00 89.20 4,021.37 760.72 4,822.31106.78 556,821.866,015,697.883,956.47 3.00 4,643.93 9,099.29 89.19 4,022.76 734.54 4,918.06103.80 556,917.796,015,672.373,957.86 3.00 4,742.61 9,200.00 89.19 4,024.19 710.52 5,015.86103.80 557,015.746,015,649.043,959.29 0.00 4,842.95 9,300.00 89.19 4,025.60 686.67 5,112.96103.80 557,113.006,015,625.873,960.70 0.00 4,942.59 9,389.29 89.19 4,026.86 665.37 5,199.66103.80 557,199.846,015,605.183,961.96 0.00 5,031.56 9,400.00 89.19 4,027.01 662.85 5,210.07103.48 557,210.266,015,602.733,962.11 3.00 5,042.23 9,500.00 89.18 4,028.43 642.10 5,307.87100.48 557,308.206,015,582.663,963.53 3.00 5,142.08 9,602.60 89.18 4,029.90 626.16 5,409.2197.40 557,409.636,015,567.433,965.00 3.00 5,244.66 9,700.00 86.75 4,033.36 613.62 5,505.7297.40 557,506.226,015,555.573,968.46 2.50 5,341.95 4/9/2025 3:40:23PM COMPASS 5000.17 Build 04 Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Standard Proposal Report Well: Wellbore: Plan: MPU J-49 MPU J-49 Survey Calculation Method:Minimum Curvature J-49 as staked @ 64.90usft (Original Well Elev) Design:MPU J-49 wp03 Database:Alaska MD Reference:J-49 as staked @ 64.90usft (Original Well Elev) North Reference: Well Plan: MPU J-49 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,977.02 Vert Section 9,806.91 84.07 4,041.92 599.89 5,611.3997.40 557,611.976,015,542.583,977.02 2.50 5,448.46 9,868.38 84.07 4,048.27 592.01 5,672.0397.40 557,672.666,015,535.123,983.37 0.00 5,509.58 9,900.00 84.86 4,051.32 587.96 5,703.2397.41 557,703.896,015,531.283,986.42 2.50 5,541.04 10,000.00 87.36 4,058.09 575.08 5,802.1697.42 557,802.896,015,519.103,993.19 2.50 5,640.76 10,039.89 88.36 4,059.58 569.92 5,841.6997.43 557,842.456,015,514.223,994.68 2.50 5,680.61 10,100.00 88.36 4,061.30 562.15 5,901.2797.43 557,902.086,015,506.873,996.40 0.00 5,740.67 10,200.00 88.36 4,064.17 549.23 6,000.3997.43 558,001.286,015,494.633,999.27 0.00 5,840.60 10,300.00 88.36 4,067.03 536.30 6,099.5197.43 558,100.486,015,482.404,002.13 0.00 5,940.52 10,400.00 88.36 4,069.89 523.38 6,198.6397.43 558,199.676,015,470.174,004.99 0.00 6,040.44 10,500.00 88.36 4,072.75 510.45 6,297.7597.43 558,298.876,015,457.944,007.85 0.00 6,140.36 10,600.00 88.36 4,075.61 497.52 6,396.8797.43 558,398.076,015,445.704,010.71 0.00 6,240.28 10,679.89 88.36 4,077.90 487.20 6,476.0697.43 558,477.326,015,435.934,013.00 0.00 6,320.11 10,700.00 88.86 4,078.39 484.60 6,495.9997.42 558,497.276,015,433.474,013.49 2.50 6,340.21 10,716.09 89.27 4,078.65 482.52 6,511.9597.42 558,513.246,015,431.504,013.75 2.50 6,356.29 10,800.00 89.27 4,079.73 471.69 6,595.1497.42 558,596.506,015,421.254,014.83 0.00 6,440.16 10,900.00 89.27 4,081.01 458.78 6,694.3097.42 558,695.746,015,409.044,016.11 0.00 6,540.11 11,000.00 89.27 4,082.29 445.87 6,793.4597.42 558,794.976,015,396.824,017.39 0.00 6,640.07 11,100.00 89.27 4,083.57 432.95 6,892.6197.42 558,894.206,015,384.604,018.67 0.00 6,740.02 11,200.00 89.27 4,084.86 420.04 6,991.7697.42 558,993.436,015,372.384,019.96 0.00 6,839.97 11,300.00 89.27 4,086.14 407.13 7,090.9297.42 559,092.676,015,360.174,021.24 0.00 6,939.93 11,359.23 89.27 4,086.90 399.49 7,149.6497.42 559,151.446,015,352.934,022.00 0.00 6,999.13 11,400.00 88.26 4,087.78 394.27 7,190.0797.28 559,191.906,015,348.004,022.88 2.50 7,039.87 11,500.00 85.78 4,092.99 381.91 7,289.1696.94 559,291.066,015,336.334,028.09 2.50 7,139.67 11,568.51 84.08 4,099.04 373.80 7,356.9296.71 559,358.876,015,328.694,034.14 2.50 7,207.87 11,600.00 84.08 4,102.29 370.14 7,388.0296.71 559,389.996,015,325.254,037.39 0.00 7,239.16 11,708.25 84.08 4,113.45 357.55 7,494.9696.71 559,497.006,015,313.414,048.55 0.00 7,346.75 11,800.00 85.61 4,121.69 348.24 7,585.8595.00 559,587.956,015,304.734,056.79 2.50 7,437.98 11,850.74 86.46 4,125.20 344.25 7,636.3194.05 559,638.436,015,301.094,060.30 2.50 7,488.44 11,900.00 86.46 4,128.24 340.77 7,685.3694.05 559,687.506,015,297.964,063.34 0.00 7,537.43 12,000.00 86.46 4,134.42 333.73 7,784.9294.05 559,787.106,015,291.614,069.52 0.00 7,636.87 12,100.00 86.46 4,140.59 326.68 7,884.4894.05 559,886.696,015,285.264,075.69 0.00 7,736.30 12,200.00 86.46 4,146.77 319.63 7,984.0494.05 559,986.296,015,278.904,081.87 0.00 7,835.74 12,250.74 86.46 4,149.90 316.05 8,034.5594.05 560,036.826,015,275.684,085.00 0.00 7,886.19 12,300.00 87.68 4,152.42 312.63 8,083.6393.91 560,085.926,015,272.614,087.52 2.50 7,935.20 12,334.30 88.54 4,153.55 310.32 8,117.8493.82 560,120.146,015,270.534,088.65 2.50 7,969.35 12,400.00 88.54 4,155.23 305.95 8,183.3793.82 560,185.696,015,266.624,090.33 0.00 8,034.75 12,500.00 88.54 4,157.78 299.29 8,283.1193.82 560,285.476,015,260.654,092.88 0.00 8,134.31 12,600.00 88.54 4,160.33 292.63 8,382.8693.82 560,385.256,015,254.694,095.43 0.00 8,233.87 12,700.00 88.54 4,162.89 285.97 8,482.6093.82 560,485.036,015,248.734,097.99 0.00 8,333.43 12,800.00 88.54 4,165.44 279.31 8,582.3593.82 560,584.816,015,242.764,100.54 0.00 8,432.99 12,900.00 88.54 4,168.00 272.65 8,682.0993.82 560,684.596,015,236.804,103.10 0.00 8,532.55 13,000.00 88.54 4,170.55 265.99 8,781.8493.82 560,784.376,015,230.844,105.65 0.00 8,632.11 13,100.00 88.54 4,173.10 259.33 8,881.5893.82 560,884.156,015,224.874,108.20 0.00 8,731.67 13,170.33 88.54 4,174.90 254.64 8,951.7393.82 560,954.326,015,220.684,110.00 0.00 8,801.69 13,200.00 88.38 4,175.70 252.85 8,981.3493.09 560,983.946,015,219.104,110.80 2.50 8,831.21 4/9/2025 3:40:23PM COMPASS 5000.17 Build 04 Page 7 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Standard Proposal Report Well: Wellbore: Plan: MPU J-49 MPU J-49 Survey Calculation Method:Minimum Curvature J-49 as staked @ 64.90usft (Original Well Elev) Design:MPU J-49 wp03 Database:Alaska MD Reference:J-49 as staked @ 64.90usft (Original Well Elev) North Reference: Well Plan: MPU J-49 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 4,111.67 Vert Section 13,229.61 88.23 4,176.57 251.44 9,010.9092.37 561,013.506,015,217.894,111.67 2.50 8,860.63 13,300.00 88.23 4,178.74 248.54 9,081.2092.37 561,083.816,015,215.484,113.84 0.00 8,930.51 13,400.00 88.23 4,181.83 244.40 9,181.0792.37 561,183.706,015,212.044,116.93 0.00 9,029.80 13,500.00 88.23 4,184.91 240.27 9,280.9392.37 561,283.586,015,208.614,120.01 0.00 9,129.08 13,600.00 88.23 4,187.99 236.14 9,380.8092.37 561,383.466,015,205.184,123.09 0.00 9,228.37 13,681.11 88.23 4,190.50 232.79 9,461.8092.37 561,464.486,015,202.394,125.60 0.00 9,308.90 13,700.00 88.23 4,191.08 231.93 9,480.6692.84 561,483.356,015,201.664,126.18 2.50 9,327.66 13,800.00 88.23 4,194.16 224.80 9,580.3595.34 561,583.076,015,195.234,129.26 2.50 9,427.24 13,900.00 88.23 4,197.25 213.33 9,679.6497.84 561,682.426,015,184.454,132.35 2.50 9,527.09 13,986.21 88.24 4,199.90 199.96 9,764.76100.00 561,767.636,015,171.684,135.00 2.50 9,613.26 14,000.00 88.26 4,200.32 197.53 9,778.33100.34 561,781.216,015,169.344,135.42 2.50 9,627.04 14,058.26 88.35 4,202.04 186.35 9,835.47101.80 561,838.436,015,158.564,137.14 2.50 9,685.23 14,100.00 88.35 4,203.24 177.82 9,876.32101.80 561,879.336,015,150.314,138.34 0.00 9,726.91 14,200.00 88.35 4,206.12 157.38 9,974.16101.80 561,977.306,015,130.564,141.22 0.00 9,826.74 14,300.00 88.35 4,208.99 136.94 10,072.01101.80 562,075.286,015,110.814,144.09 0.00 9,926.58 14,400.00 88.35 4,211.86 116.50 10,169.86101.80 562,173.266,015,091.054,146.96 0.00 10,026.42 14,500.00 88.35 4,214.74 96.06 10,267.70101.80 562,271.246,015,071.304,149.84 0.00 10,126.26 14,575.28 88.35 4,216.90 80.67 10,341.37101.80 562,345.006,015,056.434,152.00 0.00 10,201.43 14,585.38 88.29 4,217.20 78.59 10,351.24102.04 562,354.896,015,054.414,152.30 2.50 10,211.51 14,600.00 88.29 4,217.63 75.54 10,365.53102.04 562,369.206,015,051.474,152.73 0.00 10,226.10 14,700.00 88.29 4,220.61 54.68 10,463.29102.04 562,467.096,015,031.294,155.71 0.00 10,325.91 14,800.00 88.29 4,223.59 33.83 10,561.04102.04 562,564.986,015,011.124,158.69 0.00 10,425.73 14,900.00 88.29 4,226.56 12.97 10,658.80102.04 562,662.876,014,990.954,161.66 0.00 10,525.54 14,911.25 88.29 4,226.90 10.62 10,669.80102.04 562,673.886,014,988.684,162.00 0.00 10,536.77 14,994.69 88.24 4,229.42 -8.26 10,751.02104.13 562,755.236,014,970.374,164.52 2.50 10,619.95 15,000.00 88.24 4,229.58 -9.55 10,756.17104.13 562,760.396,014,969.114,164.68 0.00 10,625.24 15,100.00 88.24 4,232.65 -33.96 10,853.10104.13 562,857.476,014,945.384,167.75 0.00 10,724.80 15,200.00 88.24 4,235.71 -58.36 10,950.03104.13 562,954.566,014,921.664,170.81 0.00 10,824.35 15,300.00 88.24 4,238.77 -82.76 11,046.96104.13 563,051.656,014,897.944,173.87 0.00 10,923.90 15,400.00 88.24 4,241.84 -107.16 11,143.89104.13 563,148.746,014,874.224,176.94 0.00 11,023.45 15,500.00 88.24 4,244.90 -131.56 11,240.82104.13 563,245.826,014,850.504,180.00 0.00 11,123.01 15,600.00 88.24 4,247.96 -155.96 11,337.75104.13 563,342.916,014,826.784,183.06 0.00 11,222.56 15,700.00 88.24 4,251.03 -180.36 11,434.68104.13 563,440.006,014,803.064,186.13 0.00 11,322.11 15,800.00 88.24 4,254.09 -204.76 11,531.61104.13 563,537.096,014,779.334,189.19 0.00 11,421.66 15,900.00 88.24 4,257.15 -229.16 11,628.53104.13 563,634.176,014,755.614,192.25 0.00 11,521.22 16,000.00 88.24 4,260.22 -253.56 11,725.46104.13 563,731.266,014,731.894,195.32 0.00 11,620.77 16,100.00 88.24 4,263.28 -277.96 11,822.39104.13 563,828.356,014,708.174,198.38 0.00 11,720.32 16,200.00 88.24 4,266.34 -302.37 11,919.32104.13 563,925.446,014,684.454,201.44 0.00 11,819.87 16,300.00 88.24 4,269.41 -326.77 12,016.25104.13 564,022.526,014,660.734,204.51 0.00 11,919.43 16,381.35 88.24 4,271.90 -346.62 12,095.10104.13 564,101.506,014,641.434,207.00 0.00 12,000.41 Total Depth : 16381.35' MD, 4271.9' TVD 4/9/2025 3:40:23PM COMPASS 5000.17 Build 04 Page 8 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Standard Proposal Report Well: Wellbore: Plan: MPU J-49 MPU J-49 Survey Calculation Method:Minimum Curvature J-49 as staked @ 64.90usft (Original Well Elev) Design:MPU J-49 wp03 Database:Alaska MD Reference:J-49 as staked @ 64.90usft (Original Well Elev) North Reference: Well Plan: MPU J-49 True Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Targets Dip Angle (°) Dip Dir. (°) MPU J-49 wp02 tgt01.5 3,989.11 6,016,188.90 553,631.121,274.05 1,634.760.00 0.00 - plan hits target center - Point MPU J-49 wp01 tgt12 4,199.90 6,015,171.68 561,767.63199.96 9,764.760.00 0.00 - plan hits target center - Point MPU J-49 wp01 tgt01 3,971.90 6,016,253.68 553,096.191,342.57 1,100.240.00 0.00 - plan misses target center by 45.18usft at 5164.84usft MD (3974.15 TVD, 1297.45 N, 1100.83 E) - Point MPU J-49 wp01 tgt10 4,149.90 6,015,275.68 560,036.82316.05 8,034.550.00 0.00 - plan hits target center - Point MPU J-49 wp01 tgt11 4,174.90 6,015,220.68 560,954.32254.64 8,951.730.00 0.00 - plan hits target center - Point MPU J-49 wp03 tgt04 4,012.90 6,015,949.58 556,246.191,016.46 4,248.350.00 0.00 - plan misses target center by 12.28usft at 8370.65usft MD (4012.81 TVD, 1027.30 N, 4254.11 E) - Point MPU J-49 wp01 tgt14 4,226.90 6,014,988.68 562,673.8810.62 10,669.800.00 0.00 - plan hits target center - Point MPU J-49 wp01 tgt07 4,077.90 6,015,435.93 558,477.32487.20 6,476.060.00 0.00 - plan hits target center - Point MPU J-49 wp01 tgt05 4,029.90 6,015,567.43 557,409.63626.16 5,409.210.00 0.00 - plan hits target center - Point MPU J-49 wp01 tgt06 4,056.90 6,015,525.43 557,751.63581.77 5,750.940.00 0.00 - plan misses target center by 1.77usft at 9948.37usft MD (4055.14 TVD, 581.73 N, 5751.05 E) - Point MPU J-49 wp03 tgt03 3,994.90 6,016,224.80 555,296.751,298.32 3,300.760.00 0.00 - plan hits target center - Point MPU J-49 wp01 tgt13 4,216.90 6,015,056.43 562,345.0080.67 10,341.370.00 0.00 - plan hits target center - Point MPU J-49 wp01 tgt15 4,271.90 6,014,641.43 564,101.50-346.62 12,095.100.00 0.00 - plan hits target center - Point MPU J-49 wp01 tgt08 4,086.90 6,015,352.93 559,151.44399.49 7,149.640.00 0.00 - plan hits target center - Point MPU J-49 wp03 tgt02 3,986.90 6,016,247.43 554,242.191,328.32 2,246.280.00 0.00 - plan misses target center by 21.55usft at 6315.06usft MD (3985.88 TVD, 1306.84 N, 2247.63 E) - Point MPU J-49 wp02 tgt04.5 4,020.81 6,015,701.64 556,785.02764.74 4,785.490.00 0.00 - plan misses target center by 7.13usft at 8963.77usft MD (4020.87 TVD, 771.51 N, 4787.72 E) - Point MPU J-49 wp01 tgt09 4,116.90 6,015,309.68 559,504.07353.77 7,502.000.00 0.00 - plan misses target center by 3.98usft at 11715.92usft MD (4114.23 TVD, 356.67 N, 7502.54 E) 4/9/2025 3:40:23PM COMPASS 5000.17 Build 04 Page 9 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt J Pad Standard Proposal Report Well: Wellbore: Plan: MPU J-49 MPU J-49 Survey Calculation Method:Minimum Curvature J-49 as staked @ 64.90usft (Original Well Elev) Design:MPU J-49 wp03 Database:Alaska MD Reference:J-49 as staked @ 64.90usft (Original Well Elev) North Reference: Well Plan: MPU J-49 True - Point Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 4-1/2" Production Casing4,271.9016,381.35 4-1/2 8-1/2 9-5/8" Surface Casing3,974.165,165.00 9-5/8 12-1/4 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations Vertical Depth SS 2,043.70 1,937.90 Base Permafrost 3,660.25 3,358.90 UG_LA3 5,185.59 3,975.90 SB_NB 4,864.88 3,944.90 SB_NA 2,258.49 2,130.90 SV1 4,002.86 3,598.90 UG_MB 901.80 891.90 SV6 Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 300.00 300.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 1,050.00 1,030.94 40.31 -139.46 Start Dir 4º/100' : 1050' MD, 1030.94'TVD 1,614.54 1,552.27 195.85 -275.92 End Dir : 1614.54' MD, 1552.27' TVD 2,672.62 2,503.02 643.88 -397.84 Start Dir 4º/100' : 2672.62' MD, 2503.03'TVD 4,964.31 3,956.67 1,293.96 901.09 End Dir : 4964.31' MD, 3956.67' TVD 5,165.10 3,974.17 1,297.45 1,101.09 Begin Geosteering 16,381.35 4,271.90 -346.62 12,095.10 Total Depth : 16381.35' MD, 4271.9' TVD 4/9/2025 3:40:23PM COMPASS 5000.17 Build 04 Page 10 Clearance SummaryAnticollision Report09 April, 2025Hilcorp Alaska, LLCMilne PointM Pt J PadPlan: MPU J-49MPU J-49MPU J-49 wp03Reference Design: M Pt J Pad - Plan: MPU J-49 - MPU J-49 - MPU J-49 wp03Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,014,903.60 N, 552,005.45 E (70° 27' 05.25" N, 149° 34' 32.45" W)Datum Height: J-49 as staked @ 64.90usft (Original Well Elev)Scan Range: 33.70 to 5,165.00 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.17 Build: 04Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-49 - MPU J-49 wp03Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 33.70 to 5,165.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt J Pad - Plan: MPU J-49 - MPU J-49 - MPU J-49 wp03MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt E PadMPE-28 - MPE-28 - MPE-28 7,334.99 5,165.00 7,217.06 11,725.00 62.1975,165.00Clearance Factor Pass - Plan: MPU E-48 - MPU E-48 - MPU E-48 wp07 1,001.57 5,165.00 800.71 18,865.68 4.9865,165.00Clearance Factor Pass - M Pt G PadMPG-03 - MPG-03 - MPG-03 5,285.79 310.43 5,277.42 333.44 631.424310.43Centre Distance Pass - MPG-03 - MPG-03 - MPG-03 5,285.93 333.70 5,277.35 356.14 615.686333.70Ellipse Separation Pass - MPG-03 - MPG-03 - MPG-03 5,338.23 5,165.00 5,299.31 1,850.00 137.1465,165.00Clearance Factor Pass - MPG-03 - MPG-03A - MPG-03A 5,285.79 310.43 5,277.42 337.27 631.424310.43Centre Distance Pass - MPG-03 - MPG-03A - MPG-03A 5,285.93 333.70 5,277.35 359.97 615.686333.70Ellipse Separation Pass - MPG-03 - MPG-03A - MPG-03A 5,338.23 5,165.00 5,299.31 1,853.83 137.1465,165.00Clearance Factor Pass - MPG-04 - MPG-04 - MPG-04 4,242.84 5,165.00 4,150.91 4,478.71 46.1545,165.00Clearance Factor Pass - MPG-06 - MPG-06 - MPG-06 5,177.50 308.70 5,170.81 321.51 773.557308.70Ellipse Separation Pass - MPG-06 - MPG-06 - MPG-06 5,304.87 5,165.00 5,278.74 1,563.56 202.9885,165.00Clearance Factor Pass - MPG-07 - MPG-07 - MPG-07 4,899.61 5,165.00 4,862.86 2,633.72 133.2965,165.00Clearance Factor Pass - MPG-08 - MPG-08 - MPG-08 3,282.38 5,165.00 3,213.84 4,830.72 47.8935,165.00Clearance Factor Pass - MPG-08 - MPG-08A - MPG-08A 3,078.11 5,165.00 3,014.62 5,040.23 48.4835,165.00Clearance Factor Pass - MPG-11 - MPG-11 - MPG-11 5,295.78 111.20 5,289.68 104.60 867.403111.20Centre Distance Pass - MPG-11 - MPG-11 - MPG-11 5,295.92 208.70 5,289.50 185.76 824.493208.70Ellipse Separation Pass - MPG-11 - MPG-11 - MPG-11 5,473.57 5,165.00 5,443.94 1,572.35 184.7315,165.00Clearance Factor Pass - MPG-12 - MPG-12 - MPG-12 3,883.75 5,165.00 3,839.00 4,589.21 86.7845,165.00Clearance Factor Pass - MPG-14 - MPG-14 - MPG-14 874.24 5,165.00 800.55 6,150.00 11.8635,165.00Clearance Factor Pass - MPG-14 - MPG-14L1 - MPG-14L1 874.24 5,165.00 800.55 6,150.00 11.8635,165.00Clearance Factor Pass - MPG-16 - MPG-16 - MPG-16 5,167.01 5,158.70 5,134.48 2,526.99 158.8705,158.70Clearance Factor Pass - MPG-16 - MPG-16 - MPG-16 5,161.70 5,165.00 5,129.23 2,527.78 158.9765,165.00Ellipse Separation Pass - MPG-16 - MPG-16L1 - MPG-16L1 5,167.01 5,158.70 5,134.48 2,526.99 158.8705,158.70Clearance Factor Pass - MPG-16 - MPG-16L1 - MPG-16L1 5,161.70 5,165.00 5,129.36 2,527.78 159.6175,165.00Ellipse Separation Pass - MPG-16 - MPG-16PB1 - MPG-16PB1 5,167.01 5,158.70 5,134.48 2,526.99 158.8705,158.70Clearance Factor Pass - MPG-16 - MPG-16PB1 - MPG-16PB1 5,161.70 5,165.00 5,129.23 2,527.78 158.9765,165.00Ellipse Separation Pass - 09 April, 2025 - 15:43COMPASSPage 2 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-49 - MPU J-49 wp03Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 33.70 to 5,165.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt J Pad - Plan: MPU J-49 - MPU J-49 - MPU J-49 wp03MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPG-16 - MPG-16PB2 - MPG-16PB2 5,167.01 5,158.70 5,134.48 2,526.99 158.8705,158.70Clearance Factor Pass - MPG-16 - MPG-16PB2 - MPG-16PB2 5,161.70 5,165.00 5,129.23 2,527.78 158.9765,165.00Ellipse Separation Pass - MPG-18 - MPG-18 - MPG-18 2,473.86 5,165.00 2,429.78 8,421.00 56.1245,165.00Clearance Factor Pass - MPG-18 - MPG-18L1 - MPG-18L1 2,318.18 5,165.00 2,273.55 8,563.00 51.9345,165.00Clearance Factor Pass - MPG-18 - MPG-18PB1 - MPG-18PB1 5,145.25 33.70 5,139.27 34.00 859.91133.70Centre Distance Pass - MPG-18 - MPG-18PB1 - MPG-18PB1 5,145.44 133.70 5,139.10 112.74 811.706133.70Ellipse Separation Pass - MPG-18 - MPG-18PB1 - MPG-18PB1 5,311.48 5,165.00 5,265.44 5,578.00 115.3695,165.00Clearance Factor Pass - MPG-19 - MPG-19 - MPG-19 5,338.59 285.20 5,331.46 285.65 748.658285.20Centre Distance Pass - MPG-19 - MPG-19 - MPG-19 5,338.63 308.70 5,331.41 299.77 739.482308.70Ellipse Separation Pass - MPG-19 - MPG-19 - MPG-19 5,432.60 5,165.00 5,401.59 1,995.35 175.2075,165.00Clearance Factor Pass - M Pt I PadMPU I-20 - MPU I-20 - MPU I-20 433.04 4,225.56 377.11 10,215.14 7.7424,225.56Centre Distance Pass - MPU I-20 - MPU I-20 - MPU I-20 437.68 4,283.70 373.02 10,231.57 6.7694,283.70Ellipse Separation Pass - MPU I-20 - MPU I-20 - MPU I-20 502.66 4,458.70 416.50 10,280.76 5.8344,458.70Clearance Factor Pass - MPU I-27 - MPU I-27 - MPU I-27 419.63 4,162.05 361.30 10,352.10 7.1944,162.05Centre Distance Pass - MPU I-27 - MPU I-27 - MPU I-27 422.64 4,208.70 357.23 10,367.49 6.4614,208.70Ellipse Separation Pass - MPU I-27 - MPU I-27 - MPU I-27 483.04 4,383.70 395.53 10,426.71 5.5204,383.70Clearance Factor Pass - MPU I-35i - MPU I-35i - MPU I-35i 380.98 4,019.40 318.51 9,965.44 6.0984,019.40Centre Distance Pass - MPU I-35i - MPU I-35i - MPU I-35i 387.20 4,083.70 314.37 9,984.07 5.3164,083.70Ellipse Separation Pass - MPU I-35i - MPU I-35i - MPU I-35i 420.04 4,183.70 334.31 10,013.70 4.9004,183.70Clearance Factor Pass - M Pt J PadMPJ-01 - MPJ-01 - MPJ-01 127.38 953.94 120.42 946.90 18.310953.94Centre Distance Pass - MPJ-01 - MPJ-01 - MPJ-01 127.38 958.70 120.39 951.39 18.220958.70Ellipse Separation Pass - MPJ-01 - MPJ-01 - MPJ-01 234.71 3,883.70 211.66 3,750.65 10.1853,883.70Clearance Factor Pass - MPJ-01 - MPJ-01A - MPJ-01A 127.38 953.94 120.42 942.35 18.310953.94Centre Distance Pass - MPJ-01 - MPJ-01A - MPJ-01A 127.38 958.70 120.39 946.84 18.220958.70Ellipse Separation Pass - MPJ-01 - MPJ-01A - MPJ-01A 257.10 4,033.70 230.68 3,922.29 9.7304,033.70Clearance Factor Pass - MPJ-01 - MPJ-01AL1 - MPJ-01AL1 127.38 953.94 120.42 942.35 18.310953.94Centre Distance Pass - MPJ-01 - MPJ-01AL1 - MPJ-01AL1 127.38 958.70 120.39 946.84 18.220958.70Ellipse Separation Pass - 09 April, 2025 - 15:43COMPASSPage 3 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-49 - MPU J-49 wp03Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 33.70 to 5,165.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt J Pad - Plan: MPU J-49 - MPU J-49 - MPU J-49 wp03MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-01 - MPJ-01AL1 - MPJ-01AL1 257.10 4,033.70 230.77 3,922.29 9.7634,033.70Clearance Factor Pass - MPJ-02 - MPJ-02 - MPJ-02 90.66 675.64 85.70 674.99 18.306675.64Centre Distance Pass - MPJ-02 - MPJ-02 - MPJ-02 90.69 683.70 85.68 682.58 18.114683.70Ellipse Separation Pass - MPJ-02 - MPJ-02 - MPJ-02 94.77 758.70 89.25 751.96 17.155758.70Clearance Factor Pass - MPJ-03 - MPJ-03 - MPJ-03 23.58 657.65 18.74 662.86 4.874657.65Centre Distance Pass - MPJ-03 - MPJ-03 - MPJ-03 23.58 658.70 18.74 663.89 4.868658.70Clearance Factor Pass - MPJ-04 - MPJ-04 - MPJ-04 14.92 283.70 12.37 289.00 5.852283.70Centre Distance Pass - MPJ-04 - MPJ-04 - MPJ-04 14.94 308.70 12.25 314.00 5.547308.70Ellipse Separation Pass - MPJ-04 - MPJ-04 - MPJ-04 16.26 383.70 13.13 388.94 5.195383.70Clearance Factor Pass - MPJ-05 - MPJ-05 - MPJ-05 259.61 33.70 258.03 38.98 164.54033.70Centre Distance Pass - MPJ-05 - MPJ-05 - MPJ-05 260.30 308.70 256.85 312.69 75.499308.70Ellipse Separation Pass - MPJ-05 - MPJ-05 - MPJ-05 563.40 5,165.00 492.72 4,699.10 7.9715,165.00Clearance Factor Pass - MPJ-06 - MPJ-06 - MPJ-06 144.20 108.70 142.44 109.80 81.867108.70Centre Distance Pass - MPJ-06 - MPJ-06 - MPJ-06 144.48 308.70 141.50 309.28 48.539308.70Ellipse Separation Pass - MPJ-06 - MPJ-06 - MPJ-06 422.44 3,858.70 374.65 3,966.08 8.8413,858.70Clearance Factor Pass - MPJ-08 - MPJ-08 - MPJ-08 63.18 679.41 57.54 676.85 11.193679.41Centre Distance Pass - MPJ-08 - MPJ-08 - MPJ-08 63.19 683.70 57.51 681.06 11.130683.70Ellipse Separation Pass - MPJ-08 - MPJ-08 - MPJ-08 346.11 3,483.70 303.13 3,532.69 8.0533,483.70Clearance Factor Pass - MPJ-08 - MPJ-08A - MPJ-08A 63.18 679.41 57.54 677.65 11.193679.41Centre Distance Pass - MPJ-08 - MPJ-08A - MPJ-08A 63.19 683.70 57.51 681.86 11.130683.70Ellipse Separation Pass - MPJ-08 - MPJ-08A - MPJ-08A 346.11 3,483.70 303.13 3,533.49 8.0533,483.70Clearance Factor Pass - MPJ-09 - MPJ-09 - MPJ-09 201.15 108.70 199.39 108.85 114.218108.70Centre Distance Pass - MPJ-09 - MPJ-09 - MPJ-09 219.75 2,408.70 181.40 2,569.60 5.7302,408.70Ellipse Separation Pass - MPJ-09 - MPJ-09 - MPJ-09 234.56 2,508.70 190.45 2,650.47 5.3172,508.70Clearance Factor Pass - MPJ-09 - MPJ-09A - MPJ-09A 201.15 108.70 199.39 109.12 114.218108.70Centre Distance Pass - MPJ-09 - MPJ-09A - MPJ-09A 219.75 2,408.70 181.40 2,569.87 5.7302,408.70Ellipse Separation Pass - MPJ-09 - MPJ-09A - MPJ-09A 234.56 2,508.70 190.45 2,650.74 5.3182,508.70Clearance Factor Pass - MPJ-10 - MPJ-10 - MPJ-10 13.34 487.45 9.11 487.18 3.151487.45Ellipse Separation Pass - MPJ-10 - MPJ-10 - MPJ-10 157.16 5,165.00 102.88 4,461.47 2.8955,165.00Clearance Factor Pass - MPJ-11 - MPJ-11 - MPJ-11 109.03 794.45 103.92 783.32 21.316794.45Ellipse Separation Pass - 09 April, 2025 - 15:43COMPASSPage 4 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-49 - MPU J-49 wp03Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 33.70 to 5,165.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt J Pad - Plan: MPU J-49 - MPU J-49 - MPU J-49 wp03MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-11 - MPJ-11 - MPJ-11 115.10 908.70 109.29 888.14 19.816908.70Clearance Factor Pass - MPJ-12 - MPJ-12 - MPJ-12 116.53 4,469.00 80.70 4,157.02 3.2524,469.00Centre Distance Pass - MPJ-12 - MPJ-12 - MPJ-12 117.21 4,483.70 79.86 4,164.43 3.1384,483.70Ellipse Separation Pass - MPJ-12 - MPJ-12 - MPJ-12 140.31 4,558.70 89.19 4,199.86 2.7454,558.70Clearance Factor Pass - MPJ-13 - MPJ-13 - MPJ-13 229.89 312.45 226.87 313.71 76.112312.45Centre Distance Pass - MPJ-13 - MPJ-13 - MPJ-13 229.98 333.70 226.81 335.08 72.686333.70Ellipse Separation Pass - MPJ-13 - MPJ-13 - MPJ-13 617.84 5,165.00 565.23 4,395.33 11.7445,165.00Clearance Factor Pass - MPJ-15 - MPJ-15 - MPJ-15 63.63 1,415.87 44.85 1,458.00 3.3881,415.87Centre Distance Pass - MPJ-15 - MPJ-15 - MPJ-15 63.81 1,433.70 44.43 1,474.84 3.2921,433.70Ellipse Separation Pass - MPJ-15 - MPJ-15 - MPJ-15 64.72 1,458.70 44.78 1,498.30 3.2451,458.70Clearance Factor Pass - MPJ-16 - MPJ-16 - MPJ-16 83.62 2,314.53 64.93 2,400.20 4.4732,314.53Centre Distance Pass - MPJ-16 - MPJ-16 - MPJ-16 83.91 2,333.70 64.82 2,418.04 4.3942,333.70Ellipse Separation Pass - MPJ-16 - MPJ-16 - MPJ-16 85.29 2,358.70 65.82 2,440.79 4.3812,358.70Clearance Factor Pass - MPJ-17 - MPJ-17 - MPJ-17 215.38 410.00 211.80 411.98 60.114410.00Centre Distance Pass - MPJ-17 - MPJ-17 - MPJ-17 215.59 458.70 211.66 460.00 54.903458.70Ellipse Separation Pass - MPJ-17 - MPJ-17 - MPJ-17 407.81 1,783.70 385.71 1,782.19 18.4501,783.70Clearance Factor Pass - MPJ-18 - MPJ-18 - MPJ-18 186.12 2,146.97 157.28 2,265.38 6.4542,146.97Centre Distance Pass - MPJ-18 - MPJ-18 - MPJ-18 187.90 2,208.70 155.43 2,321.74 5.7862,208.70Ellipse Separation Pass - MPJ-18 - MPJ-18 - MPJ-18 211.64 2,383.70 170.65 2,482.95 5.1632,383.70Clearance Factor Pass - MPJ-23 - MPJ-23 - MPJ-23 124.74 1,383.70 112.40 1,331.16 10.1081,383.70Clearance Factor Pass - MPJ-23 - MPJ-23 - MPJ-23 124.57 1,399.36 112.27 1,344.96 10.1341,399.36Ellipse Separation Pass - MPJ-23 - MPJ-23A - MPJ-23A 124.74 1,383.70 112.30 1,338.66 10.0291,383.70Clearance Factor Pass - MPJ-23 - MPJ-23A - MPJ-23A 124.57 1,399.36 112.18 1,352.46 10.0581,399.36Ellipse Separation Pass - MPJ-23 - MPJ-23L1 - MPJ-23L1 124.74 1,383.70 112.40 1,331.16 10.1081,383.70Clearance Factor Pass - MPJ-23 - MPJ-23L1 - MPJ-23L1 124.57 1,399.36 112.27 1,344.96 10.1341,399.36Ellipse Separation Pass - MPJ-24 - MPJ-24 - MPJ-24 216.20 1,378.07 203.55 1,298.73 17.0971,378.07Centre Distance Pass - MPJ-24 - MPJ-24 - MPJ-24 216.20 1,383.70 203.52 1,303.61 17.0511,383.70Ellipse Separation Pass - MPJ-24 - MPJ-24 - MPJ-24 217.96 1,458.70 205.00 1,367.41 16.8161,458.70Clearance Factor Pass - MPJ-24 - MPJ-24A - MPJ-24A 216.20 1,378.07 203.48 1,295.02 17.0021,378.07Centre Distance Pass - MPJ-24 - MPJ-24A - MPJ-24A 216.20 1,383.70 203.45 1,299.90 16.9561,383.70Ellipse Separation Pass - MPJ-24 - MPJ-24A - MPJ-24A 217.96 1,458.70 204.93 1,363.70 16.7251,458.70Clearance Factor Pass - 09 April, 2025 - 15:43COMPASSPage 5 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-49 - MPU J-49 wp03Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 33.70 to 5,165.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt J Pad - Plan: MPU J-49 - MPU J-49 - MPU J-49 wp03MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-24 - MPJ-24L1 - MPJ-24L1 216.20 1,378.07 203.55 1,298.73 17.0971,378.07Centre Distance Pass - MPJ-24 - MPJ-24L1 - MPJ-24L1 216.20 1,383.70 203.52 1,303.61 17.0501,383.70Ellipse Separation Pass - MPJ-24 - MPJ-24L1 - MPJ-24L1 217.96 1,458.70 205.00 1,367.41 16.8161,458.70Clearance Factor Pass - MPJ-24 - MPJ-24L1PB1 - MPJ-24L1PB1 216.20 1,378.07 203.55 1,298.73 17.0901,378.07Centre Distance Pass - MPJ-24 - MPJ-24L1PB1 - MPJ-24L1PB1 216.20 1,383.70 203.52 1,303.61 17.0431,383.70Ellipse Separation Pass - MPJ-24 - MPJ-24L1PB1 - MPJ-24L1PB1 217.96 1,458.70 204.99 1,367.41 16.8091,458.70Clearance Factor Pass - MPJ-24 - MPJ-24L1PB2 - MPJ-24L1PB2 216.20 1,378.07 203.55 1,298.73 17.0971,378.07Centre Distance Pass - MPJ-24 - MPJ-24L1PB2 - MPJ-24L1PB2 216.20 1,383.70 203.52 1,303.61 17.0511,383.70Ellipse Separation Pass - MPJ-24 - MPJ-24L1PB2 - MPJ-24L1PB2 217.96 1,458.70 205.00 1,367.41 16.8161,458.70Clearance Factor Pass - MPJ-25 - MPJ-25 - MPJ-25 173.59 2,071.10 158.26 1,991.91 11.3292,071.10Centre Distance Pass - MPJ-25 - MPJ-25 - MPJ-25 173.70 2,108.70 158.20 2,030.36 11.2062,108.70Ellipse Separation Pass - MPJ-25 - MPJ-25 - MPJ-25 222.78 3,133.70 199.64 3,048.37 9.6263,133.70Clearance Factor Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1 173.59 2,071.10 158.26 1,991.91 11.3292,071.10Centre Distance Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1 173.70 2,108.70 158.20 2,030.36 11.2062,108.70Ellipse Separation Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1 222.78 3,133.70 199.64 3,048.37 9.6263,133.70Clearance Factor Pass - MPJ-27 - MPJ-27 - MPJ-27 250.16 1,380.46 235.93 1,522.10 17.5831,380.46Centre Distance Pass - MPJ-27 - MPJ-27 - MPJ-27 250.16 1,383.70 235.88 1,524.87 17.5131,383.70Ellipse Separation Pass - MPJ-27 - MPJ-27 - MPJ-27 272.37 1,558.70 254.87 1,675.96 15.5611,558.70Clearance Factor Pass - MPU J-29 - MPU J-29 - MPU J-29 169.23 599.80 164.55 588.30 36.202599.80Centre Distance Pass - MPU J-29 - MPU J-29 - MPU J-29 169.25 608.70 164.52 596.16 35.750608.70Ellipse Separation Pass - MPU J-29 - MPU J-29 - MPU J-29 265.62 1,932.50 252.74 1,849.89 20.6291,932.50Clearance Factor Pass - MPU J-29 - MPU J-29A - MPU J-29A 169.23 599.80 164.55 580.52 36.202599.80Centre Distance Pass - MPU J-29 - MPU J-29A - MPU J-29A 169.25 608.70 164.52 588.38 35.750608.70Ellipse Separation Pass - MPU J-29 - MPU J-29A - MPU J-29A 265.62 1,932.50 252.74 1,842.11 20.6331,932.50Clearance Factor Pass - MPU J-30i - MPU J-30 - MPU J-30 208.50 219.03 206.12 222.18 87.547219.03Centre Distance Pass - MPU J-30i - MPU J-30 - MPU J-30 208.54 233.70 206.09 235.83 84.974233.70Ellipse Separation Pass - MPU J-30i - MPU J-30 - MPU J-30 377.07 2,008.70 364.68 1,861.42 30.4402,008.70Clearance Factor Pass - MPU J-32 - MPU J-32 - MPU J-32 133.25 1,183.59 124.34 1,160.83 14.9651,183.59Clearance Factor Pass - MPU J-41 - MPU J-41 - MPU J-41 68.26 733.10 62.39 727.14 11.632733.10Centre Distance Pass - MPU J-41 - MPU J-41 - MPU J-41 68.26 733.70 62.38 727.69 11.626733.70Ellipse Separation Pass - MPU J-41 - MPU J-41 - MPU J-41 68.67 758.70 62.67 750.66 11.456758.70Clearance Factor Pass - 09 April, 2025 - 15:43COMPASSPage 6 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-49 - MPU J-49 wp03Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 33.70 to 5,165.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt J Pad - Plan: MPU J-49 - MPU J-49 - MPU J-49 wp03MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU J-41 - MPU J-41PB1 - MPU J-41PB1 68.26 733.10 62.39 727.14 11.632733.10Centre Distance Pass - MPU J-41 - MPU J-41PB1 - MPU J-41PB1 68.26 733.70 62.38 727.69 11.626733.70Ellipse Separation Pass - MPU J-41 - MPU J-41PB1 - MPU J-41PB1 68.67 758.70 62.67 750.66 11.456758.70Clearance Factor Pass - MPU J-43 - MPU J-43 - MPU J-43 36.87 1,001.16 29.35 993.69 4.9041,001.16Clearance Factor Pass - MPU J-45 - MPU J-45 - MPU J-45 103.90 714.95 97.91 723.29 17.358714.95Ellipse Separation Pass - MPU J-45 - MPU J-45 - MPU J-45 106.35 758.70 100.01 760.62 16.768758.70Clearance Factor Pass - MPU J-46 - MPU J-46 - MPU J-46 186.49 33.70 184.57 35.02 97.56233.70Centre Distance Pass - MPU J-46 - MPU J-46 - MPU J-46 186.50 58.70 184.54 59.79 94.81958.70Ellipse Separation Pass - MPU J-46 - MPU J-46 - MPU J-46 311.11 1,508.70 298.84 1,563.41 25.3601,508.70Clearance Factor Pass - MPU J-47 - MPU J-47 - MPU J-47 50.54 688.67 44.99 687.72 9.098688.67Ellipse Separation Pass - MPU J-47 - MPU J-47 - MPU J-47 52.95 758.70 46.88 755.92 8.728758.70Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.701,500.00 MPU J-49 wp03 GYD_Quest GWD1,500.005,165.00 MPU J-49 wp03 3_MWD+IFR2+MS+Sag5,165.0016,381.35 MPU J-49 wp03 GYD_Quest GWDEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.09 April, 2025 - 15:43COMPASSPage 7 of 9 0.001.002.003.004.00Separation Factor0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225Measured Depth (550 usft/in)MPJ-15MPJ-12MPJ-10MPJ-16No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU J-49 NAD 1927 (NADCON CONUS)Alaska Zone 0431.20+N/-S +E/-W Northing Easting Latittude Longitude0.000.006014903.60552005.45 70° 27' 5.2470 N149° 34' 32.4491 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-49, True NorthVertical (TVD) Reference:J-49 as staked @ 64.90usft (Original Well Elev)Measured Depth Reference:J-49 as staked @ 64.90usft (Original Well Elev)Calculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2025-03-20T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1500.00 MPU J-49 wp03 (MPU J-49) GYD_Quest GWD1500.00 5165.00 MPU J-49 wp03 (MPU J-49) 3_MWD+IFR2+MS+Sag5165.00 16381.35 MPU J-49 wp03 (MPU J-49) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225Measured Depth (550 usft/in)MPJ-11MPJ-15MPJ-12MPU J-45MPJ-06MPJ-03MPJ-04MPJ-02MPU J-43MPJ-10MPU J-47MPU J-41MPJ-08MPU J-29MPJ-16MPJ-01NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 16381.35Project: Milne PointSite: M Pt J PadWell: Plan: MPU J-49Wellbore: MPU J-49Plan: MPU J-49 wp03Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3974.16 3909.26 5165.00 9-5/8 9-5/8" Surface Casing4271.90 4207.00 16381.35 4-1/2 4-1/2" Production Casing Clearance SummaryAnticollision Report09 April, 2025Hilcorp Alaska, LLCMilne PointM Pt J PadPlan: MPU J-49MPU J-49MPU J-49 wp03Reference Design: M Pt J Pad - Plan: MPU J-49 - MPU J-49 - MPU J-49 wp03Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,014,903.60 N, 552,005.45 E (70° 27' 05.25" N, 149° 34' 32.45" W)Datum Height: J-49 as staked @ 64.90usft (Original Well Elev)Scan Range: 5,165.00 to 16,381.35 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.17 Build: 04Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-49 - MPU J-49 wp03Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 5,165.00 to 16,381.35 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt J Pad - Plan: MPU J-49 - MPU J-49 - MPU J-49 wp03MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt E PadMPE-28 - MPE-28 - MPE-282.8415,836.55-84.558,147.740.03215,836.55Clearance FactorFAIL - Plan: MPU E-48 - MPU E-48 - MPU E-48 wp07 873.89 5,937.08 669.81 18,311.21 4.2825,937.08Ellipse Separation Pass - Plan: MPU E-48 - MPU E-48 - MPU E-48 wp07 934.42 14,115.00 705.03 10,276.75 4.07414,115.00Clearance Factor Pass - M Pt G PadMPG-03 - MPG-03 - MPG-03 348.52 11,919.55 159.92 5,185.73 1.84811,919.55Centre Distance Pass - MPG-03 - MPG-03 - MPG-03 364.57 12,040.00 132.12 5,237.72 1.56812,040.00Ellipse Separation Pass - MPG-03 - MPG-03 - MPG-03 371.82 12,065.00 133.67 5,247.40 1.56112,065.00Clearance Factor Pass - MPG-03 - MPG-03A - MPG-03A 525.14 12,076.65 406.21 5,221.06 4.41512,076.65Centre Distance Pass - MPG-03 - MPG-03A - MPG-03A 534.99 12,240.00 393.91 5,351.70 3.79212,240.00Ellipse Separation Pass - MPG-03 - MPG-03A - MPG-03A 578.68 12,465.00 414.40 5,526.85 3.52212,465.00Clearance Factor Pass - MPG-04 - MPG-04 - MPG-04113.749,465.0017.044,304.531.1769,465.00Clearance FactorPass - MPG-04 - MPG-04 - MPG-04112.499,482.3216.984,303.691.1789,482.32Ellipse SeparationPass - MPG-06 - MPG-06 - MPG-06 591.27 12,239.99 427.78 5,290.40 3.61612,239.99Clearance Factor Pass - MPG-07 - MPG-07 - MPG-07 1,065.33 10,241.80 992.29 4,070.96 14.58510,241.80Centre Distance Pass - MPG-07 - MPG-07 - MPG-07 1,066.31 10,290.00 990.94 4,087.19 14.14810,290.00Ellipse Separation Pass - MPG-07 - MPG-07 - MPG-07 1,173.98 10,765.00 1,078.58 4,245.58 12.30610,765.00Clearance Factor Pass - MPG-08 - MPG-08 - MPG-08 865.88 8,015.00 791.61 4,413.17 11.6588,015.00Clearance Factor Pass - MPG-08 - MPG-08 - MPG-08 851.28 8,140.00 779.30 4,361.23 11.8278,140.00Ellipse Separation Pass - MPG-08 - MPG-08 - MPG-08 850.97 8,161.32 779.46 4,352.04 11.9018,161.32Centre Distance Pass - MPG-08 - MPG-08A - MPG-08A 708.55 7,940.00 621.27 4,735.80 8.1187,940.00Clearance Factor Pass - MPG-08 - MPG-08A - MPG-08A 705.99 7,990.00 619.39 4,717.88 8.1527,990.00Ellipse Separation Pass - MPG-08 - MPG-08A - MPG-08A 705.98 7,992.85 619.43 4,716.94 8.1567,992.85Centre Distance Pass - MPG-11 - MPG-11 - MPG-11 433.91 13,791.58 164.03 6,788.50 1.60813,791.58Centre Distance Pass - MPG-11 - MPG-11 - MPG-11445.1713,890.00143.046,828.771.47313,890.00Clearance FactorPass - MPG-12 - MPG-12 - MPG-12 856.52 9,122.75 765.03 4,276.74 9.3629,122.75Centre Distance Pass - MPG-12 - MPG-12 - MPG-12 856.69 9,140.00 765.00 4,275.03 9.3439,140.00Ellipse Separation Pass - MPG-12 - MPG-12 - MPG-12 859.13 9,190.00 767.00 4,270.07 9.3269,190.00Clearance Factor Pass - 09 April, 2025 - 15:44COMPASSPage 2 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-49 - MPU J-49 wp03Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 5,165.00 to 16,381.35 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt J Pad - Plan: MPU J-49 - MPU J-49 - MPU J-49 wp03MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPG-14 - MPG-14 - MPG-14 284.65 6,090.00 212.14 5,716.63 3.9266,090.00Clearance Factor Pass - MPG-14 - MPG-14 - MPG-14 260.82 6,190.00 199.92 5,657.43 4.2826,190.00Ellipse Separation Pass - MPG-14 - MPG-14 - MPG-14 257.00 6,244.30 203.13 5,623.75 4.7706,244.30Centre Distance Pass - MPG-14 - MPG-14L1 - MPG-14L1 284.65 6,090.00 212.14 5,716.63 3.9266,090.00Clearance Factor Pass - MPG-14 - MPG-14L1 - MPG-14L1 260.82 6,190.00 199.92 5,657.43 4.2826,190.00Ellipse Separation Pass - MPG-14 - MPG-14L1 - MPG-14L1 257.00 6,244.30 203.13 5,623.75 4.7706,244.30Centre Distance Pass - MPG-16 - MPG-16 - MPG-16 199.17 15,972.48 115.82 9,485.97 2.38915,972.48Centre Distance Pass - MPG-16 - MPG-16 - MPG-16 207.32 16,040.00 112.09 9,521.29 2.17716,040.00Ellipse Separation Pass - MPG-16 - MPG-16 - MPG-16 233.28 16,115.00 119.80 9,560.58 2.05616,115.00Clearance Factor Pass - MPG-16 - MPG-16L1 - MPG-16L1 138.59 15,944.73 53.08 9,457.07 1.62115,944.73Centre Distance Pass - MPG-16 - MPG-16L1 - MPG-16L1 139.87 15,965.00 52.48 9,464.58 1.60015,965.00Clearance Factor Pass - MPG-16 - MPG-16PB1 - MPG-16PB1 690.09 13,681.50 466.81 7,057.13 3.09113,681.50Centre Distance Pass - MPG-16 - MPG-16PB1 - MPG-16PB1 690.90 13,740.00 465.84 7,096.02 3.07013,740.00Ellipse Separation Pass - MPG-16 - MPG-16PB1 - MPG-16PB1 715.74 14,265.00 471.26 7,498.00 2.92814,265.00Clearance Factor Pass - MPG-16 - MPG-16PB2 - MPG-16PB2 670.52 14,640.00 400.99 7,934.05 2.48814,640.00Clearance Factor Pass - MPG-16 - MPG-16PB2 - MPG-16PB2 670.21 14,660.54 401.35 7,936.00 2.49314,660.54Centre Distance Pass - MPG-18 - MPG-18 - MPG-18 703.49 9,390.00 574.85 6,738.78 5.4689,390.00Ellipse Separation Pass - MPG-18 - MPG-18 - MPG-18 703.49 9,392.57 574.85 6,736.57 5.4699,392.57Centre Distance Pass - MPG-18 - MPG-18 - MPG-18 766.95 10,715.00 621.85 5,323.43 5.28610,715.00Clearance Factor Pass - MPG-18 - MPG-18L1 - MPG-18L1 666.21 9,458.13 535.62 6,634.42 5.1029,458.13Clearance Factor Pass - MPG-18 - MPG-18PB1 - MPG-18PB1 785.96 10,390.00 622.54 5,578.00 4.80910,390.00Clearance Factor Pass - MPG-18 - MPG-18PB1 - MPG-18PB1 783.35 10,415.00 621.81 5,569.84 4.84910,415.00Ellipse Separation Pass - MPG-18 - MPG-18PB1 - MPG-18PB1 766.83 10,696.50 621.84 5,334.51 5.28910,696.50Centre Distance Pass - MPG-19 - MPG-19 - MPG-19 687.90 12,973.75 572.02 5,926.74 5.93612,973.75Centre Distance Pass - MPG-19 - MPG-19 - MPG-19 707.08 13,265.00 554.41 6,169.09 4.63113,265.00Ellipse Separation Pass - MPG-19 - MPG-19 - MPG-19 859.41 14,440.00 598.59 7,556.55 3.29514,440.00Clearance Factor Pass - M Pt I PadMPU I-20 - MPU I-20 - MPU I-20 1,113.72 5,165.00 1,010.47 10,400.10 10.7875,165.00Clearance Factor Pass - MPU I-27 - MPU I-27 - MPU I-27 1,161.47 5,165.00 1,055.87 10,616.89 10.9985,165.00Clearance Factor Pass - MPU I-35i - MPU I-35i - MPU I-35i 1,287.06 5,165.00 1,185.76 10,180.35 12.7065,165.00Clearance Factor Pass - 09 April, 2025 - 15:44COMPASSPage 3 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-49 - MPU J-49 wp03Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 5,165.00 to 16,381.35 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt J Pad - Plan: MPU J-49 - MPU J-49 - MPU J-49 wp03MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt J PadMPJ-01 - MPJ-01 - MPJ-01 1,208.96 5,165.00 1,172.19 4,281.72 32.8825,165.00Ellipse Separation Pass - MPJ-01 - MPJ-01 - MPJ-01 1,233.21 5,190.00 1,195.41 4,284.57 32.6265,190.00Clearance Factor Pass - MPJ-01 - MPJ-01A - MPJ-01A 1,251.15 5,165.00 1,217.51 4,063.43 37.1885,165.00Ellipse Separation Pass - MPJ-01 - MPJ-01A - MPJ-01A 1,275.93 5,190.00 1,241.43 4,063.43 36.9795,190.00Clearance Factor Pass - MPJ-01 - MPJ-01AL1 - MPJ-01AL1 1,251.15 5,165.00 1,217.61 4,063.43 37.2995,165.00Ellipse Separation Pass - MPJ-01 - MPJ-01AL1 - MPJ-01AL1 1,275.93 5,190.00 1,241.53 4,063.43 37.0865,190.00Clearance Factor Pass - MPJ-02 - MPJ-02 - MPJ-02 383.91 7,340.00 266.03 5,619.08 3.2577,340.00Clearance Factor Pass - MPJ-02 - MPJ-02 - MPJ-02 382.65 7,365.00 265.21 5,634.83 3.2587,365.00Ellipse Separation Pass - MPJ-02 - MPJ-02 - MPJ-02 382.22 7,393.50 265.76 5,652.81 3.2827,393.50Centre Distance Pass - MPJ-03 - MPJ-03 - MPJ-03 2,941.54 5,165.00 2,915.47 2,200.00 112.8305,165.00Clearance Factor Pass - MPJ-04 - MPJ-04 - MPJ-04 2,549.69 5,165.00 2,508.90 2,776.08 62.5005,165.00Ellipse Separation Pass - MPJ-04 - MPJ-04 - MPJ-04 3,510.35 8,890.00 3,391.50 5,301.23 29.5368,890.00Clearance Factor Pass - MPJ-05 - MPJ-05 - MPJ-05 201.22 5,765.00 143.07 5,147.77 3.4605,765.00Clearance Factor Pass - MPJ-05 - MPJ-05 - MPJ-05 142.46 5,940.00 115.16 5,279.95 5.2185,940.00Ellipse Separation Pass - MPJ-05 - MPJ-05 - MPJ-05 139.70 5,985.46 116.10 5,315.53 5.9205,985.46Centre Distance Pass - MPJ-06 - MPJ-06 - MPJ-06 1,517.38 5,165.00 1,456.92 4,308.90 25.1005,165.00Clearance Factor Pass - MPJ-08 - MPJ-08 - MPJ-08 1,822.47 5,165.00 1,777.27 3,608.04 40.3275,165.00Clearance Factor Pass - MPJ-08 - MPJ-08A - MPJ-08A 1,822.47 5,165.00 1,777.27 3,608.84 40.3275,165.00Clearance Factor Pass - MPJ-09 - MPJ-09 - MPJ-09 2,433.97 5,165.00 2,385.21 3,014.97 49.9175,165.00Clearance Factor Pass - MPJ-09 - MPJ-09A - MPJ-09A 2,433.97 5,165.00 2,385.22 3,015.24 49.9235,165.00Clearance Factor Pass - MPJ-10 - MPJ-10 - MPJ-10 153.15 5,204.94 89.39 4,482.30 2.4025,204.94Centre Distance Pass - MPJ-10 - MPJ-10 - MPJ-10 156.28 5,240.00 83.57 4,500.48 2.1495,240.00Ellipse Separation Pass - MPJ-10 - MPJ-10 - MPJ-10 162.17 5,265.00 84.09 4,513.41 2.0775,265.00Clearance Factor Pass - MPJ-11 - MPJ-11 - MPJ-11 1,576.98 5,165.00 1,541.84 3,807.67 44.8755,165.00Clearance Factor Pass - MPJ-12 - MPJ-12 - MPJ-12 666.52 5,165.00 597.59 4,364.25 9.6705,165.00Clearance Factor Pass - MPJ-13 - MPJ-13 - MPJ-13 617.84 5,165.00 565.23 4,395.33 11.7445,165.00Centre Distance Pass - MPJ-13 - MPJ-13 - MPJ-13 619.47 5,190.00 565.15 4,400.13 11.4055,190.00Ellipse Separation Pass - MPJ-13 - MPJ-13 - MPJ-13 710.29 5,490.00 635.91 4,440.55 9.5495,490.00Clearance Factor Pass - 09 April, 2025 - 15:44COMPASSPage 4 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-49 - MPU J-49 wp03Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 5,165.00 to 16,381.35 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt J Pad - Plan: MPU J-49 - MPU J-49 - MPU J-49 wp03MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-15 - MPJ-15 - MPJ-15 2,505.10 5,165.00 2,439.09 3,265.10 37.9465,165.00Clearance Factor Pass - MPJ-16 - MPJ-16 - MPJ-16 1,985.49 5,165.00 1,927.54 3,721.29 34.2585,165.00Clearance Factor Pass - MPJ-17 - MPJ-17 - MPJ-17 2,960.06 5,165.00 2,926.95 2,315.94 89.3965,165.00Clearance Factor Pass - MPJ-18 - MPJ-18 - MPJ-18 2,446.20 5,165.00 2,392.02 3,087.49 45.1535,165.00Clearance Factor Pass - MPJ-23 - MPJ-23 - MPJ-23 3,030.20 5,165.00 3,001.76 2,241.60 106.5625,165.00Clearance Factor Pass - MPJ-23 - MPJ-23A - MPJ-23A 3,030.20 5,165.00 3,001.30 2,249.10 104.8795,165.00Clearance Factor Pass - MPJ-23 - MPJ-23L1 - MPJ-23L1 3,030.20 5,165.00 3,001.76 2,241.60 106.5625,165.00Clearance Factor Pass - MPJ-24 - MPJ-24 - MPJ-24 2,961.24 5,165.00 2,930.64 2,217.31 96.7655,165.00Clearance Factor Pass - MPJ-24 - MPJ-24A - MPJ-24A 2,961.24 5,165.00 2,930.29 2,213.60 95.6645,165.00Clearance Factor Pass - MPJ-24 - MPJ-24L1 - MPJ-24L1 2,961.24 5,165.00 2,930.64 2,217.31 96.7615,165.00Clearance Factor Pass - MPJ-24 - MPJ-24L1PB1 - MPJ-24L1PB1 2,961.24 5,165.00 2,930.61 2,217.31 96.6785,165.00Clearance Factor Pass - MPJ-24 - MPJ-24L1PB2 - MPJ-24L1PB2 2,961.24 5,165.00 2,930.64 2,217.31 96.7655,165.00Clearance Factor Pass - MPJ-25 - MPJ-25 - MPJ-25 1,933.12 5,165.00 1,904.52 3,254.96 67.5825,165.00Clearance Factor Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1 1,933.12 5,165.00 1,904.52 3,254.96 67.5825,165.00Clearance Factor Pass - MPJ-27 - MPJ-27 - MPJ-27 3,087.63 5,165.00 3,063.71 2,021.17 129.0635,165.00Clearance Factor Pass - MPU J-29 - MPU J-29 - MPU J-29 2,559.89 5,165.00 2,539.14 2,428.39 123.3555,165.00Clearance Factor Pass - MPU J-29 - MPU J-29A - MPU J-29A 2,559.89 5,165.00 2,539.15 2,420.61 123.4065,165.00Clearance Factor Pass - MPU J-30i - MPU J-30 - MPU J-30 2,515.77 5,165.00 2,494.52 2,473.63 118.3875,165.00Clearance Factor Pass - MPU J-32 - MPU J-32 - MPU J-32 3,196.18 5,165.00 3,173.29 2,284.59 139.6615,165.00Ellipse Separation Pass - MPU J-32 - MPU J-32 - MPU J-32 4,501.87 11,390.00 4,298.89 11,006.00 22.17911,390.00Clearance Factor Pass - MPU J-41 - MPU J-41 - MPU J-41 3,307.99 5,165.00 3,283.26 1,992.20 133.7515,165.00Ellipse Separation Pass - MPU J-41 - MPU J-41 - MPU J-41 7,930.17 16,381.35 7,649.07 16,423.00 28.21116,381.35Clearance Factor Pass - MPU J-41 - MPU J-41PB1 - MPU J-41PB1 3,307.99 5,165.00 3,283.26 1,992.20 133.7515,165.00Ellipse Separation Pass - MPU J-41 - MPU J-41PB1 - MPU J-41PB1 7,738.63 13,265.00 7,484.66 13,522.00 30.47113,265.00Clearance Factor Pass - MPU J-43 - MPU J-43 - MPU J-43 3,218.09 5,165.00 3,194.72 2,066.17 137.6855,165.00Ellipse Separation Pass - MPU J-43 - MPU J-43 - MPU J-43 6,123.37 16,381.35 5,811.05 16,149.58 19.60616,381.35Clearance Factor Pass - MPU J-45 - MPU J-45 - MPU J-45 2,626.27 5,165.00 2,584.12 3,149.57 62.3195,165.00Ellipse Separation Pass - MPU J-45 - MPU J-45 - MPU J-45 4,036.23 16,381.35 3,737.80 14,394.91 13.52516,381.35Clearance Factor Pass - MPU J-46 - MPU J-46 - MPU J-46 1,987.00 5,165.00 1,931.85 4,489.22 36.0315,165.00Ellipse Separation Pass - MPU J-46 - MPU J-46 - MPU J-46 3,024.79 16,381.35 2,705.94 15,854.03 9.48616,381.35Clearance Factor Pass - 09 April, 2025 - 15:44COMPASSPage 5 of 8 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU J-49 - MPU J-49 wp03Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 5,165.00 to 16,381.35 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt J Pad - Plan: MPU J-49 - MPU J-49 - MPU J-49 wp03MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU J-47 - MPU J-47 - MPU J-47 1,462.43 6,975.82 1,369.02 6,716.50 15.6566,975.82Centre Distance Pass - MPU J-47 - MPU J-47 - MPU J-47 1,462.66 7,015.00 1,368.71 6,738.01 15.5687,015.00Ellipse Separation Pass - MPU J-47 - MPU J-47 - MPU J-47 1,984.56 16,381.35 1,667.68 15,813.13 6.26316,381.35Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.70 1,500.00 MPU J-49 wp03 GYD_Quest GWD1,500.00 5,165.00 MPU J-49 wp03 3_MWD+IFR2+MS+Sag5,165.00 16,381.35 MPU J-49 wp03 GYD_Quest GWDEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.09 April, 2025 - 15:44COMPASSPage 6 of 8 0.001.002.003.004.00Separation Factor5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800Measured Depth (1200 usft/in)MPU E-48 wp07MPE-28MPG-19MPG-14MPG-06MPG-11MPG-03MPG-04MPG-16MPG-16L1MPG-16PB2MPJ-05MPJ-02MPJ-10No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU J-49 NAD 1927 (NADCON CONUS)Alaska Zone 0431.20+N/-S +E/-W Northing Easting Latittude Longitude0.000.006014903.60552005.4570° 27' 5.2470 N149° 34' 32.4491 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU J-49, True NorthVertical (TVD) Reference:J-49 as staked @ 64.90usft (Original Well Elev)Measured Depth Reference:J-49 as staked @ 64.90usft (Original Well Elev)Calculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2025-03-20T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1500.00 MPU J-49 wp03 (MPU J-49) GYD_Quest GWD1500.00 5165.00 MPU J-49 wp03 (MPU J-49) 3_MWD+IFR2+MS+Sag5165.00 16381.35 MPU J-49 wp03 (MPU J-49) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200Measured Depth (1200 usft/in)NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 16381.35Project: Milne PointSite: M Pt J PadWell: Plan: MPU J-49Wellbore: MPU J-49Plan: MPU J-49 wp03Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name3974.16 3909.26 5165.00 9-5/8 9-5/8" Surface Casing4271.90 4207.00 16381.35 4-1/2 4-1/2" Production Casing 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. MPU J-49 SCHRADER BLUFF OIL 225-046 MILNE POINT WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT J-49Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERWell bore segAnnular DisposalPTD#:2250460Field & Pool:MILNE POINT, SCHRADER BLFF OIL - 525140NA1Permit fee attachedYesADL025906 and ADL0255182Lease number appropriateYes3Unique well name and numberYesMILNE POINT, SCHRADER BLFF OIL - 525140 - governed by CO 477, 477.0054Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitYesArea Injection Order No. 10-C14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15All wells within 1/4 mile area of review identified (For service well only)YesUp to 30 days via a reverse circulating jet16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes20" 129.5# X-52 conductor driven to 124'18Conductor string providedYesFully cemented 9-625" casing from 2348' ssTVD19Surface casing protects all known USDWsYesFully cemented with significant excess20CMT vol adequate to circulate on conductor & surf csgNo9-5/8" surface casing will land horizontally in the reservoir. Fully cemented.21CMT vol adequate to tie-in long string to surf csgYes9-5/8" surface casing will land horizontally in the reservoir. Fully cemented.22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYesDoyon 14 has adequate tankage and good trucking support24Adequate tankage or reserve pitNAThis is a grassroots well.25If a re-drill, has a 10-403 for abandonment been approvedYesHalliburton collision scan identifies no close approaches with HSE risk.E-28 to be abandoned before spud.26Adequate wellbore separation proposedYes16" diverter line27If diverter required, does it meet regulationsYesAll fluids will be overbalanced to pore pressure28Drilling fluid program schematic & equip list adequateYes5M stack, 1 annular, 3 ram stack 1 flow cross29BOPEs, do they meet regulationYes5000 psi stack tested to 3000 psi30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYesNo H2S events on MPU J pad. Monitoring required33Is presence of H2S gas probableYes34Mechanical condition of wells within AOR verified (For service well only)YesRig will have detection equipment. I-04A had 36ppm H2S (2012).35Permit can be issued w/o hydrogen sulfide measuresYesReservoir anticipated to be normally pressured (8.46 ppg EMW). At least 5 faults expected.36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate11-Jun-25ApprMGRDate16-May-25ApprADDDate11-Jun-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 6/12/2025