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Home My WebLink About225-082Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 1/21/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260121 Well API # PTD # Log Date Log Company Log Type AOGCC E-Set# BCU 16RD 50133205540100 207125 12/3/2025 AK E-LINE PPROF T41253 BRU 211-35 50283201890000 223050 11/7/2025 AK E-LINE Perf T41254 BRU 213-26 50283201920000 223069 11/23/2025 AK E-LINE Perf T41255 BRU 213-26T 50283202040000 225038 11/4/2025 AK E-LINE Perf T41256 BRU 241-34S 50283201980000 224077 11/9/2025 AK E-LINE Perf T41257 BRU 241-34T 50283201810000 220052 11/6/2025 AK E-LINE Perf T41258 BRU 244-27 50283201850000 222038 12/13/2025 AK E-LINE Perf T41259 BRU 244-27 50283201850000 222038 12/19/2025 AK E-LINE StripGun T41259 GP ST 17586 9 50733204480000 193062 11/13/2025 AK E-LINE Perf T41260 IRU 241-01 50283201840000 221076 12/21/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/30/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/16/2025 AK E-LINE Plug T41261 IRU 241-01 50283201840000 221076 11/26/2025 AK E-LINE Plug/Perf T41261 KALOTSA 01 50133206570000 216132 11/19/2025 AK E-LINE Perf T41262 KBU 31-18 50133206490000 215024 11/8/2025 AK E-LINE Drift/PPROF T41263 KU 12-17 50133205770000 208089 11/14/2025 AK E-LINE StimGun T41264 LRU C-01RD 50283200610100 201168 11/27/2025 AK E-LINE RCT/Perf T41265 MPI 2-32 50029220840000 190119 12/10/2025 AK E-LINE LDL T41266 MPI 2-38 50029220900000 190129 12/5/2025 AK E-LINE LDL T41267 MPU H-16 50029232270000 204190 12/3/2025 AK E-LINE CBL T41268 MPU H-16 50029232270000 204190 11/19/2025 AK E-LINE TubingCut T41268 MPU I-14 50029232140000 204119 11/13/2025 AK E-LINE CBL T41269 NCIU A-06A 50883200260100 225071 11/28/2025 AK E-LINE Perf/Plug T41270 NCIU A-08 50883200280000 169063 12/2/2025 AK E-LINE GPT T41271 NCIU A-19 50883201940000 224026 12/16/2025 AK E-LINE GPT T41272 NCIU A-19 50883201940000 224026 12/12/2025 AK E-LINE GPT/Perf/Plug T41272 NCIU A-19 50883201940000 224026 12/17/2025 AK E-LINE Perf T41272 NCIU A-21A 50883201990100 225075 12/30/2025 AK E-LINE PPROF T41273 OP19-T1N 50029234910000 213068 11/19/2025 AK E-LINE TubingPunch T41274 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:35 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PCU D-10 50283202080000 225082 12/9/2025 AK E-LINE Perf T41275 SCU 322C-04 50133101040100 215217 12/4/2025 AK E-LINE TubingPunch T41276 SRU 222-33 50133207150000 223100 12/7/2025 AK E-LINE Plug T41277 SU 43-10 50133207390000 225107 11/26/2025 AK E-LINE CBL T41278 TBU A-12RD 50733200760100 171029 11/29/2025 AK E-LINE Perf T41279 TBU D-24A 50733202240100 174064 12/2/2025 AK E-LINE TubingPunch T41280 TBU D-24A 50733202240100 174064 11/21/2025 AK E-LINE TubingPunch T41280 TBU M-10 50733205880000 209154 11/15/2025 AK E-LINE Perf T41281 Please include current contact information if different from above. PCU D-10 50283202080000 225082 12/9/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:51 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/20/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251120 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 23 50133206350000 214093 10/14/2025 AK E-LINE PPROF T41129 BR 09-86 50733204480000 193062 10/28/2025 AK E-LINE Perf T41130 BRU 213-26T 50283202040000 225038 10/30/2025 AK E-LINE Perf T41131 END 1-57 50029218730000 188114 11/16/2025 READ PressTempSurvey T41132 END 2-28B 50029218470200 203006 11/15/2025 READ PressTempSurvey T41133 END 2-30B 50029222280200 208187 11/18/2025 READ PressTempSurvey T41134 END 2-52 50029217500000 187092 10/28/2025 HALLIBURTON LDL T41135 KALOTSA 10 50133207320000 224147 11/7/2025 AK E-LINE Perf T41136 MPF-92 50029229240000 198193 11/8/2025 READ CaliperSurvey T41137 MPH-01 50029220610000 190086 11/7/2025 READ CaliperSurvey T41138 MPI-14 50029232140000 204119 11/8/2025 READ CaliperSurvey T41139 MPU H-01 50029220610000 190086 11/4/2025 AK E-LINE Drift/CBL/Caliper/Packer T41138 MPU I-14 50029232140000 204119 11/8/2025 AK E-LINE RigAssist T41139 MPU J-02 50029220710000 190096 11/6/2025 AK E-LINE Caliper/Gyro T41140 NCIU A-07A 50883200270100 225094 11/1/2025 AK E-LINE CBL T41141 NCIU A-07A 50883200270100 225094 11/4/2025 AK E-LINE Perf T41141 ODSN-01A 50703206480100 216008 10/24/2025 HALLIBURTON PACKER T41142 ODSN-25 50703206560000 212030 10/23/2025 HALLIBURTON PACKER T41143 ODSN-26 50703206420000 211121 11/4/2025 HALLIBURTON PERF T41144 PBU 02-10B 50029201630200 200064 10/27/2025 HALLIBURTON RBT T41145 PBU A-24B 50029207430200 225067 10/20/2025 BAKER MRPM T41146 PBU B-05E 50029202760500 225093 10/23/2025 HALLIBURTON RBT T41147 PBU B-05E 50029202760500 225093 10/23/2025 BAKER MRPM T41147 PBU B-20A 50029208420100 212026 10/16/2025 BAKER SPN T41148 PBU F-18B 50029206360200 225099 11/5/2025 HALLIBURTON RBT-COILFLAG T41149 PCU D-10 50283202080000 225082 10/31/2025 AK E-LINE Patch T41150 PCU D-10 50283202080000 225082 10/17/2025 AK E-LINE Perf T41150 PCU D-10 50283202080000 225082 10/22/2025 AK E-LINE Perf T41150 PCU D-10 50283202080000 225082 10/29/2025 AK E-LINE Perf T41150 T41150PCU D-10 50283202080000 225082 10/31/2025 AK E-LINE Patch T41150PCU D-10 50283202080000 225082 10/17/2025 AK E-LINE Perf T41150PCU D-10 50283202080000 225082 10/22/2025 AK E-LINE Perf PCU D-10 50283202080000 225082 10/29/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.20 13:27:19 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PCU D-11 50283202090000 225088 10/16/2025 AK E-LINE CBL T41151 PCU D-11 50283202090000 225088 10/24/2025 AK E-LINE Perf T41151 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.20 13:27:31 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/14/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251114 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# PBU 01-10A 50029201690200 225055 8/29/2025 BAKER MRPM BRU 224-34T 50283202050000 225044 8/9/2025 AK E-LINE CBL MGS ST 17595 30 50733204560000 193120 8/13/2025 AK E-LINE CBL MPU H-11 50029228020000 197163 8/17/2025 AK E-LINE JetCut PCU D-10 50283202080000 225082 10/6/2025 AK E-LINE CBL Please include current contact information if different from above. T41100 T41101 T41102 T41103 T41104PCU D-10 50283202080000 225082 10/6/2025 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.14 12:58:13 -09'00' Hilf-orp ahwk*_ LI.c Date: 11/12/2025 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 To: Alaska Oil & Gas Conservation Commission Petroleum Geology Assistant 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PCU D-10 PTD: 225-082 API: 50-283-20208-00-00 Washed and Dried Well Samples (09/26/2025) 30' Frequency B Set (3 Boxes): YYI�L.L Bf3X SAlfAP#.E �TERVAk � f PCU D-10 BOX 1 OF 3 2400' - 3810' MD PCU D-10 BOX 2 OF 3 3810' - 5040' MD PCU D-10 BOX 3 OF 3 5040' - 5757' MD Please include current contact information if different from above. NOV 12 2025 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal. aas-obz Received Date: �'3 0 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: 10/27/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL Well: PCU D-10 PTD: 225-082 API: 50-283-20208-00-00 FINAL MUDLOGS - EOW DRILLING REPORTS (08/19/2025 to 09/26/2025) 1. FINAL EOW REPORT 2. DAILY REPORTS 3. DIGITAL DATA (LAS) 4. LITHOLOGY DESCRIPTIONS 5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS) Formation Log LWD Combo Log Gas Ratio Log Drilling Dynamics Log SFTP Transfer - Main Folder Contents: Please include current contact information if different from above. 225-082 T41038 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.27 14:19:23 -08'00' 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:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz Subject:RE: PCU D-10 (PTD# 225-082) Sundry # 325-598 additional zone Date:Tuesday, October 21, 2025 4:15:00 PM Approved. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, October 21, 2025 4:06 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: PCU D-10 (PTD# 225-082) Sundry # 325-598 additional zone Bryan, We would like to add one additional zone to be perforated in PCU D-10 (PTD# 225-082). The new zone would be the Beluga D5 FM MD TOP MD BASE TVD TOP TVD BASE H BEL D5 ±4,000'±4,004'±3,839'±3,843'±4' Regards Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C 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, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Arvell Bass - (C); Donna Ambruz Subject:RE: PCU D-10 (PTD# 225-082) Cement Bond Log Date:Monday, October 6, 2025 4:27:00 PM Chad, Hilcorp has approval to proceed with perfs per the approved sundry, and approval to add the additional perf interval in your email below. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Monday, October 6, 2025 3:13 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Arvell Bass - (C) <Arvell.Bass@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: PCU D-10 (PTD# 225-082) Cement Bond Log Bryan, Please find attached the cement bond log for PCU D-10 well. We have good cement from the bottom of the well to the top of the liner at 2250’. Please let us know if we have approval to perforate based on this CBL. We also would like to add one more perf to the table in the Sterling sands if we don’t find gas before we get there. Sterling B4 FM MD TOP MD BASE TVD TOP TVD BASE H ST B4 ±3,786'±3,790'±3,628'±3,632'±4' Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C 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, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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: 10/08/2025 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Well: PCU D-10 PTD: 225-082 API: 50-283-20208-00-00 FINAL LWD FORMATION EVALUATION LOGS (08/19/2025 to 08/26/2025) iCruise, DGR and BaseStar Gamma Ray ADR and StrataStar Resistivity LithoStar Density and Thermal Neutron Porosity Pressure While Drilling (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey Folder Contents: Please include current contact information if different from above. 225-082 T40968 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.09 08:54:16 -08'00' 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 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): 5,757'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi Liner 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: Chad Helgeson, Operations Engineer Contact Email:chelgeson@hilcorp.com Contact Phone: 907-777-8405 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 N/A Length LTP; N/A 2,228 MD / 2,107 TVD; N/A, N/A 5,569' 5,691' 5,504' 16" Pretty Creek Unit (PCU) D-1020 AAC 25.055 Same 5,567'3-1/2" 2139 Pretty Creek Undefined Gas Size October 6, 2025 3-1/2" 5,755' Perforation Depth MD (ft): 2,980psi 6,890psi 135' 2,400' MD See Attached Schematic 135' 2,400'7-5/8" 3,527' See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 L-80 TVD Burst 2,265' 10,160psi 2,270' 135' Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0058810 / ADL0063048 225-082 50-283-20208-00-00 Hilcorp Alaska, LLC Proposed Pools: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Other: Initial Completion Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: 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: No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 7:49 am, Oct 02, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.10.01 18:40:41 - 08'00' Noel Nocas (4361) 325-598 DSR-10/2/25BJM 10/2/25 Submit CBL and obtain approval from AOGCC before perforating. 10-407 TS 10/3/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.10.03 11:16:59 -08'00' 10/03/25 RBDMS JSB 100625 Well Prognosis Well Name:PCU-10 API Number:50-283-20208-00-00 Current Status:New Drill Well Permit to Drill Number:225-082 Second Call Engineer:Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) First Call Engineer:Scott Warner (907) 564-4506 (O) (907) 830-8863 (C) Maximum Expected BHP:2413 psi @ 5486’ TVD (Based on 0.44 psi/ft gradient) Max. Potential Surface Pressure:2139 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient:0.776 psi/ft using 14.92 ppg EMW FIT at the 7-5/8” surface casing shoe Shallowest Potential Perf TVD:MPSP/(0.776-0.05) = 2139 psi / 0.726 = 2946’ TVD with H Sands open Well Status:New Drill Well Initial Completion Brief Well Summary PCU D-10 is the first well drilled on Diamond pad and the 2nd of three grass roots well to be drilled in the 2025 Pretty Creek drilling campaign targeting the Sterling and Beluga sands. The objective of this sundry is to perforate the well and flow the new drill well. Wellbore Conditions: - Max Inclination – 26° at 1,682’ MD - Max DLS °/100’ – 5° at 2,797’ MD - T & IA PT to 3100 psi (30 min) on 9/28/25 - Min ID- 2.992” 3-1/2” tubing/liner - Liner is full of ~9.6 ppg 6% KCl mud - Tubing and IA are displaced to 8.4 ppg CIW Work to be completed on PTD# 225-059 Step 20.0: x Eline Run CBL o Send results to AOGCC to review prior to perforating x CT Mud displacement & CT N2 blowdown Procedure: 1. Review all approved COAs 2. MIRU E-Line and pressure control equipment 3. PT lubricator to 250 psi low / 2,500 psi high 4. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 5. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: Below are proposed targeted sands in order of testing (bottom/up), but additional sands may be added/removed depending on results of these perfs, between the proposed top and bottom perfs Sands Top MD Btm MD Top TVD Btm TVD Amt ώ³͏ ѷ͒Ϡ͑͒͏Д ѷ͒Ϡ͑͒͘Д ѷ͒Ϡ͏͖͗Д ѷ͒Ϡ͏͖͗Д ѷ͘Д ώ³͐ ѷ͒Ϡ͓͔͑Д ѷ͒Ϡ͔͑͐Д ѷ͒Ϡ͏͒͘Д ѷ͒Ϡ͏͗͘Д ѷ͕Д ώ³͒ ѷ͒Ϡ͖͒͘Д ѷ͒Ϡ͕͒͗Д ѷ͒Ϡ͔͑͑Д ѷ͒Ϡ͑͒͑Д ѷ͖Д ώ͑ ѷ͒Ϡ͖͏͏Д ѷ͒Ϡ͖͒͑Д ѷ͒Ϡ͔͓͒Д ѷ͒Ϡ͔͖͓Д ѷ͒͑Д ώ͐ ѷ͒Ϡ͗͏͑Д ѷ͒Ϡ͗͏͘Д ѷ͒Ϡ͕͓͒Д ѷ͒Ϡ͕͔͏Д ѷ͖Д Well Prognosis ώ͒ ѷ͒Ϡ͗͐͘Д ѷ͒Ϡ͗͘͘Д ѷ͒Ϡ͖͒͐Д ѷ͒Ϡ͖͒͏Д ѷ͗Д ώ͓ ѷ͒Ϡ͘͏͔Д ѷ͒Ϡ͐͐͘Д ѷ͒Ϡ͖͓͔Д ѷ͒Ϡ͖͔͐Д ѷ͕Д ([ώ"͕ ѷ͓Ϡ͏͑͐Д ѷ͓Ϡ͏͒͐Д ѷ͒Ϡ͔͗͘Д ѷ͒Ϡ͕͗͘Д ѷ͐͏Д ([ώ"͕ ѷ͓Ϡ͐͏͏Д ѷ͓Ϡ͕͐͑Д ѷ͒Ϡ͖͒͘Д ѷ͒Ϡ͕͒͘Д ѷ͖͑Д ([ώ"͕ ѷ͓Ϡ͐͒͑Д ѷ͓Ϡ͓͐͑Д ѷ͒Ϡ͕͘͘Д ѷ͒Ϡ͖͘͘Д ѷ͐͏Д ([ώ(͕ ѷ͓Ϡ͐͗͑Д ѷ͓Ϡ͐͑͘Д ѷ͓Ϡ͏͐͗Д ѷ͓Ϡ͏͑͗Д ѷ͐͏Д ([ώ(͕ ѷ͓Ϡ͕͑͏Д ѷ͓Ϡ͕͕͑Д ѷ͓Ϡ͏͔͘Д ѷ͓Ϡ͐͏͐Д ѷ͕Д ([ώ> ѷ͓Ϡ͓͒͑Д ѷ͓Ϡ͒͒͒Д ѷ͓Ϡ͔͐͗Д ѷ͓Ϡ͕͖͐Д ѷ͘Д ([ώ>͓ ѷ͓Ϡ͖͔͒Д ѷ͓Ϡ͒͗͒Д ѷ͓Ϡ͑͏͗Д ѷ͓Ϡ͕͑͐Д ѷ͗Д ([ώ@ ѷ͓Ϡ͕͓͏Д ѷ͓Ϡ͕͔͕Д ѷ͓Ϡ͓͖͏Д ѷ͓Ϡ͓͔͗Д ѷ͕͐Д ([ώ@͓ ѷ͓Ϡ͗͐͘Д ѷ͓Ϡ͖͗͑Д ѷ͓Ϡ͕͓͕Д ѷ͓Ϡ͕͔͓Д ѷ͗Д ([ώF͐͏ώ ѷ͔Ϡ͒͗͘Д ѷ͔Ϡ͕͒͘Д ѷ͔Ϡ͑͏͖Д ѷ͔Ϡ͓͑͐Д ѷ͖Д ([ώF͐͏ώ ѷ͔Ϡ͓͏͏Д ѷ͔Ϡ͓͔͐Д ѷ͔Ϡ͑͐͗Д ѷ͔Ϡ͑͒͒Д ѷ͔͐Д ([ώF͐͏ώ ѷ͔Ϡ͓͖͖Д ѷ͔Ϡ͓͗͑Д ѷ͔Ϡ͓͑͘Д ѷ͔Ϡ͑͘͘Д ѷ͔Д ([ώF͐͏ώ" ѷ͔Ϡ͓͗͘Д ѷ͔Ϡ͓͕͘Д ѷ͔Ϡ͒͏͕Д ѷ͔Ϡ͒͐͒Д ѷ͖Д ([ώIώ( ѷ͔Ϡ͔͔͏Д ѷ͔Ϡ͔͔͔Д ѷ͔Ϡ͕͕͒Д ѷ͔Ϡ͖͒͐Д ѷ͔Д ([ώI ѷ͔Ϡ͕͕͑Д ѷ͔Ϡ͕͖͑Д ѷ͔Ϡ͓͖͕Д ѷ͔Ϡ͓͕͗Д ѷ͐͏Д a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Pending well production, all perf intervals may not be completed ii. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 6. RDMO 7. Turn well over to production & flow test well 8. Test SVS as necessary once well has reached stable flow rates a. Notify state 24 hrs prior to testing within 5 days of stable production Attachments: 1. Current Schematic 2. Proposed Schematic Updated by JLL 09/29/25 CURRENT SCHEMATC Pretty Creek Unit PCU D-10 PTD: 225-082 API: 50-283-20208-00-00 PBTD = 5,691’ MD / TVD = 5,504’ TD = 5,757’ MD / TVD = 5,569’ RKB to GL = 20.68’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 135’ 7-5/8" Surf Csg 29.7 P-110 GBCD 6.875” Surf 2,400’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.992” 2,228’ 5,755’ 3-1/2” Production Tieback 9.3 L-80 EUE 2.992” Surf 2,265’ 1/2 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth Item 1 Cactus CTF-ONE-CTL 11” x 4-1/2” Hanger w/ 4” Type H BPV profile 2 2,228’ YJ Ranger Liner Hanger & Scout Pkr 5.75” ID on Upper polish 3 2,255’ Bullet Seal assembly 1.52’ off no-go at 2,254’ OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 139 bbl (349 sx) 12 ppg Type I II lead cement followed by 37 bbl (242 sx) 15.8 Type I II tail cement. Bumped plug @ 106 bbls. 60 bbls of returned spacer & 52 bbls of lead cement to surface, 7 bbls of losses during job. Reciprocated during the job. 3-1/2” 137 bbl (322 sx) 12 ppg lead cement followed by 24 bbl (109 sx) 15.3 tail cement. Bumped plug returned spacer & 56 bbls of lead cement to surface, 0 bbls of losses during job: TOC @ xxxx’ based on CBL on 10/x/25 6-3/4” hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Undefined Pool – No recorded Top of Pool. RA Pup 4,000’ RA Pup 4,510’ Notes: 10’ Short jt w/ RA tags 4510, 4000 10’ Short joints 5273’, 3298’ Deviation 26 deg @ 1682’, Max dogleg 5deg @ 2797’ Updated by JLL 09/29/25 PROPOSED SCHEMATC Pretty Creek Unit PCU D-10 PTD: 225-082 API: 50-283-20208-00-00 PBTD = 5,691’ MD / TVD = 5,504’ TD = 5,757’ MD / TVD = 5,569’ RKB to GL = 20.68’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 135’ 7-5/8" Surf Csg 29.7 P-110 GBCD 6.875” Surf 2,400’ 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.992” 2,228’ 5,755’ 3-1/2” Production Tieback 9.3 L-80 EUE 2.992” Surf 2,265’ 1/2 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth Item 1 Cactus CTF-ONE-CTL 11” x 4-1/2” Hanger w/ 4” Type H BPV profile 2 2,228’ YJ Ranger Liner Hanger & Scout Pkr 5.75” ID on Upper polish 3 2,255’ Bullet Seal assembly 1.52’ off no-go at 2,254’’ OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 139 bbl (349 sx) 12 ppg Type I II lead cement followed by 37 bbl (242 sx) 15.8 Type I II tail cement. Bumped plug @ 106 bbls. 60 bbls of returned spacer & 52 bbls of lead cement to surface, 7 bbls of losses during job. Reciprocated during the job. 3-1/2” 137 bbl (322 sx) 12 ppg lead cement followed by 24 bbl (109 sx) 15.3 tail cement. Bumped plug returned spacer & 56 bbls of lead cement to surface, 0 bbls of losses during job: TOC @ xxxx’ based on CBL on 10/x/25 6-3/4” hole PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status ST X0 ±3,230' ±3,239' ±3,078' ±3,087' ±9' TBD Proposed ST X1 ±3,245' ±3,251' ±3,093' ±3,098' ±6' TBD Proposed ST X3 ±3,379' ±3,386' ±3,225' ±3,232' ±7' TBD Proposed ST B2 ±3,700' ±3,732' ±3,543' ±3,574' ±32' TBD Proposed ST C1 ±3,802' ±3,809' ±3,643' ±3,650' ±7' TBD Proposed ST C3 ±3,891' ±3,899' ±3,731' ±3,730' ±8' TBD Proposed ST C4 ±3,905' ±3,911' ±3,745' ±3,751' ±6' TBD Proposed BEL D6 ±4,021' ±4,031' ±3,859' ±3,869' ±10' TBD Proposed BEL D6 ±4,100' ±4,126' ±3,937' ±3,963' ±27' TBD Proposed BEL D6 ±4,132' ±4,142' ±3,969' ±3,979' ±10' TBD Proposed BEL E6 ±4,182' ±4,192' ±4,018' ±4,028' ±10' TBD Proposed BEL E6 ±4,260' ±4,266' ±4,095' ±4,101' ±6' TBD Proposed BEL F ±4,324' ±4,333' ±4,158' ±4,167' ±9' TBD Proposed BEL F4 ±4,375' ±4,383' ±4,208' ±4,216' ±8' TBD Proposed BEL G ±4,640' ±4,656' ±4,470' ±4,485' ±16' TBD Proposed BEL G4 ±4,819' ±4,827' ±4,646' ±4,654' ±8' TBD Proposed BEL H10 A ±5,389' ±5,396' ±5,207' ±5,214' ±7' TBD Proposed BEL H10 B ±5,400' ±5,415' ±5,218' ±5,233' ±15' TBD Proposed BEL H10 C ±5,477' ±5,482' ±5,294' ±5,299' ±5' TBD Proposed BEL H10 D ±5,489' ±5,496' ±5,306' ±5,313' ±7' TBD Proposed BEL I UPPER ±5,550' ±5,555' ±5,366' ±5,371' ±5' TBD Proposed BEL I ±5,662' ±5,672' ±5,476' ±5,486' ±10' TBD Proposed RA Pup 4,000’ RA Pup 4,510’ Notes: 10’ Short jt w/ RA tags 4510, 4000 10’ Short joints 5273’, 3298’ Deviation 26 deg @ 1682’, Max dogleg 5deg @ 2797’ CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:McLellan, Bryan J (OGC) To:Nathan Sperry Cc:Cody Dinger; Regg, James B (OGC) Subject:RE: [EXTERNAL] RE: PTD 225-082 Hilcorp Well PCU D-10: Ram change Date:Tuesday, September 23, 2025 11:55:00 AM Nathan, That stack up is acceptable. Regards Bryan From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Tuesday, September 23, 2025 11:50 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Cody Dinger <cdinger@hilcorp.com>; Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] RE: PTD 225-082 Hilcorp Well PCU D-10: Ram change Bryan, Annular 2-7/8” x 5” VBR’s Blind rams Flow cross 4-1/2” FBR’s Thank you, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, September 23, 2025 11:39 AM To: Nathan Sperry <nathan.sperry@hilcorp.com> Cc: Cody Dinger <cdinger@hilcorp.com>; jim.regg <jim.regg@alaska.gov> Subject: [EXTERNAL] RE: PTD 225-082 Hilcorp Well PCU D-10: Ram change Nathan, 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. What is in the rest of the rams in the stack? You need at least one set of rams that can close on the 3-1/2” tubing in addition to the 4-1/2” FBR’s which are sized to close on the 4-1/2” DP. Please list from top down. Thanks Bryan From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Tuesday, September 23, 2025 9:25 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Cody Dinger <cdinger@hilcorp.com> Subject: PTD 225-082 Hilcorp Well PCU D-10: Ram change Bryan, While performing our BOPE test, the lower VBR’s would not pass and had to be swapped out. We replaced them with 4-1/2” FBR’s. Let me know if you need any more information. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified 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 theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Dewhurst, Andrew D (OGC) To:Nathan Sperry; Cody Dinger Cc:McLellan, Bryan J (OGC); Guhl, Meredith D (OGC); AOGCC Records (CED sponsored) Subject:RE: [EXTERNAL] PCU D-10 PTD (225-082): Question Date:Thursday, August 21, 2025 1:40:26 PM Nate, Yes. Mudlogging through the production hole only is approved. This email is sufficient documentation. Andy From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Thursday, 21 August, 2025 07:54 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Cody Dinger <cdinger@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: RE: [EXTERNAL] PCU D-10 PTD (225-082): Question Good morning Andy, Our geologist has planned mudlogging for the production hole (production hole only) w/ a minimum sample rate of 30’ and 10’ through show zones. This seems to me to satisfy the intent of the requirement. Do you have any objection to our plan? Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Tuesday, August 19, 2025 8:26 AM To: Nathan Sperry <nathan.sperry@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: RE: [EXTERNAL] PCU D-10 PTD (225-082): Question 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. Nate, Understood. Our typical cuttings sampling requirements state maximum intervals of 10’ across the targeted interval and 30’ everywhere else. The targeted interval in this well is a much larger stratigraphic zone than typical, so let me know if the sampling interval should be increased. Also, Meredith can answer any questions about sample data submissions if you have any. Andy From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Tuesday, 19 August, 2025 07:23 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Cody Dinger <cdinger@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: RE: [EXTERNAL] PCU D-10 PTD (225-082): Question Andy, Yes, we are planning to run mud logging. Thank you for clarifying the conditions that would allow you to waive the requirement, I appreciate it. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Monday, August 18, 2025 5:29 PM To: Nathan Sperry <nathan.sperry@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: [EXTERNAL] PCU D-10 PTD (225-082): Question CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Nathan, I’m completing my review of the Pretty Creek Unit D-10 PTD and have a question: Are you planning to run mud logging? Mud logs and cutting samples are required under 20 AAC 25.071, but the requirement to collect mud logs in particular can be waived if they will not significantly add to the geologic knowledge of the area. In practice, we only typically require the first well on a new pad (which this appears to be) to collect a mud log. It would also help to know what the distance is to the nearest well that has a mud log. Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis 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 responsibilityis 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis 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 responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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.govSean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Pretty Creek Unit, Undefined Gas Pool, PCU D-10 Hilcorp Alaska, LLC Permit to Drill Number: 225-082 Surface Location: 1405' FNL, 874' FWL, Sec 27, T14N, R9W, SM, AK Bottomhole Location: 946' FNL, 320' FEL, Sec 28, T14N, R9W, SM, 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. 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. Sampling interval can be increased for high ROP. 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, *UHJRU\ &.:LOVRQ Commissioner DATED this 20 th day of August 2025. Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.08.20 09:26:00 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 5,752' TVD: 5,564' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 63.8' 15. Distance to Nearest Well Open Surface: x-345617 y-2660306 Zone-4 45.3' to Same Pool: 5250' to PCU-02A 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 25 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# L-80 GBCD 2,399' Surface Surface 2,399' 2,264' 6-3/4" 3-1/2" 9.2# L-80 563/ACME 3,553' 2,199' 2,074' 5,752' 5,564' Tieback 3-1/2" 9.2# L-80 EUE 2,199' Surface Surface 2,199' 2,074' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 8/31/2025 946' to nearest unit boundary Nate Sperry nathan.sperry@hilcorp.com 907-777-8450 Tieback Assy. 1428 Cement Volume MD Drilling Manager Sean Mclaughlin 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate LengthCasing Size Plugs (measured): (including stage data) Driven L - 778 ft3 / T - 128 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 2559 GL / BF Elevation above MSL (ft): Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 764 ft3 / T - 131 ft3 2003 1055' FNL, 37' FEL, Sec 28, T14N, R9W, SM, AK 946' FNL, 320' FEL, Sec 28, T14N, R9W, SM, AK LOCI 25-001 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1405' FNL, 874' FWL, Sec 27, T14N, R9W, SM, AK ADL 58810 / ADL 63048 PCU D-10 Pretty Creek Unit Undefined Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. s N ype of W L l R L 1b S Class: os N s No s N o D s s s D 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 1:25 pm, Jul 23, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.07.23 11:07:41 - 08'00' Sean McLaughlin (4311) BOP test to 3000 psi. Annular test to 2500 psi. Submit FIT/LOT data within 48 hrs of obtaining results. 50-283-20208-00-00 DSR-7/23/25 225-082 BJM 8/19/25 A.Dewhurst 19AUG25JLC 8/19/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.08.20 09:21:58 -08'00' RBDMS JSB 082225 PCU D-10 Drilling Program Pretty Creek Unit July 22, 2025 PCU D-10 Drilling Procedure 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........................................................................................................10 10.0 N/U 21-1/4” 2M Diverter.............................................................................................................11 11.0 Drill 9-7/8” Hole Section..............................................................................................................12 12.0 Run 7-5/8” Surface Casing..........................................................................................................14 13.0 Cement 7-5/8” Surface Casing....................................................................................................17 14.0 BOP N/U and Test........................................................................................................................21 15.0 Drill 6-3/4” Hole Section..............................................................................................................22 16.0 Run 3-1/2” Production Liner......................................................................................................24 17.0 Cement 3-1/2” Production Liner................................................................................................27 18.0 3-1/2” Liner Tieback Polish Run................................................................................................31 19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................32 20.0 CBL and Nitrogen Operation (Post Rig Work)........................................................................33 21.0 Diverter Schematic ......................................................................................................................36 22.0 BOP Schematic.............................................................................................................................37 23.0 Wellhead Schematic.....................................................................................................................38 24.0 Anticipated Drilling Hazards......................................................................................................39 25.0 Hilcorp Rig 147 Layout...............................................................................................................41 26.0 FIT/LOT Procedure ....................................................................................................................42 27.0 Choke Manifold Schematic.........................................................................................................43 28.0 Casing Design Information.........................................................................................................44 29.0 6-3/4” Hole Section MASP..........................................................................................................45 30.0 Spider Plot....................................................................................................................................46 31.0 Surface Plat As-Staked (Slot 5)...................................................................................................47 Page 2 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 1.0 Well Summary Well PCU D-10 Pad & Old Well Designation Pretty Creek Diamond Pad– Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Sterling/Beluga Planned Well TD, MD / TVD 5752’ MD / 5564’ TVD PBTD, MD / TVD 5712’ MD AFE Drilling Days 18 Maximum Anticipated Pressure (Surface)2003 psi Maximum Anticipated Pressure (Downhole/Reservoir)2559 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 63.8’ Ground Elevation 45.3’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 2.0 Management of Change Information Page 4 Rev 0.0 April 7, 2025 PCU D-10 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 16”15.01”14.822”-84 X-56 Weld 2980 1410 - Surface 9-7/8”7-5/8”6.875”6.750”8.500”29.7 L-80 GBDC 6890 4790 683 Prod 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 GB ACME 10160 10540 168 ** Liner must overlap surface casing by at least 100’. 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update x Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 2. Spills: x Notify Drlg Manager 1. Sean Mclaughlin: C: 907-223-6784 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com,andcdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com,and cdinger@hilcorp.com Page 6 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 7.0 Drilling / Completion Summary PCU D-10 is an S-shaped directional grassroots development well to be drilled from Pretty Creek Diamond Pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Sterling and Beluga sands. The base plan is an S-shaped directional wellbore with a kickoff point at ~300’ MD. Maximum hole angle will be ~25 deg. and TD of the well will be 5752’ MD / 5564’ TVD, ending with 10 deg inclination left in the hole. Drilling operations are expected to commence approximately August 31st, 2025. The Hilcorp Rig # 147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 2399’ MD / 2264’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a cement evaluation log (CBL/VDL or temperature log for example)maybe runto determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Beluga Waste Cells.The contingency plan will be tohaul cuttingsto theKenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 147 to wellsite. 2. N/U diverter and test. 3. Drill 9-7/8” hole to surface TD. Run and cmt 7-5/8” surface casing. 4. Test casing to 3500 psi. Perform FIT to 13.4ppg. 5. ND diverter, N/U & test 11” x 5M BOP to 3000 psi 6. Drill 6-3/4” hole section to production TD. Perform wiper trip. 7. Run and cmt 3-1/2” production liner. 8. Displace well to 6% KCL completion fluid. 9. POOH and LDDP. 10. RIH and land 3-1/2” tieback string in liner top. 11. Test IA to 3000; Test tubing to 3000 psi 12. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: Surface hole: GR + Res MWD Production Hole: Triple Combo Page 8 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. 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 BOPs shall be tested at (2) week intervals during the drilling of PCU D-10. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/10 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, 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” x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC 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. Page 9 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only 6-3/4” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48 hours’ notice prior to testing BOPs. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email:bryan.mclellan@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 10 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install landing ring on conductor. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 147, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.8 Mix mud for 9-7/8” hole section. 9.9 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. Page 11 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 10.0 N/U 21-1/4” 2M Diverter 10.1 N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) 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). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x NOTE:Ensure closing time on diverter annular is in line with API RP 64: 2..1.1.Annular element ID 20” or smaller: Less than 30 seconds 2..1.2.Annular element ID greater than 20”: Less than 45 seconds 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. 10.4 Set wear bushing in wellhead. 10.5 Estimated diverter line orientation on Pretty Creek Pad (actual orientation may change from proposed): Page 12 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 11.0 Drill 9-7/8” Hole Section 11.1 P/U 9-7/8” directional drilling assy: 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 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 4-1/2” Workstring & HWDP will come from Hilcorp. 11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 9-7/8” hole section to 2399’ MD/ 2264’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale x Take MWD surveys every stand drilled (60’ intervals). 11.5 9-7/8” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite 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. Pason 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. System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 13 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-2399’8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.6 At TD, pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.7 TOH with the drilling assy, handle BHA as appropriate. Page 14 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker 7-5/8” casing running equipment. x Ensure 7-5/8” Casing x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. 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. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 7-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 15 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Page 16 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 17 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 13.0 Cement 7-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt 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 cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls spacer. Test surface cmt lines. 13.5 Pump remaining spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 75% lead open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 18 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hange elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. Lead Slurry Tail Slurry (500’) System Extended Conventional Density 12 lb/gal 15.8 lb/gal Yield 2.44 ft3/sk 1.16 ft3/sk Mixed Water 14.40 gal/sk 5.03 gal/sk Mixed Fluid 14.40 gal/sk 5.03 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A CalSeal Accelerator D-Air 5000 Anti Foam VersaSet Thixotropic Calcium Chloride Accelerator D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner BridgeMaker II Lost Circulation Page 19 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.6 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require running steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 13.13 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. 13.14 R/D cement equipment. Flush out wellhead with FW. 13.15 Back out and L/D landing joint. Flush out wellhead with FW. 13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.17 Lay down landing joint and pack-off running tool. Ensure to report the following on WellView: 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 Page 20 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 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 cdinger@hilcorp.com and nathan.sperry@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 21 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 14.0 BOP N/U and Test 14.1 ND Diverter line and diverter 14.2 N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test packoff to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Land out test plug (if not installed previously). x Test BOP to 250/3000 psi for 5/10 min. x Test VBR’s with 3-1/2” and 4-1/2” test joints x Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint x Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 9.0 ppg 6% KCL PHPA mud system. 14.7 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. Page 22 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 15.0 Drill 6-3/4” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH and conduct shallow hole test of MWD to confirm all LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 6-3/4” hole section mud program summary: Weighting material to be used for the hole section will be barite, salt, and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason 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. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: Interval Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT Production 9.0–9.5 40-53 15-25 15-25 8.5-9.5 11.0 Page 23 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 9.7 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. x Triple Combo LWD tools required 15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst.7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 14.0 ppg EMW. A 13.4 ppg FIT will result in a 20 bbl KTV. This assumes a 8.85ppg PP and a 9.4ppg MW (swabbed kick). 15.14 Drill 6-3/4” hole section to 5752’ MD / 5564’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 200 - 300 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. x Trip back to the 7-5/8” shoe about ½ way through the hole section x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Verify lost circulation potential zones with town geologist or drilling engineer. If there is lost circulation potential through specific zones, SLOW ROP, add Black products, and background LCM to the mud. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. 15.15 At TD, pump sweeps, CBU, flowcheck, and pull a wiper trip back to the 7-5/8” shoe. TIH. 15.16 CBU. Flowcheck. TOH with the drilling assy, LDDP and BHA. Page 24 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 16.0 Run 3-1/2” Production Liner 16.1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” HYD 563 x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints 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. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 3-1/2” production liner x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint to the 7-5/8” shoe. Leave the centralizers free floating. 16.5. Continue running 3-1/2” production liner Page 25 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure Page 26 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 16.6. Run in hole w/ 3-1/2” liner to the 7-5/8” casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. PU 3-1/2” X 7-5/8” liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 16.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.15. Stage pump rates up slowly to circulating rate.Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 27 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 17.0 Cement 3-1/2” Production Liner 17.1. Hold a pre-job safety meeting over the upcoming cmt 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 cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 17.3. Pump 5 bbls spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Page 28 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure Estimated Total Cement Volume: Page 29 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure Cement Slurry Design: Lead Slurry Tail Slurry (500’) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss HR-5 Retarder HR-5 Retarder D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner SA-1015 Suspension Agent BridgeMaker II Lost Circulation 17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 17.9. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to up as required by service company procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).Hold pressure for 3-5 minutes. 17.11. Slack off total liner weight plus 30k to confirm hanger is set. 17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls. 17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. Page 30 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17.17. Pressure up drill pipe to 500 psi and pick up to remove the bushing from the liner. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 17.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. 17.21. WOC minimum of 500 psi compressive strength. Test casing to 3000 psi and chart for 30 minutes. Ensure to report the following on WellView: 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 cdinger@hilcorp.com and nathan.sperry@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 31 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 18.0 3-1/2” Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy per service company rep and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per procedure. 18.3. POOH, and LDDP and polish mill. 18.4. If not completed, test 3-1/2” casing to 3000 psi and chart for 30 minutes Page 32 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 19.0 3-1/2” Tieback Run, ND/NU, RDMO 19.1 PU 3-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 EUE. Ensure any jewelry is picked up per tally. x Install chemical injection mandrel at ~1,500’ MD. 19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 19.3 Circulate inhibited completion fluid. 19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance of seals from no-go. 19.5 Install packoff and test hanger void. 19.6 Test 3-1/2” liner and tieback to 3000 psi and chart for 30 minutes. 19.7 Test 7-5/8” x 3-1/2” annulus to 3000 psi and chart for 30 minutes. 19.8 Install BPV in wellhead 19.9 N/D BOPE 19.10 N/U dry-hole tree and test 19.11 RDMO Hilcorp Rig #147 Page 33 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 20.0 CBL and Nitrogen Operation (Post Rig Work) Pre-Sundry work: 1. Review all approved COAs 2. MIRU E-line and pressure control equipment 3. Log well with CBL tool in 3-1/2” liner (send results to AOGCC to review) 4. RDMO E-line Coiled Tubing Procedure 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3500psi high a. Provide AOGCC 48hr notice for BOP test 3. MU cleanout BHA 4. RIH to PBTD, cleanout well as necessary (based on CBL depth) and swap well over to 8.4 ppg water a. If well is left with 9.4 ppg mud or less, mud may be circulated out with Nitrogen, based on Operations Engineer direction without swapping to water. 5. Once well is clean with 8.4 ppg water a. Reverse circulate water 6. RDMO CT 7. Leave N2 pressure on well when coil is rigged down Submit Completion sundry for perforating well. Attachments to be included 1. Coil Tubing BOP Diagram 2. Standard Nitrogen Operations Page 34 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure Page 35 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure Page 36 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 21.0 Diverter Schematic Page 37 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 22.0 BOP Schematic Page 38 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 23.0 Wellhead Schematic Page 39 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 24.0 Anticipated Drilling Hazards 9-7/8” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 – 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help ensure good cement to surface after running the casing, condition the mud to a YP of 25 – 30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 40 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022, ensure all LCM inventory is fully stocked before drilling out surface casing. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 41 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 25.0 Hilcorp Rig 147 Layout Page 42 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 26.0 FIT/LOT 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. Page 43 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 27.0 Choke Manifold Schematic Page 44 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 28.0 Casing Design Information Page 45 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 29.0 6-3/4” Hole Section MASP Page 46 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 30.0 Spider Plot Page 47 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure 31.0 Surface Plat As-Staked (Slot 5) Page 48 Rev 0.0 April 7, 2025 PCU D-10 Drilling Procedure ! "#$$ %& '( ) * 0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625True Vertical Depth (750 usft/in)-750 -375 0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 Vertical Section at 291.00° (750 usft/in) 7-5/8" x 9-7/8" 3-1/2" x 6-3/4" 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 40 0 0 4 5 0 0 5 0 0 0 5 500 5752 PCU D-10 wp04 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 1133.33' MD, 1107.14' TVD Start Dir 3º/100' : 2083.33' MD, 1968.13'TVD End Dir : 2583.33' MD, 2443.63' TVD Total Depth : 5752' MD, 5564.16' TVD STERLING X2 STERLING B3 STERLING C1 STERLING C5 BELUGA D5 Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: PCU D-10 45.30 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2660306.70 345617.65 61° 16' 42.7326 N 150° 52' 38.7761 W SURVEY PROGRAM Date: 2025-07-07T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.50 2398.87 PCU D-10 wp04 (PCU D-10) 3_MWD+AX+Sag 2398.87 5752.00 PCU D-10 wp04 (PCU D-10) 3_MWD+AX+Sag REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well PCU D-10, True North Vertical (TVD) Reference:RKB As-Staked @ 63.80usft (HEC 147) Measured Depth Reference:RKB As-Staked @ 63.80usft (HEC 147) Calculation Method: Minimum Curvature Project:Beluga River North Site:Diamond Pad Well:PCU D-10 Wellbore:PCU D-10 Design:PCU D-10 wp04 CASING DETAILS TVD TVDSS MD Size Name 2263.80 2200.00 2398.87 7-5/8 7-5/8" x 9-7/8" 5564.16 5500.36 5752.00 3-1/2 3-1/2" x 6-3/4" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.50 0.00 0.00 18.50 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 3 1133.33 25.00 291.00 1107.14 64.13 -167.05 3.00 291.00 178.94 End Dir : 1133.33' MD, 1107.14' TVD 4 2083.33 25.00 291.00 1968.13 208.01 -541.87 0.00 0.00 580.43 Start Dir 3º/100' : 2083.33' MD, 1968.13'TVD 5 2583.33 10.00 291.00 2443.63 261.73 -681.84 3.00 180.00 730.35 End Dir : 2583.33' MD, 2443.63' TVD 6 5752.00 10.00 291.00 5564.16 458.92 -1195.53 0.00 0.00 1280.58 Total Depth : 5752' MD, 5564.16' TVD FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3156.80 3093.00 3307.50 STERLING X2 3601.80 3538.00 3759.37 STERLING B3 3620.80 3557.00 3778.66 STERLING C1 3719.80 3656.00 3879.19 STERLING C5 3810.80 3747.00 3971.59 BELUGA D5 -150-75075150225300375450525600South(-)/North(+) (150 usft/in)-1275 -1200 -1125 -1050 -975 -900 -825 -750 -675 -600 -525 -450 -375 -300 -225 -150 -75 0 75West(-)/East(+) (150 usft/in)7-5/8" x 9-7/8"3-1/2" x 6-3/4"5007501000125015001750200022502500275030003250350037504000425045004750500052505564PCU D-10 wp04Start Dir 3º/100' : 300' MD, 300'TVDEnd Dir : 1133.33' MD, 1107.14' TVDStart Dir 3º/100' : 2083.33' MD, 1968.13'TVDEnd Dir : 2583.33' MD, 2443.63' TVDTotal Depth : 5752' MD, 5564.16' TVDCASING DETAILSTVDTVDSS MDSize Name2263.80 2200.00 2398.87 7-5/8 7-5/8" x 9-7/8"5564.16 5500.36 5752.00 3-1/2 3-1/2" x 6-3/4"Project: Beluga River NorthSite: Diamond PadWell: PCU D-10Wellbore: PCU D-10Plan: PCU D-10 wp04WELL DETAILS: PCU D-1045.30+N/-S +E/-W Northing Easting Latittude Longitude0.00 0.002660306.70345617.6561° 16' 42.7326 N 150° 52' 38.7761 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well PCU D-10, True NorthVertical (TVD) Reference: RKB As-Staked @ 63.80usft (HEC 147)Measured Depth Reference:RKB As-Staked @ 63.80usft (HEC 147)Calculation Method:Minimum Curvature +! * $ ! ,! -. ,! / /0 !" !" 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eparation Factor0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:PCU D-10 NAD 1927 (NADCON CONUS)Alaska Zone 0445.30+N/-S +E/-W Northing EastingLatittudeLongitude0.000.002660306.70 345617.6561° 16' 42.7326 N150° 52' 38.7761 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well PCU D-10, True NorthVertical (TVD) Reference: RKB As-Staked @ 63.80usft (HEC 147)Measured Depth Reference:RKB As-Staked @ 63.80usft (HEC 147)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-07-07T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.50 2398.87 PCU D-10 wp04 (PCU D-10) 3_MWD+AX+Sag2398.87 5752.00 PCU D-10 wp04 (PCU D-10) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)PCU D-11 wp04GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.50 To 5752.00Project: Beluga River NorthSite: Diamond PadWell: PCU D-10Wellbore: PCU D-10Plan: PCU D-10 wp04CASING DETAILSTVD TVDSS MD Size Name2263.80 2200.00 2398.87 7-5/8 7-5/8" x 9-7/8"5564.16 5500.36 5752.00 3-1/2 3-1/2" x 6-3/4" 1 Dewhurst, Andrew D (OGC) From:Dewhurst, Andrew D (OGC) Sent:Tuesday, 19 August, 2025 08:26 To:Nathan Sperry; Cody Dinger Cc:McLellan, Bryan J (OGC); Guhl, Meredith D (OGC) Subject:RE: [EXTERNAL] PCU D-10 PTD (225-082): Question Nate, Understood. Our typical cuttings sampling requirements state maximum intervals of 10’ across the targeted interval and 30’ everywhere else. The targeted interval in this well is a much larger stratigraphic zone than typical, so let me know if the sampling interval should be increased. Also, Meredith can answer any questions about sample data submissions if you have any. Andy From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Tuesday, 19 August, 2025 07:23 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Cody Dinger <cdinger@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: RE: [EXTERNAL] PCU D-10 PTD (225-082): Question Andy, Yes, we are planning to run mud logging. Thank you for clarifying the conditions that would allow you to waive the requirement, I appreciate it. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Monday, August 18, 2025 5:29 PM To: Nathan Sperry <nathan.sperry@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: [EXTERNAL] PCU D-10 PTD (225-082): Question Nathan, 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. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 I’m completing my review of the Pretty Creek Unit D-10 PTD and have a question: x Are you planning to run mud logging? Mud logs and cutting samples are required under 20 AAC 25.071, but the requirement to collect mud logs in particular can be waived if they will not signiƱcantly add to the geologic knowledge of the area. In practice, we only typically require the Ʊrst well on a new pad (which this appears to be) to collect a mud log. It would also help to know what the distance is to the nearest well that has a mud log. Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME:______________________________________ PTD:_____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD:__________________________POOL:____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in nogreater 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. PCU D-10 225-082 PRETTY CREEK UNDEFINED GAS Sampling interval can be increased for high ROP. -A.Dewhurst 19AUG25 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:PRETTY CK UNIT D-10Initial Class/TypeDEV / PENDGeoArea820Unit11620On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250820Field & Pool:PRETTY CREEK, UNDEFINED GAS - 580500NA1 Permit fee attachedYes ADL0058810 and ADL00630482 Lease number appropriateYes3 Unique well name and numberYes PRETTY CREEK, UNDEFINED GAS - 580500 - governed by Statewide Regs4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2003 psi, BOP rated to 5000 psi (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not expected35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipated pore pressure gradient is 8.85 PPG EMW36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate8/18/2025ApprBJMDate8/19/2025ApprADDDate8/18/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 8/19/2025