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HomeMy WebLinkAbout225-113David 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: 01/30/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: SRU 233-10 PTD: 225-113 API: 50-133-20740-00-00 FINAL GAS SAMPLING (12/12/2025 to 12/25/2025) x FINAL WEL REPORT x DAILY REPORTS x DIGITAL DATA (LAS) x LOG PRINTS (2” + 5”, MD and TVD COLOR PRINTS) Drilling Dynamics Gas Ratio LWD Combo SFTP Transfer - Main Folder Contents: Please include current contact information if different from above. 225-113 T41298 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.30 11:03:41 -09'00' 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: 01/30/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: SRU 233-10 PTD: 225-113 API: 50-133-20740-00-00 FINAL LWD FORMATION EVALUATION LOGS (12/13/2025 to 12/23/2025) DGR, ADR, LithoStar Density and Porosity (2” & 5” MD/TVD Color Logs) Pressure While Drill (PWD) Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. 225-113 T41298 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.30 11:03:17 -09'00' 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: Beluga Gas 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 8,541' 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: Ryan LeMay, Operations Engineer Contact Email:ryan.lemay@hilcorp.com Contact Phone: 661-487-0871 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 Other: Initial Completion, N2 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: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AKA 028406 / AKA 028405 225-113 50-133-20740-00-00 Hilcorp Alaska, LLC Proposed Pools: See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 L-80 TVD Burst 3,671' 10,160psi 3,129' 120' MD See Attached Schematic 120' 3,890'7-5/8" 2,980psi 6,890psi 120' 3,890' January 11, 2026 Tieback 3-1/2" 8,540' Perforation Depth MD (ft): Swanson River Unit (SRU) 233-10CO 716A Same 7,349'3-1/2" 2,746 psi Swanson River Sterling/Beluga Gas, Tyonek Gas Size 4,866' N/A Length LTP; N/A 3,638' MD / 2,891' TVD; N/A, N/A 7,350' 8,476' 7,292' 16" No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 326-008 By Grace Christianson at 4:28 pm, Jan 07, 2026 DSR-1/12/26TS 1/9/25 10-407 CBL received shows apparent TOC at 6876' MD. The proposed perfs above this depth are not authorized with this sundry. BJM 1/12/26 01/12/26 Well Prognosis Well Name: SRU 233-10 API Number: 50-133-20740-00-00 Current Status: New Drill Well Permit to Drill Number: 225-113 First Call Engineer: Ryan LeMay (661) 487-0871 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP: 3469 psi @ 7226’ TVD (Based on 0.48 psi/ft gradient) Max. Potential Surface Pressure: 2746 psi @ 7226’ TVD (0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.664 psi/ft using 12.77 ppg EMW FIT @ 7-5/8” surface shoe Shallowest Potential Perf TVD: MPSP / (0.664-0.1) = 2746 psi / 0.564 = 4869’ TVD Applicable Pool(s) / PA(s): Tyonek: 6543’ MD / 5570’ TVD Beluga: 5885’ MD / 4983’ TVD Well Status: New Drill Well Initial Completion Brief Well Summary SRU 233-10 is a directional grassroots development well drilled in December 2025 targeting the Tyonek and Beluga Sands. The objective of this sundry is to perforate and flow the new drill well. Wellbore Conditions: - T & IA PT to 3000 psi (30 min) on 12/27/25 - Min ID- 2.993” 3-1/2” packer ID - Liner is full of ~10.0 ppg 6% KCl mud - Tubing and IA are displaced to 8.4 ppg CIW 6% KCl Work to be completed pre sundry: Covered in Section 20.0 of approved Drilling Program Eline Run CBL o Send results to AOGCC + BLM to review prior to perforating CTU cleanout / N2 blowdown Well Prognosis Procedure: 1. MIRU E-line unit. PT lubricator 250 psi low / 3500 psi high 2. Perforate the following intervals Below are proposed targeted sands in order of testing (bottom/up), but additional sand may be added depending on results of these perfs, between the proposed top and bottom perfs Well Sand MD top MD Bottom TVD top TVD bottom Interval SRU 233-10 TY 54-1 +6,615’ +6,638’ +5,635’ +5,655’ +23’ SRU 233-10 TY 54-4 +6,686’ +6,709’ +5,699’ +5,719’ +23’ SRU 233-10 TY 54-4 +6,738’ +6,743’ +5,744’ +5,749’ +5’ SRU 233-10 TY 54-4 +6,751’ +6,768’ +5,756’ +5,771’ +17’ SRU 233-10 TY 55-5 +6,840’ +6,859’ +5,836’ +5,853’ +19’ SRU 233-10 TY 55-7 +6,937’ +6,946’ +5,921’ +5,930’ +9’ SRU 233-10 TY 55-7 +6,955’ +6,963’ +5,938’ +5,945’ +8’ SRU 233-10 TY 55-7 +6,974’ +6,979’ +5,954’ +5,959’ +5’ SRU 233-10 TY 55-7 +7,000’ +7,013’ +5,978’ +5,989’ +13’ SRU 233-10 TY 56-9 +7,048’ +7,056’ +6,020’ +6,028’ +8’ SRU 233-10 TY 56-9 +7,068’ +7,075’ +6,039’ +6,044’ +7’ SRU 233-10 TY 56-9 +7,086’ +7,092’ +6,054’ +6,060’ +6’ SRU 233-10 TY 57-8 +7,152’ +7,166’ +6,114’ +6,126’ +14’ SRU 233-10 TY 57-8 +7,170’ +7,181’ +6,130’ +6,140’ +11’ SRU 233-10 TY 61-0 +7,225’ +7,233’ +6,178’ +6,186’ +8’ SRU 233-10 TY 61-0 +7,246’ +7,280’ +6,198’ +6,228’ +34’ SRU 233-10 TY 61-0 +7,280’ +7,310’ +6,228’ +6,254’ +30’ SRU 233-10 TY 61-0 +7,333’ +7,363’ +6,275’ +6,302’ +30’ SRU 233-10 TY 61-8 +7,424’ +7,434’ +6,356’ +6,365’ +10’ SRU 233-10 TY 61-8 +7,444’ +7,450’ +6,374’ +6,379’ +6’ SRU 233-10 TY 62-3 +7,471’ +7,481’ +6,398’ +6,406’ +10’ SRU 233-10 TY 62-3 +7,550’ +7,570’ +6,468’ +6,486’ +20’ SRU 233-10 TY 62-3 +7,570’ +7,580’ +6,486’ +6,495’ +10’ SRU 233-10 TY 62-3 +7,612’ +7,622’ +6,523’ +6,532’ +10’ SRU 233-10 TY 62-5 +7,647’ +7,661’ +6,554’ +6,567’ +14’ SRU 233-10 TY 64-5 +7,919’ +7,925’ +6,796’ +6,801’ +6’ SRU 233-10 TY 67-0 +8,178’ +8,184’ +7,027’ +7,032’ +6’ SRU 233-10 TY 68-0 +8,289’ +8,303’ +7,126’ +7,139’ +14’ SRU 233-10 TY 68-3 +8,355’ +8,365’ +7,185’ +7,194’ +10’ SRU 233-10 TY 68-3 +8,387’ +8,401’ +7,213’ +7,226’ +14’ CBL shows apparent TOC at 6876' MD. Proposed perfs above this depth are not approved with this sundry. -bjm Well Prognosis a. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation b. Use Gamma/CCL to correlate c. Record tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min intervals post perf shot (if using switched guns, wait 10 min between shots) d. Pending well production, all perf intervals may not be completed e. If any proposed zone produces sand and / or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Note: A CIBP may be used instead of WRP if it is determined that no cement is needed for operational purposes. 35ft will not be placed on each plug as these zones are close together. If possible, the CIBP will be set 50’ above of the top of the last perforated sand unless zones are too close together in which case the plug will be set within 50’. f. If necessary, use high pressure pad gas or N2 to pressure up well during perforating or to depress water prior to setting a plug above perforations. 3. RDMO. 4. Turn well over to production & flow test well. 5. 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. Contingency Procedure: Coiled Tubing Cleanout 1. If throughout the job any proposed zones produce sand and / or water that cannot be depressed and pushed away with nitrogen, a coil tubing unit may be rigged up to clean out fill or fluid blown down as necessary. a. MIRU Fox CTU, PT BOPE to 250 psi low / 3500 psi high i. Provide AOGCC 24hrs notice of BOP test. b. Cleanout wellbore fill and / or blowdown well with nitrogen as necessary. Attachments: Current Wellbore Schematic Proposed Wellbore Schematic Coil Tubing BOP Schematic Standard Well Procedure – N2 Operations Updated by RPL 12-30-2025 CURRENT SCHEMATIC Swanson River Unit SRU 233-10 PTD: 225-113 API: 50-133-20740-00-00 PBTD = 8,476’ MD / TVD = 7,292’ TD = 8,541’ MD / TVD = 7,350’ RKB to GL = 19.23’ NOTES 10’ Short jt w/ RA tags 4,994’, 5,986’, 7,008’ 10’ Short joints 4,515’, 5,506’, 6,497’, 7,488’, 8,029’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120’ 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875”Surf 3,890’ 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.992”3,674’8,540’ 3-1/2"Prod Tieback 9.2 L-80 EUE 2.992”Surf 3,671’ 1 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth Item 1 20’Cactus CTF-ONE-CTL 11” x 4-1/2” Hanger w/ 4” Type H BPV profile 2 1,507’3-1/2” Chemical Injection Mandrel (2.867” ID) w/ 3/8” control line 3 3,638’YJ Scout Ranger Liner Hanger & Scout Pkr 5.75” ID on Upper Polish 4 3,671’Bullet Seal Assembly spaced 1.4’ off no-go OPEN HOLE / CEMENT DETAIL 7-5/8" Cement at surface. 60 bbls 10.5 ppg spacer + 237 bbls 12 ppg lead cement + 38 bbls 15.8 ppg tail cement pumped. Full returns throughout cement job and got 60 bbls spacer + 154 bbls cement returns back to surface (12-17-2025). 3-1/2” 30 bbls 10.5 ppg spacer + 210 bbls 12 ppg lead cement + 24 bbls 15.3 ppg tail cement pumped. Lost returns 185 bbls into pumping lead cement (12-25-25). TOC via CBL = xxxx’ (date) 6-3/4” hole 2 3/4 Updated by RPL 12-30-2025 PROPOSED SCHEMATIC Swanson River Unit SRU 233-10 PTD: 225-113 API: 50-133-20740-00-00 PBTD = 8,476’ MD / TVD = 7,292’ TD = 8,541’ MD / TVD = 7,350’ RKB to GL = 19.23’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120’ 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875”Surf 3,890’ 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.992”3,674’8,540’ 3-1/2"Prod Tieback 9.2 L-80 EUE 2.992”Surf 3,671’ 1 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth Item 1 20’Cactus CTF-ONE-CTL 11” x 4-1/2” Hanger w/ 4” Type H BPV profile 2 1,507’3-1/2” Chemical Injection Mandrel (2.867” ID) w/ 3/8” control line 3 3,638’YJ Scout Ranger Liner Hanger & Scout Pkr 5.75” ID on Upper Polish 4 3,671’Bullet Seal Assembly spaced 1.4’ off no-go OPEN HOLE / CEMENT DETAIL 7-5/8" Cement at surface. 60 bbls 10.5 ppg spacer + 237 bbls 12 ppg lead cement + 38 bbls 15.8 ppg tail cement pumped. Full returns throughout cement job and got 60 bbls spacer + 154 bbls cement returns back to surface (12-17-2025). 3-1/2” 30 bbls 10.5 ppg spacer + 210 bbls 12 ppg lead cement + 24 bbls 15.3 ppg tail cement pumped. Lost returns 185 bbls into pumping lead cement (12-25-25). TOC via CBL = xxxx’ (date) 6-3/4” hole 2 3/4 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status TY 54-1 +6,615’+6,638’+5,635’+5,655’+23’TBD Proposed TY 54-4 +6,686’+6,709’+5,699’+5,719’+23’TBD Proposed TY 54-4 +6,738’+6,743’+5,744’+5,749’+5’TBD Proposed TY 54-4 +6,751’+6,768’+5,756’+5,771’+17’TBD Proposed TY 55-5 +6,840’+6,859’+5,836’+5,853’+19’TBD Proposed TY 55-7 +6,937’+6,946’+5,921’+5,930’+9’TBD Proposed TY 55-7 +6,955’+6,963’+5,938’+5,945’+8’TBD Proposed TY 55-7 +6,974’+6,979’+5,954’+5,959’+5’TBD Proposed TY 55-7 +7,000’+7,013’+5,978’+5,989’+13’TBD Proposed TY 56-9 +7,048’+7,056’+6,020’+6,028’+8’TBD Proposed TY 56-9 +7,068’+7,075’+6,039’+6,044’+7’TBD Proposed TY 56-9 +7,086’+7,092’+6,054’+6,060’+6’TBD Proposed TY 57-8 +7,152’+7,166’+6,114’+6,126’+14’TBD Proposed TY 57-8 +7,170’+7,181’+6,130’+6,140’+11’TBD Proposed TY 61-0 +7,225’+7,233’+6,178’+6,186’+8’TBD Proposed TY 61-0 +7,246’+7,280’+6,198’+6,228’+34’TBD Proposed TY 61-0 +7,280’+7,310’+6,228’+6,254’+30’TBD Proposed TY 61-0 +7,333’+7,363’+6,275’+6,302’+30’TBD Proposed TY 61-8 +7,424’+7,434’+6,356’+6,365’+10’TBD Proposed TY 61-8 +7,444’+7,450’+6,374’+6,379’+6’TBD Proposed TY 62-3 +7,471’+7,481’+6,398’+6,406’+10’TBD Proposed TY 62-3 +7,550’+7,570’+6,468’+6,486’+20’TBD Proposed TY 62-3 +7,570’+7,580’+6,486’+6,495’+10’TBD Proposed TY 62-3 +7,612’+7,622’+6,523’+6,532’+10’TBD Proposed TY 62-5 +7,647’+7,661’+6,554’+6,567’+14’TBD Proposed TY 64-5 +7,919’+7,925’+6,796’+6,801’+6’TBD Proposed TY 67-0 +8,178’+8,184’+7,027’+7,032’+6’TBD Proposed TY 68-0 +8,289’+8,303’+7,126’+7,139’+14’TBD Proposed TY 68-3 +8,355’+8,365’+7,185’+7,194’+10’TBD Proposed TY 68-3 +8,387’+8,401’+7,213’+7,226’+14’TBD Proposed NOTES 10’ Short jt w/ RA tags 4,994’, 5,986’, 7,008’ 10’ Short joints 4,515’, 5,506’, 6,497’, 7,488’, 8,029’ STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 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:Ryan Lemay Subject:RE: Program Change Request / SRU 233-10 / PTD: 225-113 Date:Friday, December 19, 2025 10:26:00 AM Approved. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Lemay <ryan.lemay@hilcorp.com> Sent: Friday, December 19, 2025 9:58 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: Program Change Request / SRU 233-10 / PTD: 225-113 Bryan, Thank you for taking my call. As discussed, Hilcorp is seeking a program change approval to install a chemical injection mandrel in the 3.5” upper completion at + 1500’ with 3/8” control line on current new drill SRU 233-10 in Swanson River. Thank you and let me know if you have any additional questions. Ryan LeMay Operations Engineer Swanson River / Beaver Creek Cell: (661) 487-0871 E-mail: Ryan.lemay@hilcorp.com 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. 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): N/A Casing Collapse Structural Conductor Surface Intermediate Production 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: Nathan Sperry Contact Email:nathan.sperry@hilcorp.com Contact Phone:907-777-8450 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 Swanson River Unit Sterling/Beluga & Beluga & Tyonek Gas Pool Subsequent Form Required: 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: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Drilling Manager STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AKA 028406 / AKA 028405 225-113 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-133-20740-00-00 Hilcorp Alaska, LLC SRU 233-10 Length Size Proposed Pools: N/A TVD Burst N/A MD 120'120'16"120' Perforation Depth MD (ft): N/A N/A N/A Other: 12/7/2025 N/A N/A N/A m n P s 2 6 5 6 tc N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.12.02 09:53:47 - 09'00' Sean McLaughlin (4311) 325-733 By Grace Christianson at 10:24 am, Dec 02, 2025 BJM 12/2/25 Variance to 20 AAC 25.030(e) approved to test below 50% of P110 grade 7-5/8" casing. Test will be to 3500 psi which is 50% of standard design L80 casing. SFD 12/2/2025 10-407 DSR-12/3/25 12/04/25 Well Prognosis Well: SRU 233-10 Date: 12/2/2025 Well Name:SRU 233-10 API Number:50-133-20740-00-00 Current Status:Upcoming Drill Well Estimated Start Date:12/7/2025 Rig:169 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:225-113 First Call Engineer:Nathan Sperry 907-777-8450 Second Call Engineer Sean Mclaughlin 907-223-6784 AFE Number: Change to Approved Program Summary: Hilcorp permitted SRU 233-10 to run 7-5/8” L-80 intermediate casing. Hilcorp has consumed our L-80 inventory and now have 7-5/8” 29.7# P-110 that we’re running. Hilcorp is requesting that we keep the PT to 3500 psi (~1/2 the burst rating of L-80) since the casing grade change is being made due to inventory availability and not required by any specific well conditions or operations.Please see variance request in attachment 4. Attachments: 1.Updated MOC 2.Updated Tubular Program 3.Updated Planned Wellbore Schematic 4.Updated Mandatory Regulatory Compliance and Notifications 5.Updated Page 25 of the Drilling Program (Casing Test) 6.Updated Casing Spec Sheet and Casing Design Information Page 3 Version 2.0 December 1, 2025 SRU 233-10 Drilling Procedure 2.0 Management of Change Information Page 4 Version 2.0 December 1, 2025 SRU 233-10 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 P-110 GBCD 9470 5340 940 Prod 6-3/4” 3-1/2” 2.992” 2.867” 4.250” 9.2 L-80 Hydril 563 or GB Acme 10160 10540 207 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 6 Version 2.0 December 1, 2025 SRU 233-10 Drilling Procedure 6.0 Planned Wellbore Schematic Page 8 Version 2.0 December 1, 2025 SRU 233-10 Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with all relevant AOGCC regulations and all BLM regulations pertaining to Onshore Order No.1. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. BOPs shall be tested at (2) week intervals during the drilling of SRU 233-10. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs and BLM 48 hrs notice prior to testing. 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. 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. All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” Ensure AOGCC and BLM approved drilling permits are posted on the rig floor and in Co Man office. Review all conditions of approval of the BLM APD and 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. BLM Regulation Variance Requests: Onshore Oil and Gas Order No. 1, Section III. D. 3. C. o Hilcorp requests approval to install a 2-1/16” 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. AOGCC Variance Request: Hilcorp requests a variance from 20 AAC 25.030(e) to test the 7-5/8” casing to less than 50% of the P-110 MIYP. P-110 casing is being run due to inventory constraints and is not needed for the design requirements. Page 25 Version 2.0 December 1, 2025 SRU 233-10 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 – 10.0 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. R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. 50% of burst is 4735 psi but P-110 casing is being run due to inventory constraints and is not needed for the design requirements. 15.10 Drill out shoe track and 20’ of new formation. CBU and condition mud for FIT. 15.11 Conduct FIT to 12.5 ppg EMW. A 12.2# ppg FIT will result in a 20 bbl KTV assuming an 8.27ppg PP and a 9.2ppg MW (swabbed kick). 15.12 Drill 6-3/4” hole section to planned TD Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. Keep swab and surge pressures low when tripping. Make wiper trips every 1000’ to 1500’ unless hole conditions dictate otherwise. Trip back to the 7-5/8” shoe about ½ way through the hole section Ensure shale shakers are functioning properly. Check for holes in screens on connections. Lost circulation potential when drilling through Sterling A, Lower Beluga, and the Tyonek 61-8 and 68-0. Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if necessary. SRU 34-10 has a 0.993 clearance factor at 8648’ MD. SRU 34-10 has been plugged and abandoned. There is no HSE risk associated with a collision. The potential consequence is financial. 15.13 At TD, pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 15.14 TOH with the drilling assy, laying down drill pipe. LD density and porosity tools. Page 17 Version 2.0 December 1, 2025 SRU 233-10 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 47 Version 2.0 December 1, 2025 SRU 233-10 Drilling Procedure 28.0 Casing Design Information Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Swanson River Unit, Field, Sterling/Belugas Gas Pool, SRU 233-10 Hilcorp Alaska, LLC Permit to Drill Number: 225-113 Surface Location: 598' FNL, 2074' FWL, Sec 15, T8N, R9W, SM, AK Bottomhole Location: 343' FSL, 2476' FEL, Sec 10, T8N, 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. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 12th day of November 2025. 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): Swanson River Unit MD: 8,648' TVD: 7,436' 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): 335.5' 15. Distance to Nearest Well Open Surface: x-349944 y- 2481648 Zone-4 317.5' to Same Pool: 1320' to SRU 224-10 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 55 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# P-110 GBCD 3,863' Surface Surface 3,863' 3,092' 6-3/4" 3-1/2" 9.2# L-80 Hyd 563 4,985' 3,663' 2,903' 8,648' 7,436' Tieback 3-1/2" 9.2# L-80 EUE 3,650' Surface Surface 3,663' 2,903' 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 SRU 233-10 Sterling/Beluga Gas Pool Beluga Gas Pool Tyonek Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. 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 - 1126 ft3 / T - 131 ft3 2454 845' FSL, 1968' FWL, Sec 10, T8N, R9W, SM, AK 343' FSL, 2476' FEL, Sec 10, T8N, R9W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 598' FNL, 2074' FWL, Sec 15, T8N, R9W, SM, AK AKA 028406 / AKA 028405 18. Casing Program: Top - Setting Depth - BottomSpecifications 3197 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) Driven L - 1328 ft3 / T - 208 ft3 Effect. Depth MD (ft): Effect. Depth TVD (ft): LengthCasing Size Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate 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): 12/15/2025 1517' to nearest unit boundary Nathan Sperry nathan.sperry@hilcorp.com 907-777-8450 Tieback Assy. 4944 Cement Volume MD s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 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 11:08 am, Oct 22, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.10.21 16:51:53 - 08'00' Sean McLaughlin (4311) 225-113 BOP test to 3000 psi. Annular test to 2500 psi.. Submit FIT/LOT results within 48 hrs of performing tests DSR-10/30/25BJM 11/11/25 SFD 10/30/2025 50-133-20740-00-00 11/12/25 11/12/25 SRU 233-10 Drilling Program Swanson River Unit October 15, 2025 SRU 233-10 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........................................................................................................11 10.0 N/U 21-1/4” 2M Diverter.............................................................................................................12 11.0 Drill 9-7/8” Hole Section..............................................................................................................14 12.0 Run 7-5/8” Surface Casing..........................................................................................................16 13.0 Cement 7-5/8” Surface Casing....................................................................................................18 14.0 BOP N/U and Test........................................................................................................................22 15.0 Drill 6-3/4” Hole Section..............................................................................................................23 16.0 Run 3-1/2” Production Liner......................................................................................................25 17.0 Cement 3-1/2” Production Liner................................................................................................28 18.0 3-1/2” Liner Tieback Polish Run................................................................................................33 19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................34 20.0 CBL and Nitrogen Operation (Post Rig Work)........................................................................35 21.0 Diverter Schematic ......................................................................................................................38 22.0 BOP Schematic.............................................................................................................................39 23.0 Wellhead Schematic.....................................................................................................................40 24.0 Anticipated Drilling Hazards......................................................................................................41 25.0 Hilcorp Rig 169 Layout...............................................................................................................43 26.0 FIT/LOT Procedure ....................................................................................................................44 27.0 Choke Manifold Schematic.........................................................................................................45 28.0 Casing Design Information.........................................................................................................46 29.0 6-3/4” Hole Section MASP..........................................................................................................47 30.0 Spider Plot w/ 660’ Radius for SSSV.........................................................................................48 31.0 Surface Plat (As-Staked NAD27 & NAD83)..............................................................................49 Page 2 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 1.0 Well Summary Well SRU 233-10 Pad & Old Well Designation SRU pad 21-15 – Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s) Sterling/Beluga/Tyonek Planned Well TD, MD / TVD 8648’ MD / 7436’ TVD PBTD, MD / TVD 8578’ MD / 7391’ TVD AFE Drilling Days 18 AFE Completion Days 3 Maximum Anticipated Pressure (Surface) 2454 psi Maximum Anticipated Pressure (Downhole/Reservoir) 3197 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 336.2’ Ground Elevation 317.7’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 2.0 Management of Change Information Supreseded Page 3 Version 1.0 November 11, 2025 SRU 233-10 Drilling Procedure 2.0 Management of Change Information Page 4 Version 0.0 October 15, 2025 SRU 233-10 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 GBCD 6890 4790 683 Prod 6-3/4” 3-1/2” 2.992” 2.867” 4.250”9.2 L-80 Hydril 563 or GB Acme 10160 10540 207 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 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. Report covers operations from 6am to 6am Ensure time entry adds up to 24 hours total. Capture any out-of-scope work as NPT. 5.2 Afternoon Updates Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting Notify EHS field coordinator. 1. Know who your EHS field coordinator is at all times. a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 2. Spills: Notify Drlg Manager 1. Sean Mclaughlin: C: 907-223-6784 Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com, and cdinger@hilcorp.com 5.6 Casing and Cmt report Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com, and cdinger@hilcorp.com Page 6 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 7.0 Drilling / Completion Summary SRU 233-10 is an S-shaped directional grassroots development well to be drilled from Swanson River 21-15 Pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Sterling, Beluga, and Tyonek sands. The base plan is an S-shaped directional wellbore with a kickoff point at ~300’ MD. Maximum hole angle will be ~55 deg. and TD of the well will be 8648’ TMD/ 7436’ TVD, ending with 10 deg inclination left in the hole. Vertical separation will be 1220 ft. Drilling operations are expected to commence approximatelyDecember15th,2025.TheHilcorpRig #169will be used to drill the wellbore and run and cement casing. Surface casing will be run to 3,863’ MD / 3,092’ TVD and cemented to surface to ensure protection of any shallow freshwaterresources. 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 be discussed with BLM and 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 # 169 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. ND diverter, N/U & test 11” x 5M BOP. 5. Test casing to 3500 psi. Perform 12.5# FIT (12.2# minimum to drill ahead). 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: Triple Combo + MWD Production Hole: Triple Combo + MWD -bjm 27 deg inclination. -bjm Page 8 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with all relevant AOGCC regulations and all BLM regulations pertaining to Onshore Order No.1. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. BOPs shall be tested at (2) week intervals during the drilling of SRU 233-10. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs and BLM 48 hrs notice prior to testing. 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. 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. All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” Ensure AOGCC and BLM approved drilling permits are posted on the rig floor and in Co Man office. Review all conditions of approval of the BLM APD and 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. BLM Regulation Variance Requests: Onshore Oil and Gas Order No. 1, Section III. D. 3. C. o Hilcorp requests approval to install a 2-1/16” 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. Page 9 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8”21-1/4” x 2M Hydril MSP diverter Function Test Only 6-3/4” 11” x 5M Annular BOP 11” x 5M Double Ram o Blind ram in btm cavity Mud cross 11” x 5M Single Ram 3-1/8” 5M Choke Line 2-1/16” x 5M Kill line 3-1/8” x 2-1/16” 5M Choke manifold Standpipe, floor valves, etc Initial Test: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: Well control event (BOPs utilized to shut in the well to control influx of formation fluids). 24 hours’ notice prior to testing BOPs. Any other notifications required in APD. Required BLM Notifications: 48 hours before spud. Follow up with actual spud date and time within 24 hours. 48 hours before casing running and cmt operations 48 hours before BOPE tests 48 hours before logging, coring, & testing Any other notifications required in APD Additional requirements may be stipulated on APD and Sundry. Page 10 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 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) BLM Allie Schoessler / BLM Petroleum Engineer / (O): 907-271-3127 Email:aschoessler@blm.gov Use the below email address for BOP notifications to the BLM: BLM_AK_AKSO_EnergySection_Notifications@blm.gov Page 11 Version 0.0 October 15, 2025 SRU 233-10 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 # 169, 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. HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. Page 12 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 10.0 N/U 21-1/4” 2M Diverter 10.1 N/U 21-1/4” Hydril MSP 2M diverter System. N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. N/U 21-1/4” diverter “T”. Knife gate, 16” diverter line. Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 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. 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: A prohibition on vehicle parking. A prohibition on ignition sources or running equipment. A prohibition on staged equipment or materials. Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. 10.5 Estimated diverter line orientation on SRU Pad 21-15 (orientation is subject to change on location): Page 13 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure Page 14 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 11.0 Drill 9-7/8” Hole Section 11.1 P/U 9-7/8” directional drilling assy: Ensure BHA components have been inspected previously. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. Ensure TF offset is measured accurately and entered correctly into the MWD software. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 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 3,863’ MD/ 3,092’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. Utilize Inlet experience to drill through coal seams efficiently. Keep swab and surge pressures low when tripping. Make a wiper trip halfway through the surface hole interval. Make additional wiper trips if hole conditions dictate. Ensure shale shakers are functioning properly. Check for holes in screens on connections. Adjust MW as necessary to maintain hole stability. TD the hole section in a good shale 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. Page 15 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity PV YP API FL pH Surface Interval 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 16 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker TRS 7-5/8” casing running equipment. Ensure Casing x CDS 40 XO on rig floor and M/U to FOSV. R/U fill-up line to fill casing while running. Ensure all casing has been drifted on the location prior to running. Be sure to count the total # of joints on the location before running. Keep hole covered while R/U casing tools. Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: (1) Shoe joint w/ float shoe bucked on (thread locked). (1) Joint with coupling thread locked. (1) Joint with float collar bucked on pin end & thread locked. Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. Install (1) centralizer, mid tube on thread locked joint and on FC joint. Ensure proper operation of float equipment. 12.5 Continue running 7-5/8” surface casing Fill casing while running using fill up line on rig floor. Use “API Modified” thread compound. Dope pin end only w/ paint brush. Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 17 Version 0.0 October 15, 2025 SRU 233-10 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. 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 18 Version 0.0 October 15, 2025 SRU 233-10 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. Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole How to handle cmt returns at surface. Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. 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% open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 19 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure Estimated Total Cement Volume: Verified cement calcs. -bjm Page 20 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure Cement Slurry Design: 13.8 Attempt to reciprocate casing during cement pumping as hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 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. 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. 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. 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 21 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 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 wellez: Pre flush type, volume (bbls) & weight (ppg) Cement slurry type, lead or tail, volume & weight Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Note if casing is reciprocated or rotated during the job Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note if pre flush or cement returns at surface & volume Note time cement in place Note calculated top of cement 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 22 Version 0.0 October 15, 2025 SRU 233-10 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: 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 Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram in btm cavity. Single ram should be dressed with 2-7/8” x 5” variable bore rams N/U bell nipple, install flowline. Install (2) manual valves & a check valve on kill side of mud cross. 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). Test BOP to 250/3000 psi for 5/10 min. Test VBR’s with 3-1/2” and 4-1/2” test joints Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint 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 23 Version 0.0 October 15, 2025 SRU 233-10 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: MD MW Viscosity PV Yield Point pH HPHT Production Hole 8.8 – 9.2 40-53 15-25 15-25 8.5-9.5 11.0 Page 24 Version 0.0 October 15, 2025 SRU 233-10 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 – 10.0 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. 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. CBU and condition mud for FIT. 15.12 Conduct FIT to 12.5 ppg EMW. A 12.2# ppg FIT will result in a 20 bbl KTV assuming an 8.27ppg PP and a 9.2ppg MW (swabbed kick). 15.13 Drill 6-3/4” hole section to planned TD Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. Keep swab and surge pressures low when tripping. Make wiper trips every 1000’ to 1500’ unless hole conditions dictate otherwise. Trip back to the 7-5/8” shoe about ½ way through the hole section Ensure shale shakers are functioning properly. Check for holes in screens on connections. Lost circulation potential when drilling through Sterling A, Lower Beluga, and the Tyonek 61-8 and 68-0. Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. 15.14 At TD, pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 15.15 TOH with the drilling assy, laying down drill pipe. LD density and porosity tools. Perform 10 minute flowchecks prior to tripping off bottom, prior to tripping above the surface shoe, and prior to laying down the BHA. Section 15.13 superseded. See following pg. -bjm Page 24 Version 1.0 November 11, 2025 SRU 233-10 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 – 10.0 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. 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. CBU and condition mud for FIT. 15.12 Conduct FIT to 12.5 ppg EMW. A 12.2# ppg FIT will result in a 20 bbl KTV assuming an 8.27ppg PP and a 9.2ppg MW (swabbed kick). 15.13 Drill 6-3/4” hole section to planned TD Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. Keep swab and surge pressures low when tripping. Make wiper trips every 1000’ to 1500’ unless hole conditions dictate otherwise. Trip back to the 7-5/8” shoe about ½ way through the hole section Ensure shale shakers are functioning properly. Check for holes in screens on connections. Lost circulation potential when drilling through Sterling A, Lower Beluga, and the Tyonek 61-8 and 68-0. Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if necessary. SRU 34-10 has a 0.993 clearance factor at 8648’ MD. SRU 34-10 has been plugged and abandoned. There is no HSE risk associated with a collision. The potential consequence is financial. 15.14 At TD, pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 15.15 TOH with the drilling assy, laying down drill pipe. LD density and porosity tools. Page 25 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 16.0 Run 3-1/2” Production Liner 16.1. R/U Parker 3-1/2” casing running equipment. Ensure 3-1/2” Liner x CDS 40 crossover on rig floor and M/U to FOSV. R/U fill up line to fill casing while running. Ensure all casing has been drifted prior to running. Be sure to count the total # of joints before running. Keep hole covered while R/U casing tools. Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). (1) Joint with Baker landing collar bucked on pin end & threadlocked. Solid body centralizers will be pre-installed on shoe joint an FC joint. Leave centralizers free floating so that they can slide up and down the joint. Ensure proper operation of float shoe and float collar. Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 3-1/2” production liner Fill casing while running using fill up line on rig floor. Use “API Modified” thread compound. Dope pin end only w/ paint brush. 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 26 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure Page 27 Version 0.0 October 15, 2025 SRU 233-10 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 28 Version 0.0 October 15, 2025 SRU 233-10 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. Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. Positions and expectations of personnel involved with the cmt operation. 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 29 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure Estimated Total Cement Volume: 8648' -bjm Verified cement calcs. -bjm Page 30 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure Cement Slurry Design: Lead Slurry Tail Slurry (500’ MD) System Extended Conventional Density 12 lb/gal 15.3 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 following service company procedure to release from the hanger and set the LTP. 17.14. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.15. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight Page 31 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 17.16. Pressure up drill pipe to 500 psi and pick up to remove the packoff bushing from the nipple. 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). 17.17. 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. 17.18. 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. 17.19. RD cementers and flush equipment. POOH, LDDP and running tool. Backup release from liner hanger (verify with service company rep): 17.20. If the tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 17.21. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 17.22. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. 17.23. WOC until the compressive strength hits at least 500 psi before testing casing to 3000 psi and chart for 30 minutes. Page 32 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure Ensure to report the following on wellez: Pre flush type, volume (bbls) & weight (ppg) Cement slurry type, lead or tail, volume & weight Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Note if casing is reciprocated or rotated during the job Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note if pre flush or cement returns at surface & volume Note time cement in place Note calculated top of cement 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 33 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 18.0 3-1/2” Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per service company 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 34 Version 0.0 October 15, 2025 SRU 233-10 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. 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. 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 #169 Page 35 Version 0.0 October 15, 2025 SRU 233-10 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 2-1/2” 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 24 hr notice required. -bjm Page 36 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure Page 37 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure Page 38 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 21.0 Diverter Schematic Page 39 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 22.0 BOP Schematic Page 40 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 23.0 Wellhead Schematic Page 41 Version 0.0 October 15, 2025 SRU 233-10 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 42 Version 0.0 October 15, 2025 SRU 233-10 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. 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. Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. Use asphalt-type additives to further stabilize coal seams. Increase fluid density as required to control running coals. 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 43 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 25.0 Hilcorp Rig 169 Layout Page 44 Version 0.0 October 15, 2025 SRU 233-10 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 45 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 27.0 Choke Manifold Schematic Page 46 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 28.0 Casing Design Information Page 47 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 29.0 6-3/4” Hole Section MASP ? ? ? ? ? NOTE: Some listed TVDs aren't close to TVDs for same horizons in directional survey, but not critical here since pressure gradient is uniform. SFD ? Page 48 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 30.0 Spider Plot w/ 660’ Radius for SSSV Page 49 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure 31.0 Surface Plat (As-Staked NAD27 & NAD83) Page 50 Version 0.0 October 15, 2025 SRU 233-10 Drilling Procedure Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. Swanson River Sterling / U Beluga Gas, Beluga Gas, Tyonek Gas Swanson River Unit 233-10 225-113 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:SWANSON RIV UNIT 233-10Initial Class/TypeDEV / PENDGeoArea820Unit51994On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2251130Field & Pool:SWANSON RIVER, TYONEK GAS - 772500, SWANSON RIVER, BELUGA GAS - 772520, SWANNA1 Permit fee attachedYes Surface Location lies within ADL0028406; Top Prod Int & TD lie within ADL0028405.2 Lease number appropriateYes3 Unique well name and numberYes SWANSON RIVER, Sterling/Upper Beluga GS, Beluga Gas, Tyonek Gas4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsNA7 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 approvedYes Close approach well SRU 34-10 has been P&A'd26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2454 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 None anticipated based on offset wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure is 0.43 psi/ft (8.3 ppg EMW). Operator's planned mud program36 Data presented on potential overpressure zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate10/30/2025ApprBJMDate11/11/2025ApprSFDDate10/30/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 11/12/2025