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Home My WebLink About225-123Nolan 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: 2/4/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260204 Well API # PTD # Log Date Log Company Log Type AOGCC E-Set# BRU 223-34T 50283202060000 225059 12/31/2025 AK E-LINE Perf T41308 BRU 244-27 50283201850000 222038 1/2/2026 AK E-LINE Perf T41309 CLU 11RD 50133205590000 225013 1/2/2026 YELLOWJACKET SCBL T41310 CLU 11RD 50133205590000 225013 12/19/2025 YELLOWJACKET SCBL T41310 END 1-25A 50029217220100 197075 11/7/2025 HALLIBURTON COILFLAG T41311 END 1-25A 50029217220100 197075 12/26/2025 READ PressTempSurvey T41311 END 2-40 50029225270000 194152 12/18/2025 READ PressTempSurvey T41312 END 2-52 50029217500000 187092 12/24/2025 HALLIBURTON MFC40 T41313 END 2-56A 50029228630100 198058 1/1/2026 HALLIBURTON COILFLAG T41314 END 2-56A 50029228630100 198058 1/19/2026 READ CaliperSurvey T41314 KALOTSA 3 50133206610000 217028 1/14/2026 YELLOWJACKET PERF T41315 KALOTSA 3 50133206610000 217028 1/9/2026 YELLOWJACKET PERF T41315 KALOTSA 8 50133207050000 222003 12/18/2025 YELLOWJACKET PERF T41316 KBU 44-06 50133204980000 200179 12/22/2026 YELLOWJACKET CBL T41317 KBU 44-06 50133204980000 200179 11/12/2025 YELLOWJACKET PLUG T41317 KU 24-07RD 50133203520100 205099 1/6/2026 AK E-LINE CBL T41318 KU 24-07RD 50133203520100 205099 1/6/2026 AK E-LINE Plug/Cement T41318 KU 24-07RD 50133203520100 205099 1/1/2026 AK E-LINE Plug/Cement/TubingPunch T41318 MPI-36 50029236770000 220047 1/19/2026 READ CaliperSurvey T41319 MPI-36 50029236770000 220047 1/19/2026 READ LeakDetectLog T41319 NCIU A-19 50883201940000 224026 1/7/2025 AK E-LINE Perf T41320 NFU 42-35 50231200460000 214170 1/8/2026 YELLOWJACKET PERF T41321 NIK OI24-08 50029234570000 211130 1/19/2026 HALLIBURTON COILFLAG T41322 ODSN-04 50703206700000 213037 1/20/2026 HALLIBURTON LDL T41323 ODSN-22 50703207080000 215054 12/20/2025 READ LeakDetection T41324 PBU 15-11D 50029206530400 225112 1/18/2026 HALLIBURTON RBT-COILFLAG T41325 PBU 15-43 50029226760000 196083 12/21/2025 HALLIBURTON RBT T41326 PBU B-30B 50029215420200 225009 1/24/2026 HALLIBURTON RBT-COILFLAG T41327 PBU C-33B 50029223730200 225096 12/16/2025 HALLIBURTON RBT-COILFLAG T41328 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 09:10:43 -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: PBU D-26B 50029215300200 206098 12/20/2025 HALLIBURTON ISAT T41329 PBU D-26B 50029215300200 206098 12/19/2025 BAKER SPN T41329 PBU F-21A 50029219490100 225019 1/18/2026 HALLIBURTON RBT-COILFLAG T41330 PBU J-21A 50029217050100 225106 1/21/2026 HALLIBURTON RBT-COILFLAG T41331 PBU L-291 50029237790000 224002 12/26/2025 HALLIBURTON RBT T41332 PBU L-291 50029237790000 224002 12/9/2025 YELLOWJACKET RCBL T41332 PBU S-107A 50029220440200 225083 12/8/2025 HALLIBURTON RBT-COILFLAG T41333 PBU S-201A 50029229870100 219092 1/21/2026 HALLIBURTON WFL-TMD3D T41335 PBU S-24B 50029220440200 203163 12/22/2025 HALLIBURTON RBT T41334 PBU S-24B 50029230230100 203163 12/23/2025 HALLIBURTON WFL-TMD3D T41334 SRU 223-15 50133207410000 225123 1/29/2026 YELLOWJACKET GPT-PERF T41336 SRU 223-15 50133207410000 225123 1/20/2026 YELLOWJACKET SCBL T41336 SRU 233-10 50133207400000 225113 12/30/2026 AK E-LINE CBL T41337 SRU 233-10 50133207400000 225113 1/10/2026 YELLOWJACKET SCBL T41337 SRU 233-10 50133207400000 225113 1/6/2026 YELLOWJACKET SCBL T41337 SRU 34-28 50133101580000 163007 1/7/2026 YELLOWJACKET Gamma Ray T41338 SU 32-16 50133207380000 225095 1/17/2026 YELLOWJACKET GPT-PLUG-PERF T41339 SU 32-16 50133207380000 225095 11/22/2025 YELLOWJACKET SCBL T41339 SU 43-10 50133207390000 225107 12/10/2025 YELLOWJACKET SCBL T41340 TBU A-12RD 50883200320100 171029 1/2/2026 AK E-LINE StripGun T41341 TBU D-24A 50733202240100 174064 12/4/2025 AK E-LINE TubingPunch T41342 Please include current contact information if different from above. T41336SRU 223-15 50133207410000 225123 1/29/2026 YELLOWJACKET GPT-PERF T41336SRU 223-15 50133207410000 225123 1/20/2026 YELLOWJACKET SCBL T41337SRU 233-10 50133207400000 225113 12/30/2026 AK E-LINE CBL T41337SRU 233-10 50133207400000 225113 1/10/2026 YELLOWJACKET SCBL SRU 233-10 50133207400000 225113 1/6/2026 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 09:11:00 -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: 02/04/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: SRU 223-15 PTD: 225-123 API: 50-133-20741-00-00 FINAL GAS SAMPLING (01/04/2026 to 01/11/2026) 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. 225-123 T41307 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.04 15:30:27 -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: 02/02/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: SRU 223-15 PTD: 225-123 API: 50-133-20741-00-00 FINAL LWD FORMATION EVALUATION LOGS (12/29/2025 to 01/11/2026) ROP, DGR and BaseStar Gamma Ray ADR and StrataStar Resistivity, 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. 225-123 T41305 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.03 08:12:21 -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 Other: Initial Completion, N2 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): 7,640' 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 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 225-123 50-133-20741-00-00 Hilcorp Alaska, LLC Proposed Pools: 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 9.3# / L-80 TVD Burst 3,034' 10,160psi 3,106' 120' 3,197' MD See Attached Schematic 29,980psi 6,890psi 120'120' 3,197' January 25, 2026 3-1/2" Tieback 7,640' Perforation Depth MD (ft): 7-5/8" Swanson River Unit (SRU) 223-15CO 716A Same 7,393'3-1/2" ~2,665psi Swanson River Sterling/Bel Gas, Beluga Gas, Tyonek Gas Size See Attached Schematic 4,505' N/A Length LTP; N/A 3,009' MD/ 2,925' TVD; N/A, N/A 7,393' 7,576' 7,331' 16" m n P s 66 t 2 N 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 1:45 pm, Jan 16, 2026 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2026.01.16 12:28:32 - 09'00' Noel Nocas (4361) 326-034 DSR-1/6/26A.Dewhurst 19JAN26 10-407 BJM 1/21/26 2970 psi -bjm 01/21/26 Well Prognosis Well Name: SRU 223-15 API Number: 50-133-20741-00-00 Current Status: New Drill Well Permit to Drill Number: 225-123 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: 3390 psi @ 7242 TVD (Based on 0.468 psi/ft gradient) Max. Potential Surface Pressure: 2665 psi @ 7242 TVD (0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.659 psi/ft using 12.67 ppg EMW FIT @ 7-5/8 surface shoe Shallowest Potential Perf TVD: MPSP / (0.659 - 0.1) = 2665 psi / 0.559 = 4767 TVD Applicable Pool(s) / PA(s): Tyonek: 5817 MD / 5643 TVD Beluga: 5155 MD / 4997 TVD Well Status: New Drill Well Initial Completion Brief Well Summary SRU 223-15 is a directional grassroots development well drilled in January 2026 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 1/14/2026 - 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 9.8 ppg kick (.51 psi/ft) was taken while drilling the Tyonek 68-3 sand. Calculate BHP based on this. Received CBL. TOC ~ 3378' MD. -bjm 3695 psi 2970 psi 5313' TVD. -bjm See attached email from Ryan Lemay 1/21/2026. -bjm 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 223-15 TY 53-0 +5,827 +5,835 +5,645 +5,653 +8 SRU 223-15 TY 54-4 +6,043 +6,056 +5,853 +5,865 +13 SRU 223-15 TY 55-4 +6,065 +6,074 +5,874 +5,883 +9 SRU 223-15 TY 56-9 +6,295 +6,307 +6,096 +6,107 +12 SRU 223-15 TY 56-9 +6,325 +6,331 +6,125 +6,131 +6 SRU 223-15 TY 57-8 +6,403 +6,418 +6,200 +6,215 +15 SRU 223-15 TY 61-0 +6,467 +6,474 +6,262 +6,269 +7 SRU 223-15 TY 61-0 +6,491 +6,501 +6,285 +6,295 +10 SRU 223-15 TY 61-8 +6,630 +6,647 +6,420 +6,436 +17 SRU 223-15 TY 62-3 +6,676 +6,690 +6,464 +6,478 +14 SRU 223-15 TY 62-3 +6,742 +6,762 +6,528 +6,547 +20 SRU 223-15 TY 62-3 +6,766 +6,789 +6,551 +6,573 +23 SRU 223-15 TY 62-5 +6,827 +6,833 +6,609 +6,615 +6 SRU 223-15 TY 62-5 +6,870 +6,876 +6,651 +6,657 +6 SRU 223-15 TY 64-5 +7,112 +7,120 +6,882 +6,890 +8 SRU 223-15 TY 65-0 +7,208 +7,212 +6,974 +6,978 +4 SRU 223-15 TY 68-0 +7,394 +7,406 +7,153 +7,165 +12 SRU 223-15 TY 68-3 +7,432 +7,446 +7,190 +7,204 +14 SRU 223-15 TY 68-3 +7,465 +7,485 +7,222 +7,242 +20 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. Well Prognosis 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 1-15-26 CURRENT SCHEMATIC Swanson River Unit SRU 223-15 PTD: 225-123 API: 50-133-20741-00-00 PBTD = 7,576 MD / TVD = 7,331 TD = 7,640 MD / TVD = 7,393 RKB to GL = 21.14 NOTES 10 Short jt w/ RA tags 3,982, 4,999, 5,986, 10 Short joints 4,488, 5,506, 6,495, 7,004 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875Surf 3,197 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.9923,0457,640 3-1/2"Prod Tieback 9.3 L-80 EUE 2.992Surf 3,034 1 16 7-5/8 9-7/8 hole 3-1/2 JEWELRY DETAIL No. Depth Item 1 21Cactus CTF-ONE-CTL 11 x 4-1/2 Hanger w/ 4 Type H BPV profile 2 1,4903-1/2 Chemical Injection Mandrel (2.867 ID) w/ 3/8 control line 3 3,009YJ Scout Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper Polish 4 3,035Bullet Seal Assembly spaced 1.91 off no-go OPEN HOLE / CEMENT DETAIL 7-5/8" Cement at surface. 60 bbls 10.5 ppg spacer + 194 bbls 12 ppg lead cement + 38 bbls 15.8 ppg tail cement pumped. Full returns throughout cement job and got 60 bbls spacer + 90 bbls cement returns back to surface (1-3-26). 3-1/2 30 bbls 10.5 ppg spacer + 194 bbls 12 ppg lead cement + 27 bbls 15.3 ppg tail cement pumped. Partial returns throughout cement job. Lost a total of 117 bbls during cement job. TOC via CBL = xxxx (date) 6-3/4 hole 2 3/4 Updated by RPL 1-15-26 PROPOSED SCHEMATIC Swanson River Unit SRU 223-15 PTD: 225-123 API: 50-133-20741-00-00 PBTD = 7,576 MD / TVD = 7,331 TD = 7,640 MD / TVD = 7,393 RKB to GL = 21.14 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status TY 53-0 +5,827+5,835+5,645+5,653+8TBD Proposed TY 54-4 +6,043+6,056+5,853+5,865+13TBD Proposed TY 55-4 +6,065+6,074+5,874+5,883+9TBD Proposed TY 56-9 +6,295+6,307+6,096+6,107+12TBD Proposed TY 56-9 +6,325+6,331+6,125+6,131+6TBD Proposed TY 57-8 +6,403+6,418+6,200+6,215+15TBD Proposed TY 61-0 +6,467+6,474+6,262+6,269+7TBD Proposed TY 61-0 +6,491+6,501+6,285+6,295+10TBD Proposed TY 61-8 +6,630+6,647+6,420+6,436+17TBD Proposed TY 62-3 +6,676+6,690+6,464+6,478+14TBD Proposed TY 62-3 +6,742+6,762+6,528+6,547+20TBD Proposed TY 62-3 +6,766+6,789+6,551+6,573+23TBD Proposed TY 62-5 +6,827+6,833+6,609+6,615+6TBD Proposed TY 62-5 +6,870+6,876+6,651+6,657+6TBD Proposed TY 64-5 +7,112+7,120+6,882+6,890+8TBD Proposed TY 65-0 +7,208+7,212+6,974+6,978+4TBD Proposed TY 68-0 +7,394+7,406+7,153+7,165+12TBD Proposed TY 68-3 +7,432+7,446+7,190+7,204+14TBD Proposed TY 68-3 +7,465+7,485+7,222+7,242+20TBD Proposed NOTES 10 Short jt w/ RA tags 3,982, 4,999, 5,986, 10 Short joints 4,488, 5,506, 6,495, 7,004 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875Surf 3,197 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.9923,0457,640 3-1/2"Prod Tieback 9.3 L-80 EUE 2.992Surf 3,034 1 16 7-5/8 9-7/8 hole 3-1/2 JEWELRY DETAIL No. Depth Item 1 21Cactus CTF-ONE-CTL 11 x 4-1/2 Hanger w/ 4 Type H BPV profile 2 1,4903-1/2 Chemical Injection Mandrel (2.867 ID) w/ 3/8 control line 3 3,009YJ Scout Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper Polish 4 3,035Bullet Seal Assembly spaced 1.91 off no-go OPEN HOLE / CEMENT DETAIL 7-5/8" Cement at surface. 60 bbls 10.5 ppg spacer + 194 bbls 12 ppg lead cement + 38 bbls 15.8 ppg tail cement pumped. Full returns throughout cement job and got 60 bbls spacer + 90 bbls cement returns back to surface (1-3-26). 3-1/2 30 bbls 10.5 ppg spacer + 194 bbls 12 ppg lead cement + 27 bbls 15.3 ppg tail cement pumped. Partial returns throughout cement job. Lost a total of 117 bbls during cement job. TOC via CBL = xxxx (date) 6-3/4 hole 2 3/4 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. 1 McLellan, Bryan J (OGC) From:Ryan Lemay <ryan.lemay@hilcorp.com> Sent:Wednesday, January 21, 2026 11:18 AM To:McLellan, Bryan J (OGC) Cc:Nathan Sperry; Donna Ambruz Subject:RE: SRU 223-15 (PTD 225-123) perf sundry / CBL Results Attachments:SRU 223-15 SCBL FINAL 1-20-26.pdf; SRU 223-15 SCBL MAIN PASS 1-20-26.las Good morning Bryan, I am good to use 9.8 ppg as the initial basis for pressure calculations and shallowest allowable perf up to / through the TY 68-3 formation. I would ask that if during completion operations we perf this zone and we ultimately need to isolate with a plug that we can revert back to assumed 0.468 psi / ft (9.0 ppg equivalent that the hole section was drilled with prior to drilling into the TY 68-3 formation). Updating calculations to a 9.8 ppg (0.51 psi / ft) 7242 TVD x 0.51 psi / ft = 3694 psi Maximum Expected BHP 7242 TVD x 0.41 psi / ft = 2970 psi Max Potential Surface Pressure (using 0.1 psi / ft gas gradient to surface) 0.659 psi / ft using 12.67 ppg EMW FIT @ 7-5/8 shoe 2970 psi / 0.559 = 5313 Shallowest allowable Perf TVD The updated calculations would allow for us to perf up through the Tyonek / proposed perforation intervals in the completion sundry. Additionally, the sundry procedure calls out that we will test PCE 250 low / 3500 psi high which will cover the expected maximum potential surface pressures wed expect with the updated 0.51 psi / ft assumption. I have also included a copy of the CBL, we were able to get the ran yesterday for your review. Please let me know if you need me to send you a revised procedure with these updated calculations or if this e-mail will su ice in the review and approval of the completion sundry. Have a great day, Ryan LeMay Opera ons Engineer Swanson River / Beaver Creek Cell: (661) 487-0871 E-mail: Ryan.lemay@hilcorp.com CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 To help protect your privacy, Microsoft Office prevented automatic download of this picture from the Internet. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, January 20, 2026 4:21 PM To: Ryan Lemay <ryan.lemay@hilcorp.com> Cc: Nathan Sperry <nathan.sperry@hilcorp.com> Subject: SRU 223-15 (PTD 225-123) perf sundry Ryan, The rig took a 9.8 ppg kick while drilling the Tyonek 68-3 formation, which equates to 0.51 psi/ft pressure gradient. The sundry is using 0.468 psi/ft gradient to calculate max expected reservoir pressure. I think 9.8 ppg should be used as the basis for pressure calculations and shallowest perf. Nate said that maybe there was evidence that it wasnt 9.8 ppg, so if you have more data to support a lower pressure, please send it over. Initial shut-in casing and drillpipe pressure and the pressures after the rst circulation of the drillers method could potentially be used, but I dont have that data. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 1 Dewhurst, Andrew D (OGC) From:Ryan Lemay <ryan.lemay@hilcorp.com> Sent:Monday, 19 January, 2026 10:21 To:Dewhurst, Andrew D (OGC) Cc:McLellan, Bryan J (OGC); Donna Ambruz Subject:RE: [EXTERNAL] SRU 223-15 Perf Sundry (326-034): Question Attachments:SRU 223-15_Final Surveys.xlsx; SRU 223-15.txt; SRU 223-15 Field Final FE Data.las Good morning Andy, Attached are the preliminary eld nal les requested. Let me know if you have any questions or need anything else. Ryan LeMay Opera ons Engineer Swanson River / Beaver Creek Cell: (661) 487-0871 E-mail: Ryan.lemay@hilcorp.com To help protect your priv acy, Microsoft Office prevented automatic download of this picture from the Internet. From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Monday, January 19, 2026 9:22 AM To: Ryan Lemay <ryan.lemay@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] SRU 223-15 Perf Sundry (326-034): Question Ryan, To help me with the SRU 223-15 perf sundry, would you please send the following: Directional survey (.txt or other digital le) LWD logs (.las) Thanks, Andy 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. 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:Nathan Sperry To:AOGCC Reporting (CED sponsored); McLellan, Bryan J (OGC); Regg, James B (OGC) Cc:Sean McLaughlin; Cody Dinger Subject:PTD 225-123 Hilcorp Well SRU 223-15: BOPE Usage Form Date:Sunday, January 11, 2026 9:03:20 PM Attachments:BOPE USAGE REPORT_Rig 169 SRU 223-15 PTD 225-123.pdf Good evening, I’ve attached the BOPE usage form for Hilcorp rig 169 on SRU 223-15 in response to a well control event yesterday at 22:06. 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 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. AOGCC BOPE USAGE REPORT FORM (Well Control Event) Drilling Manager Name: Sean Mclaughlin Drill Site Foreman: Jay Murphy Contact Number: 907-223-6784 Contact Number: 907-283-1369 HILCORP Velocity Number: TBD Rig Name & Well Pad or Drill Site & Well Name: Hilcorp Rig 169 SRU 223-15 Permit To Drill (PTD) Number: 225-123 Date and Time of Incident: 1/10/2026 22:06 Original Scope of Work: Drill 6-3/4” Production Hole Operational Description Leading up to Well Control Event: While drilling ahead at 7,531’ MD with a 9.1ppg mud weight, an increase in return flow was noticed. The pumps were shut down, and the well was shut in using the annular. A 9 bbls pit gain was recorded. The influx was circulated out through the choke using the drillers method. The pumps were shut down and the well was shut in. The choke was opened and the well was circulated over to 9.4ppg MW. The well was shut in at the choke and monitored. After 13 minutes of zero pressure, the SIDPP and SICP built to 137 psi. The rig team built 10ppg KWM and circulated surface to surface. After monitoring, they opened the well and established pipe movement. They shut down and shut in on the pipe rams to monitor. No pressure was recorded. We resumed drilling the final 109’ to TD. BOPE Used and Reason: Annular preventer, ram preventer, and choke HCR valve. Current BOPE test time/date 1/14/2026 Is a BOPE re-test required after use: Yes BOPE Retest time/date and result: Will be completed once out of the hole prior to running liner. Plan Forward: The well has been drilled to TD. The plan forward is to trip out and lay down the drilling BHA. Additional Comments: ACTIONS REQUIRED: by Drilling Foreman 1. Timely email notification of BOPE re-test time estimate to AOGCC North Slope Inspectors is required following any WC incident to allow the State to witness re-test as required. 2. Email the completed BOPE Usage Report form to AOGCC North Slope Inspectors within 24 hours of a WC incident: doa.aogcc.prudhoe.bay@alaska.gov 3. Complete AOGCC BOPE Test report form 10-424 and send to three AOGCC addresses (noted in form) within 5 days following the test/retest. This is applicable to Well Control events Only. 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:Nathan Sperry To:AOGCC Reporting (CED sponsored); McLellan, Bryan J (OGC); Regg, James B (OGC) Cc:Sean McLaughlin; Cody Dinger Subject:PTD 225-123 Hilcorp Well SRU 223-15: BOPE Usage Form Date:Sunday, January 11, 2026 9:03:20 PM Attachments:BOPE USAGE REPORT_Rig 169 SRU 223-15 PTD 225-123.pdf Good evening, I’ve attached the BOPE usage form for Hilcorp rig 169 on SRU 223-15 in response to a well control event yesterday at 22:06. 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 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. 6ZDQVRQ5LYHU8QLW 37' AOGCC BOPE USAGE REPORT FORM (Well Control Event) Drilling Manager Name: Sean Mclaughlin Drill Site Foreman: Jay Murphy Contact Number: 907-223-6784 Contact Number: 907-283-1369 HILCORP Velocity Number: TBD Rig Name & Well Pad or Drill Site & Well Name: Hilcorp Rig 169 SRU 223-15 Permit To Drill (PTD) Number: 225-123 Date and Time of Incident: 1/10/2026 22:06 Original Scope of Work:Drill 6-3/4”Production Hole Operational Description Leading up to Well Control Event:While drilling ahead at 7,531’MD with a 9.1ppg mud weight, an increase in return flow was noticed. The pumps were shut down, and the well was shut in using the annular. A 9 bbls pit gain was recorded. The influx was circulated out through the choke using the drillers method. The pumps were shut down and the well was shut in. The choke was opened and the well was circulated over to 9.4ppg MW. The well was shut in at the choke and monitored. After 13 minutes of zero pressure, the SIDPP and SICP built to 137 psi. The rig team built 10ppg KWM and circulated surface to surface. After monitoring, they opened the well and established pipe movement. They shut down and shut in on the pipe rams to monitor. No pressure was recorded. We resumed drilling the final 109’ to TD. BOPE Used and Reason:Annular preventer, ram preventer,and choke HCR valve. Current BOPE test time/date 1/14/2026 Is a BOPE re-test required after use: Yes BOPE Retest time/date and result: Will be completed once out of the hole prior to running liner. Plan Forward: The well has been drilled to TD. The plan forward is to trip out and lay down the drilling BHA. Additional Comments: ACTIONS REQUIRED: by Drilling Foreman 1.Timely email notification of BOPE re-test time estimate to AOGCC North Slope Inspectors is required following any WC incident to allow the State to witness re-test as required. 2.Email the completed BOPE Usage Report form to AOGCC North Slope Inspectors within 24 hours of a WC incident: doa.aogcc.prudhoe.bay@alaska.gov 3.Complete AOGCC BOPE Test report form 10-424 and send to three AOGCC addresses (noted in form) within 5 days following the test/retest. This is applicable to Well Control events Only. 9 9 9 9 9 9 WHVWQRWLILHGDQGDJDLQVHHDWWDFKHGMEU 225-123 Hilcorp Rig 169 SRU 223-15 1/10/2026 22:06 increase in return flow 9 bbls pit gain was recorded Annular preventer, ram preventer,and choke HCR valve. BOPE re-test required after use 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:Jay Murphy To:DOA AOGCC Prudhoe Bay; ced-svc-ogcforms (CED sponsored) Subject:AOGCC Test Witness Notification Request: BOPE, Hilcorp 169, Well SRU 223-15, SRU Pad Tank setting 2-15. Date:Sunday, January 11, 2026 3:24:23 PM Question Answer Type of Test Requested: BOPE Requested Time for Inspection 01-12-2026 8:00 AM Location Hilcorp 169, Well SRU 223-15, SRU Pad Tank setting 2-15. Name Jay Murphy E-mail Jay.Murphy@hilcorp.com Phone Number (907) 283-1369 Company Hilcorp Alaska Other Information:We will be testing components that were used to secure the well when we get to surface tomorrow morning. Submission ID: 6439866221316409946 9 9 9 01-12-2026 8:00 AM Hilcorp 169, Well SRU 223-15 Sunday, January 11, 2026 3:24:23 PM 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; Maercklein, William C Cc:Donna Ambruz Subject:RE: Program Change / New Drill SRU 223-15 / Request to Install CIM in 3.5" Upper Completion Date:Thursday, January 8, 2026 4:24:00 PM Change is 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: Thursday, January 8, 2026 2:56 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Maercklein, William C <wmaercklein@blm.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: Program Change / New Drill SRU 223-15 / Request to Install CIM in 3.5" Upper Completion Good afternoon Bryan and Will, Swanson River New Drill SRU 223-15 API Number: 50-133-20741-00-00 AOGCC PTD: 225-123 BLM APD ID: 10400108410 Hilcorp is seeking a program change approved to install a chemical injection mandrel in the 3.5” upper completion at + 1500’ with 3/8” control line on current new drill SRU 223- 15 in Swanson River. Thank you and please let me know if you have any 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 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 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. 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 Field, Sterling/Beluga Gas Pool, SRU 223-15 Hilcorp Alaska, LLC Permit to Drill Number: 225-123 Surface Location: 2133' FNL, 972' FWL, Sec 15, T8N, R9W, SM, AK Bottomhole Location: 2231' FSL, 2627' FWL, Sec 15, 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 1st day of December 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: 7,772' TVD: 7,522' 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): 334.6' 15. Distance to Nearest Well Open Surface: x-348823 y- 2480127 Zone-4 316.6' to Same Pool: 2700' to SRU 223-15 16. Deviated wells: Kickoff depth: 200 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 15 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 3,213' Surface Surface 3,213' 3,122' 6-3/4" 3-1/2" 9.2# L-80 Hyd 563 4,759' 3,013' 2,929' 7,772' 7,522' Tieback 3-1/2" 9.2# L-80 EUE 3,013' Surface Surface 3,013' 2,929' 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 12/28/2025 2601' to nearest unit boundary Nathan Sperry nathan.sperry@hilcorp.com 907-777-8450 Tieback Assy. 2400 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 - 1084 ft3 / T - 208 ft3 Effect. Depth MD (ft): Effect. Depth TVD (ft): 18. Casing Program: Top - Setting Depth - BottomSpecifications 3234 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 - 1071 ft3 / T - 131 ft3 2482 2457' FNL, 1618' FWL, Sec 15, T8N, R9W, SM, AK 2231' FSL, 2627' FWL, Sec 15, T8N, R9W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 2133' FNL, 972' FWL, Sec 15, T8N, R9W, SM, AK AKA 028406 SRU 223-15 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. 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) L-80 By Grace Christianson at 11:08 am, Nov 12, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.11.12 09:55:30 - 09'00' Sean McLaughlin (4311) 225-123 50-133-20741-00-00 BJM 11/24/25 DSR-11/13/25 BOP test to 3000 psi. Annular test to 2500 psi. Submit FIT/LOT results within 48 hrs of performing test. TS 12/1/25 Downhole commingling in this well not allowed without an order from the AOGCC 12/01/25 12/01/25 SRU 223-15 Drilling Program Swanson River Unit November 3rd, 2025 SRU 223-15 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................................................................................................29 18.0 3-1/2 Liner Tieback Polish Run................................................................................................34 19.0 3-1/2 Tieback Run, ND/NU, RDMO.........................................................................................35 20.0 CBL and Nitrogen Operation (Post Rig Work)........................................................................36 21.0 Diverter Schematic ......................................................................................................................39 22.0 BOP Schematic.............................................................................................................................40 23.0 Wellhead Schematic.....................................................................................................................41 24.0 Anticipated Drilling Hazards......................................................................................................42 25.0 Hilcorp Rig 169 Layout...............................................................................................................44 26.0 FIT/LOT Procedure ....................................................................................................................45 27.0 Choke Manifold Schematic.........................................................................................................46 28.0 Casing Design Information.........................................................................................................47 29.0 6-3/4 Hole Section MASP..........................................................................................................48 30.0 Spider Plot w/ 660 Radius for SSSV.........................................................................................49 31.0 Surface Plat (As-Built NAD27 & NAD83).................................................................................50 Page 2 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 1.0 Well Summary Well SRU 223-15 Pad & Old Well Designation SRU TS pad 12-15 Grassroots Well Planned Completion Type 3-1/2 Production Liner w/Tieback (monobore) Target Reservoir(s) Sterling/Beluga/Tyonek Planned Well TD, MD / TVD 7772 MD / 7522 TVD PBTD, MD / TVD 7712 MD / 7453 TVD AFE Drilling Days 16 AFE Completion Days 3 Maximum Anticipated Pressure (Surface) 2482 psi Maximum Anticipated Pressure (Downhole/Reservoir) 3234 psi Work String 4-1/2 16.6# S-135 CDS-40 RKB 335.3 Ground Elevation 316.8 BOP Equipment 11 5M Annular BOP 11 5M Double Ram 11 5M Single Ram Page 3 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 2.0 Management of Change Information Page 3 Version 1.0 December 1, 2025 SRU 223-15 Drilling Procedure 2.0 Management of Change Information Page 4 Version 0.0 November 4, 2025 SRU 223-15 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 8.50029.7 L-80 GBCD 6890 4790 683 Prod 6-3/4 3-1/2 2.992 2.867 4.2509.2 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 4-1/23.826 2.6875 5.2516.6 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 4 Version 1.0 December 1, 2025 SRU 223-15 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 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 November 4, 2025 SRU 223-15 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 November 4, 2025 SRU 223-15 Drilling Procedure 6.0 Planned Wellbore Schematic Page 6 Version 1.0 December 1, 2025 SRU 223-15 Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 7.0 Drilling / Completion Summary SRU 223-15 is an S-shaped directional grassroots development well to be drilled from Swanson River TS pad 12-15. 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 ~16 deg. and TD of the well will be 7772 TMD/ 7522 TVD. Vertical separation will be 1967 ft. Drilling operations are expected to commence approximately January1 st, 2026. The Hilcorp Rig #169 will be used to drill the wellbore and run and cement casing. Surface casing will be run to 3,213 MD / 3,122 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 Kenai 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 (12.3# 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 + mudlogging (gas log only, no samples) Page 8 Version 0.0 November 4, 2025 SRU 223-15 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 223-15. 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 8 Version 1.0 December 1, 2025 SRU 223-15 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 223-15. 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. AOGCC Regulation Variance Requests: Test 7-5/8 casing to 3500 psi (50% of burst is 4735 psi). P-110 casing is being run due to inventory constraints and is not needed for the design requirements. 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 November 4, 2025 SRU 223-15 Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/821-1/4 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 November 4, 2025 SRU 223-15 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 November 4, 2025 SRU 223-15 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 November 4, 2025 SRU 223-15 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. Page 13 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 10.5 Estimated diverter line orientation on SRU Pad 12-15 (orientation is subject to change on location): Page 14 Version 0.0 November 4, 2025 SRU 223-15 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 3,213 MD/ 3,122 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 drillers console, Co Man office, Toolpusher office, and mud loggers office. Page 15 Version 0.0 November 4, 2025 SRU 223-15 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 November 4, 2025 SRU 223-15 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 ODs, IDs, lengths, S/Ns 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 November 4, 2025 SRU 223-15 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 17 Version 1.0 December 1, 2025 SRU 223-15 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 November 4, 2025 SRU 223-15 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 Halliburtons 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 November 4, 2025 SRU 223-15 Drilling Procedure Estimated Total Cement Volume: Verified cement calcs. -bjm Page 20 Version 0.0 November 4, 2025 SRU 223-15 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 November 4, 2025 SRU 223-15 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. 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 November 4, 2025 SRU 223-15 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 VBRs 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 November 4, 2025 SRU 223-15 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 4-1/2 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 drillers 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 November 4, 2025 SRU 223-15 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 12.3# 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 BHA. Perform 10 minute flowchecks prior to tripping off bottom, prior to tripping above the surface shoe, and prior to laying down the BHA. Page 24 Version 1.0 December 1, 2025 SRU 223-15 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 12.3# 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 deemed necessary. 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 BHA. Page 25 Version 0.0 November 4, 2025 SRU 223-15 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 ODs, IDs, lengths, S/Ns 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 November 4, 2025 SRU 223-15 Drilling Procedure Page 27 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure Page 28 Version 0.0 November 4, 2025 SRU 223-15 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 29 Version 0.0 November 4, 2025 SRU 223-15 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 Halliburtons 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 recipe below. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Page 30 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure Estimated Total Cement Volume: Verified cement calcs. -bjm Page 31 Version 0.0 November 4, 2025 SRU 223-15 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 32 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 17.16. Remove running tool from TOL per vendor procedure. 17.17. 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. 17.18. RD cementers and flush equipment. POOH, LDDP and running tool. Backup release from liner hanger (verify with service company rep): 17.19. 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. 17.20. NOTE: Some hole conditions may require movement of the drillpipe to work the torque down to the setting tool. 17.21. 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. 17.22. WOC until the compressive strength hits at least 500 psi before testing casing to 3000 psi and chart for 30 minutes. Contingency Cement Downsqueeze 17.23. If the well experiences total lost circulation and the primary cement job is pumped with no returns, a contingency cement downsqueeze may be performed. Contact drilling engineer to confirm. Do not set the LTP. Release from the liner and POOH to pickup the downsqueeze assembly. 17.24. TIH and pump the downsqueeze per Halliburton cementers. Set the liner top packer. Circulate the hole clean. POOH for polish mill run. Page 33 Version 0.0 November 4, 2025 SRU 223-15 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 34 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 18.0 3-1/2 Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy per vendor 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 35 Version 0.0 November 4, 2025 SRU 223-15 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 36 Version 0.0 November 4, 2025 SRU 223-15 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 (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 37 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure Page 38 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure Page 39 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 21.0 Diverter Schematic Page 40 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 22.0 BOP Schematic Page 41 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 23.0 Wellhead Schematic Page 42 Version 0.0 November 4, 2025 SRU 223-15 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 43 Version 0.0 November 4, 2025 SRU 223-15 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 44 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 25.0 Hilcorp Rig 169 Layout Page 45 Version 0.0 November 4, 2025 SRU 223-15 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 46 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 27.0 Choke Manifold Schematic Page 47 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 28.0 Casing Design Information Page 47 Version 1.0 December 1, 2025 SRU 223-15 Drilling Procedure 28.0 Casing Design Information Page 48 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 29.0 6-3/4 Hole Section MASP Page 49 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 30.0 Spider Plot w/ 660 Radius for SSSV Page 50 Version 0.0 November 4, 2025 SRU 223-15 Drilling Procedure 31.0 Surface Plat (As-Built NAD27 & NAD83) Page 51 Version 0.0 November 4, 2025 SRU 223-15 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. STERLING/UPPER BELUGA GAS BELUGA GAS TYONEK GAS SRU 223-15 SWANSON RIVER 225-123 WELL PERMIT CHECKLISTCompany Hilcorp Alaska, LLCWell Name: SWANSON RIV UNIT 223-15Initial Class/TypeDEV / PENDGeoArea820 Unit 51994On/Off ShoreOnProgram DEVWell bore segAnnular DisposalPTD#:2251230Field & Pool:SWANSON RIVER, TYONEK GAS - 772500, SWANSON RIVER, BELUGA GAS - 772520, SWANNA1 Permit fee attachedYes Entire Well lies within AKA 028406.2 Lease number appropriateYes3 Unique well name and numberYes CO required for comingling4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 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 waitNA14Well 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)No16 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 = 2482 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)Yes35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.43 psi/ft (8.3 ppg EMW)36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprTCSDate12/1/2025ApprBJMDate11/24/2025ApprTCSDate12/1/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 12/1/2025