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Home My WebLink About225-0711. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,425 N/A Casing Collapse Structural Conductor Surface 630psi Intermediate 2,090psi Production 4,320psi Liner 10,540psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Eric Dickerman Contact Email:Eric.Dickerman@hilcorp.com Contact Phone:(907) 564-4061 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Other: CTCO, N2 Operations CO 68A N Cook Inlet Tertiary System Gas Same 6,150 5,372 717psi N/A Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY 10,160psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 225-071 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20026-01-00 Hilcorp Alaska, LLC N Cook Inlet Unit A-06A Length Size Proposed Pools: L-80 TVD Burst 3,190 4,980psi MD 3,580psi 1,640psi 382' 623' 2,397' 382' 623' 2,991'7" 30" 16" 382' 10-3/4"2,579' 623' 3,300' Perforation Depth MD (ft): 2,579' 6,003 - 6,081 3,300' 3-1/2" 5,250 - 5,314 1/27/2026 B. McLellan Verbal for CT/N2 Lift 7,423'4,268' 3-1/2" 6,452' LTP & SSSV 3,155 (MD) 2,873 (TVD) & 436 (MD) 436 (TVD) Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2026.01.26 15:43:11 - 09'00' Dan Marlowe (1267) 326-059 By Grace Chistianson at 7:40 am, Jan 27, 2026 DSR-1/27/26TS 1/27/26 BOP test to 3000 psi X 10-404 BJM 2/6/26 02/06/26 N2 Lift & Add Perf Well: North Cook Inlet Unit A-06A Well Name:NCIU A-09A API Number:50-883-20026-01 Current Status:Online, Gas Well Leg:Leg #3 (SE corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:225-071 First Call Engineer:Eric Dickerman (907) 564-4061 Second Call Engineer:Dan Marlowe (907) 283-1329 Maximum Expected BHP:1,235 psi at 5,188 tvd 0.24 psi/ft BHP survey 1/24/26 Max. Potential Surface Pressure: 717 psi MPSP -0.1 psi/ft gas grad. to surface Field/Pool: North Cook Inlet Unit, Tertiary System Gas Pool Applicable Frac Gradient: 0.77 psi/ft using 14.9 ppg EMW 9/1/2025 LOT. Shallowest Allowable Perf TVD: MPSP/(Frac grad. Gas grad.) = 717 psi / (0.77 0.1 psi/ft) = 1,071 tvd Brief Well Summary: NCIU A-06A was drilled and completed in September 2025 targeting the Beluga formation within the North Cook Inlet field. Initial perforations found gas, however the well began to produce solids and was shut in. The well was cleaned out and production was attempted again, however the solids problem persisted, and the well was shut in. In November 2025, a bridge plug was set to plug off the intervals producing solids and additional perforations were added shallower in the well. The well was a steady producer until it failed an SVS test on 1/23/26 with the subsurface safety valve and the surface safety valve failing to hold differential pressure. Slickline brushed the subsurface safety valve and the surface safety valve was flushed with fluid on 1/23/26, and both subsequently passed in house performance tests. After the performance tests, the well would not flow, and a fluid level was logged at 5,300. Objective: N2 lift to kick well off. Add Beluga perforations. Return well to production. Wellbore information: North Cook Inlet Unit, Tertiary System Gas Pool top = Top of Sterling sands, at 3,586 md / 3,221 tvd. North Cook Inlet Unit, Tertiary System Gas Pool Bottom = Base of Beluga sands (below TD). N2 Lift & Add Perf Well: North Cook Inlet Unit A-06A Coiled Tubing N2 Blowdown: 1. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment. 2. Pressure test BOP and PCE to 250 psi low / 3,000 psi high. a. Provide AOGCC with 48 hr witness notification for BOP test. 3. MU nozzle BHA. 4. RIH and blow well dry with nitrogen. 5. RDMO CTU. Eline Perforate: 6. MIRU Eline. 7. Pressure test PCE to 250 psi low / 3,000 psi high. 8. Set 3-1/2 CIBP at ± 6,140. 9. Dump bail 25 of cement on top of CIBP. Target TOC ± 6,115. 10. Perforate the target intervals per the perf table below. All perforations are within the North Cook Inlet Unit, Tertiary gas pool. Tie in to the attached correlation log. Sand Interval Perforation Top (MD) Perforation Bottom (MD) Perforation Interval Footage (ft.) Beluga_Fc 5762 5764 2 Beluga_Fc 5775 5786 11 Beluga_Fc 5805 5820 15 Beluga_Gb 5879 5881 2 Beluga_Gb 5885 5899 14 Beluga_Gb 5903 5905 2 Beluga_Gb 5908 5917 9 Beluga_Ha 5959 5972 13 Beluga_Ha 5974 5980 6 Beluga_Ha 5988 5992 4 Beluga_Hc 6057 6067 10 Beluga_Hc 6071 6093 22 11. RDMO Eline. 12. Hand well over to Operations to flow test. If new perf intervals bring in unwanted solids or water execute the CONTINGENCY Eline plug and/or coil cleanout. CONTINGENCY Eline plug/patch: (if any zone makes unwanted solids or water) 13. RU Nitrogen to tubing and pressure test treating iron to 250 psi low / 3,000 psi high. 14. Pressure up on tubing to displace water back into formation. 15. MIRU Eline. 16. Pressure test PCE to 250 psi low / 3,000 psi high. N2 Lift & Add Perf Well: North Cook Inlet Unit A-06A 17. Set 3-1/2 CIBP or patch to shut off unwanted interval per Operations Engineer. b. If a 3-1/2 CIBP is set, dump bail 25 of cement on top of plug as allowed by perf interval. 18. RDMO Eline and Nitrogen. CONTINGENCY Coiled Tubing Cleanout/N2 Blowdown: (if any zone brings in excessive fill and needs to be cleaned out) 19. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment. 20. Pressure test BOP and PCE to 250 psi low / 3,000 psi high. c. Provide AOGCC with 48 hr witness notification for BOP test. 21. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to target depth per Operations Engineer. d. Working fluid will be 6% KCl (8.6 ppg). e. Take returns to surface from the coiled tubing by 3-1/2 annulus. f. Add foam and nitrogen as necessary to carry solids to surface. 22. RIH and blow well dry with nitrogen. 23. RDMO CTU. Attachments: 1. Correlation log 2. Current Wellbore Schematic 3. Proposed Wellbore Schematic 4. CT BOP Drawing 5. Nitrogen procedure N2 Lift & Add Perf Well: North Cook Inlet Unit A-06A Correlation Log: Target perf intervals CIBP and Cement Updated by JLL 01/26/26 SCHEMATIC North Cook Inlet Unit Tyonek Platform Well: NCI A-06A PTD: 225-071 API: 50-883-20026-01-00 PBTD: 6,150 TD: 7,423 7 30 RKB: MSL =126.6 RKB: Wellhead = 53.37 8 3 5/6 2 7 3-1/2 7Window @ 3,300 MD 4 16 10-3/4 A-06 Bel I Bel J Bel K Bel L Bel M Bel O Bel P Bel Q Bel H 1 CASING DETAIL SIZE WT GRADE CONN MIN ID Top Btm 30 Welded 28.000 Surf 382 16 65 H-40 Welded 15.062 Surf 623 10-3/4 50 H-40 BTC 9.850 Surf 2,579 7 26 J-55 BTC 6.272 Surf 3,300TOW 3-1/2 9.2 L-80 Hyd 563 2.992 3,155 7,423 3-1/2 9.2 L-80 EUE 2.992 Surf 3,190 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Bel Ha 6,003 6,009 5,250 5,255 3 11/30/25 Open Bel Hc 6,071 6,081 5,306 5,314 10 11/30/25 Open Bel Ia 6,158 6,186 5,378 5,042 28 09/27/25 Isolated 11/30/25 Bel Ib 6,200 6,203 5,414 5,416 3 09/27/25 Isolated 11/30/25 Bel Ic 6,216 6,226 5,427 5,435 10 09/27/25 Isolated 11/29/25 Bel Id 6,241 6,246 5,448 5,452 5 09/27/25 Isolated 11/29/25 Bel Ja 6,317 6,326 5,511 5,519 9 09/27/25 Isolated 11/29/25 Bel Jb 6,345 6,349 5,535 5,538 4 09/27/25 Isolated 11/29/25 Bel Jc 6,361 6,371 5,548 5,557 10 09/27/25 Isolated 11/29/25 Bel Jd 6,383 6,389 5,567 5,572 6 09/27/25 Isolated 11/29/25 Bel Ka 6,410 6,425 5,589 5,602 15 09/27/25 Isolated 11/29/25 Bel Kb 6,446 6,452 5,619 5,625 6 09/27/25 Isolated 11/29/25 Bel La 6,559 6,564 5,714 5,719 5 09/27/25 Isolated 11/29/25 Bel Lb 6,589 6,592 5,740 5,742 3 09/27/25 Isolated 11/29/25 Bel M 6,662 6,664 5,801 5,803 2 09/27/25 Isolated 11/29/25 Bel O 6,788 6,792 5,907 5,911 4 09/27/25 Isolated 11/29/25 Bel P 6,857 6,864 5,965 5,970 7 09/27/25 Isolated 11/29/25 Bel Qa 6,984 6,990 6,071 6,076 6 09/26/25 Isolated 11/29/25 Bel Qb 7,020 7,025 6,102 6,106 5 09/26/25 Isolated 11/29/25 Bel Qc 7,045 7,063 6,123 6,139 18 09/26/25 Isolated 11/29/25 Depth Item 3,661 10 Marker Joint 4,295 10 Marker Joint 4,927 RA Tag 5,529 RA Tag 6,132 RA Tag 6,736 RA Tag JEWELRY DETAIL No.Depth MD Depth TVD ID OD Item 1 436 436 2.812 5.20Baker S-5, TRSSSV, w/ 2.812 BX Profile 2 1,5861,563 2.992 5.20MO-1 VanOil GLM, 1 Dome, 16/64, 750 psi Psc 3 3,086 2,817 2.992 5.20MO-1 VanOil GLM, 1 OGLV, 24/64 4 3,141 2,862 2.813 4.533-1/2 X Nipple 5 3,155 2,873 2.992 5.25Liner hanger / LTP Assembly 6 3,190 2,902 2.992 5.25Baker Seal assembly 7 6,150 5,372 - -CIBP (11/30/25) 8 6,210 5,422 - -CIBP (11/29/25) Updated by JLL 01/26/26 PROPOSED North Cook Inlet Unit Tyonek Platform Well: NCI A-06A PTD: 225-071 API: 50-883-20026-01-00 PBTD: 6,150 TD: 7,423 8 30 RKB: MSL =126.6 RKB: Wellhead = 53.37 9 3 5/6 2 7 3-1/2 7Window @ 3,300 MD 4 16 10-3/4 A-06 Bel I Bel J Bel K Bel L Bel M Bel O Bel P Bel Q Bel H Bel F Bel G 7 1 CASING DETAIL SIZE WT GRADE CONN MIN ID Top Btm 30 Welded 28.000 Surf 382 16 65 H-40 Welded 15.062 Surf 623 10-3/4 50 H-40 BTC 9.850 Surf 2,579 7 26 J-55 BTC 6.272 Surf 3,300TOW 3-1/2 9.2 L-80 Hyd 563 2.992 3,155 7,423 3-1/2 9.2 L-80 EUE 2.992 Surf 3,190 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Bel Fc ±5,762' ±5,764' ±5,050' ±5,052' ±2 Future Proposed Bel Fc ±5,775' ±5,786' ±5,061' ±5,070' ±11 Future Proposed Bel Fc ±5,805' ±5,820' ±5,086' ±5,098' ±15 Future Proposed Bel Gb ±5,879' ±5,881' ±5,147' ±5,149' ±2 Future Proposed Bel Gb ±5,885' ±5,899' ±5,152' ±5,163' ±14 Future Proposed Bel Gb ±5,903' ±5,905' ±5,167' ±5,169' ±2 Future Proposed Bel Gb ±5,908' ±5,917' ±5,171' ±5,179' ±9 Future Proposed Bel Ha ±5,959' ±5,972' ±5,213' ±5,224' ±13 Future Proposed Bel Ha ±5,974' ±5,980' ±5,226' ±5,231' ±6 Future Proposed Bel Ha ±5,988' ±5,992' ±5,237' ±5,241' ±4 Future Proposed Bel Ha 6,003 6,009 5,250 5,255 3 11/30/25 Open Bel Hc ±6,057' ±6,067' ±5,294' ±5,303' ±10 Future Proposed Bel Hc ±6,071' ±6,093' ±5,306' ±5,324' ±22 Future Proposed Bel Hc 6,071 6,081 5,306 5,314 10 11/30/25 Open Depth Item 3,661 10 Marker Joint 4,295 10 Marker Joint 4,927 RA Tag 5,529 RA Tag 6,132 RA Tag 6,736 RA Tag JEWELRY DETAIL No.Depth MD Depth TVD ID OD Item 1 436 436 2.812 5.20Baker S-5, TRSSSV, w/ 2.812 BX Profile 2 1,5861,563 2.992 5.20MO-1 VanOil GLM, 1 Dome, 16/64, 750 psi Psc 3 3,086 2,817 2.992 5.20MO-1 VanOil GLM, 1 OGLV, 24/64 4 3,141 2,862 2.813 4.533-1/2 X Nipple 5 3,155 2,873 2.992 5.25Liner hanger / LTP Assembly 6 3,190 2,902 2.992 5.25Baker Seal assembly 7 ±6,140' ±5,363' - -CIBP w/25' cement 8 6,150 5,372 - -CIBP (11/30/25) 9 6,210 5,422 - -CIBP (11/29/25) Updated by JLL 01/26/26 PROPOSED North Cook Inlet Unit Tyonek Platform Well: NCI A-06A PTD: 225-071 API: 50-883-20026-01-00 ISOLATED PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Bel Ia 6,158 6,186 5,378 5,042 28 09/27/25 Isolated 11/30/25 Bel Ib 6,200 6,203 5,414 5,416 3 09/27/25 Isolated 11/30/25 Bel Ic 6,216 6,226 5,427 5,435 10 09/27/25 Isolated 11/29/25 Bel Id 6,241 6,246 5,448 5,452 5 09/27/25 Isolated 11/29/25 Bel Ja 6,317 6,326 5,511 5,519 9 09/27/25 Isolated 11/29/25 Bel Jb 6,345 6,349 5,535 5,538 4 09/27/25 Isolated 11/29/25 Bel Jc 6,361 6,371 5,548 5,557 10 09/27/25 Isolated 11/29/25 Bel Jd 6,383 6,389 5,567 5,572 6 09/27/25 Isolated 11/29/25 Bel Ka 6,410 6,425 5,589 5,602 15 09/27/25 Isolated 11/29/25 Bel Kb 6,446 6,452 5,619 5,625 6 09/27/25 Isolated 11/29/25 Bel La 6,559 6,564 5,714 5,719 5 09/27/25 Isolated 11/29/25 Bel Lb 6,589 6,592 5,740 5,742 3 09/27/25 Isolated 11/29/25 Bel M 6,662 6,664 5,801 5,803 2 09/27/25 Isolated 11/29/25 Bel O 6,788 6,792 5,907 5,911 4 09/27/25 Isolated 11/29/25 Bel P 6,857 6,864 5,965 5,970 7 09/27/25 Isolated 11/29/25 Bel Qa 6,984 6,990 6,071 6,076 6 09/26/25 Isolated 11/29/25 Bel Qb 7,020 7,025 6,102 6,106 5 09/26/25 Isolated 11/29/25 Bel Qc 7,045 7,063 6,123 6,139 18 09/26/25 Isolated 11/29/25 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review 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 Nitrogen Tank. 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 supplier 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 Tank. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 1/21/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260121 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 16RD 50133205540100 207125 12/3/2025 AK E-LINE PPROF T41253 BRU 211-35 50283201890000 223050 11/7/2025 AK E-LINE Perf T41254 BRU 213-26 50283201920000 223069 11/23/2025 AK E-LINE Perf T41255 BRU 213-26T 50283202040000 225038 11/4/2025 AK E-LINE Perf T41256 BRU 241-34S 50283201980000 224077 11/9/2025 AK E-LINE Perf T41257 BRU 241-34T 50283201810000 220052 11/6/2025 AK E-LINE Perf T41258 BRU 244-27 50283201850000 222038 12/13/2025 AK E-LINE Perf T41259 BRU 244-27 50283201850000 222038 12/19/2025 AK E-LINE StripGun T41259 GP ST 17586 9 50733204480000 193062 11/13/2025 AK E-LINE Perf T41260 IRU 241-01 50283201840000 221076 12/21/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/30/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/16/2025 AK E-LINE Plug T41261 IRU 241-01 50283201840000 221076 11/26/2025 AK E-LINE Plug/Perf T41261 KALOTSA 01 50133206570000 216132 11/19/2025 AK E-LINE Perf T41262 KBU 31-18 50133206490000 215024 11/8/2025 AK E-LINE Drift/PPROF T41263 KU 12-17 50133205770000 208089 11/14/2025 AK E-LINE StimGun T41264 LRU C-01RD 50283200610100 201168 11/27/2025 AK E-LINE RCT/Perf T41265 MPI 2-32 50029220840000 190119 12/10/2025 AK E-LINE LDL T41266 MPI 2-38 50029220900000 190129 12/5/2025 AK E-LINE LDL T41267 MPU H-16 50029232270000 204190 12/3/2025 AK E-LINE CBL T41268 MPU H-16 50029232270000 204190 11/19/2025 AK E-LINE TubingCut T41268 MPU I-14 50029232140000 204119 11/13/2025 AK E-LINE CBL T41269 NCIU A-06A 50883200260100 225071 11/28/2025 AK E-LINE Perf/Plug T41270 NCIU A-08 50883200280000 169063 12/2/2025 AK E-LINE GPT T41271 NCIU A-19 50883201940000 224026 12/16/2025 AK E-LINE GPT T41272 NCIU A-19 50883201940000 224026 12/12/2025 AK E-LINE GPT/Perf/Plug T41272 NCIU A-19 50883201940000 224026 12/17/2025 AK E-LINE Perf T41272 NCIU A-21A 50883201990100 225075 12/30/2025 AK E-LINE PPROF T41273 OP19-T1N 50029234910000 213068 11/19/2025 AK E-LINE TubingPunch T41274 NCIU A-06A 50883200260100 225071 11/28/2025 AK E-LINE Perf/Plug Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:35 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PCU D-10 50283202080000 225082 12/9/2025 AK E-LINE Perf T41275 SCU 322C-04 50133101040100 215217 12/4/2025 AK E-LINE TubingPunch T41276 SRU 222-33 50133207150000 223100 12/7/2025 AK E-LINE Plug T41277 SU 43-10 50133207390000 225107 11/26/2025 AK E-LINE CBL T41278 TBU A-12RD 50733200760100 171029 11/29/2025 AK E-LINE Perf T41279 TBU D-24A 50733202240100 174064 12/2/2025 AK E-LINE TubingPunch T41280 TBU D-24A 50733202240100 174064 11/21/2025 AK E-LINE TubingPunch T41280 TBU M-10 50733205880000 209154 11/15/2025 AK E-LINE Perf T41281 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:51 -09'00' 1 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Monday, January 26, 2026 4:01 PM To:Eric Dickerman Cc:Rixse, Melvin G (OGC) Subject:RE: PTD 225-071, NCIU A-06A, Sundry Program, Verbal Approval Request for N2 lift Eric, Verbal approval is granted for the CT N2 blowdown scope described in your email below. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Eric Dickerman <eric.dickerman@hilcorp.com> Sent: Monday, January 26, 2026 3:57 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: PTD 225-071, NCIU A-06A, Sundry Program, Verbal Approval Request for N2 lift Mr. McLellan, As discussed on the phone, Hilcorp is requesting verbal approval to perform a coiled tubing nitrogen lift on NCIU A-06A tomorrow. After SVS testing on 1/23/26 we have been unable to kick this well back oƯ. Today, Hilcorp submitted the attached sundry to execute eline perforations if the well does not return to production post Nitrogen Lift. A BOP test witness notification was sent and waived for this well, we will plan to BOP test as described in the attached sundry. Please let me know if you have any questions. 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 Thank you, Eric Dickerman Hilcorp – CIO Ops Engineer Cell: 307-250-4013 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. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/24/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251024 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BR 11-86 (REVISED) 50733207370000 225057 8/1/2025 HALLIBURTON RMT3D BRU 241-34T 50283201810000 220052 9/23/2025 AK E-LINE Perf END 2-36 50029220140000 190024 10/13/2025 READ Caliper Survey MPI 2-72 50029237810000 224016 10/2/2025 AK E-LINE Patch MPU I-01 50029220650000 190090 9/25/2025 AK E-LINE Punch MPU J-08A 50029224970100 199117 10/22/2025 HALLIBURTON COILFLAG MPU R-109 50029238220000 225073 9/24/2025 YELLOWJACKET SCBL NCIU A-06A 50883200260100 225071 9/25/2025 AK E-LINE CBL NCIU A-06A 50883200260100 225071 9/26/2025 AK E-LINE Perf PBU A-24B 50029207430200 225067 10/20/2025 HALLIBURTON RBT PBU GC-2E 50029227400000 197018 10/21/2025 HALLIBURTON TEMP PBU W-35A 50029217990200 225076 10/10/2025 HALLIBURTON RBT SP-03-NE2 50629236390000 219089 9/25/2025 AK E-LINE Caliper Please include current contact information if different from above. T41022 T41023 T41024 T41025 T41026 T41027 T41028 T41029 T41029 T41030 T41031 T41032 T41033 NCIU A-06A 50883200260100 225071 9/25/2025 AK E-LINE CBL NCIU A-06A 50883200260100 225071 9/26/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.24 13:32:55 -08'00' 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: 10/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: NCIU A-06A PTD: 225-071 API: 50-883-20026-01-00 FINAL LWD FORMATION EVALUATION LOGS (08/28/2025 to 09/15/2025) x ROP, ADR, PCG, ALD, CTN (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer – Data Main Folders: Please include current contact information if different from above. 225-071 T40965 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.08 09:02:50 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): ±7,425 (proposed)N/A Casing Collapse Structural Conductor Surface 630psi Intermediate 2,090psi Production 4,320psi Liner 10,540psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Eric Dickerman Contact Email:Eric.Dickerman@hilcorp.com Contact Phone:(907) 564-4061 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 September 18, 2025 ±7,425 (proposed)±4,325 (proposed) 3-1/2" ±6,427 (proposed) LTP & SSSV ±3,100 (MD) ±2,141 (TVD) & ±450 (MD) ±450 (TVD) ±3,300 (proposed) Perforation Depth MD (ft): 2,579' See schematic ±3,300 (proposed) 3-1/2" See schematic ±2,283 (proposed)7" 30" 16" 382' 10-3/4"2,579' 623' MD 3,580psi 1,640psi 382' 623' 2,397' 382' 623' Length Size Proposed Pools: L-80 TVD Burst ±3,100 (proposed) 4,980psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 225-071 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20026-01-00 Hilcorp Alaska, LLC N Cook Inlet Unit A-06A AOGCC USE ONLY 10,160psi Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Other: Initial Completion, N2 CO 68A N Cook Inlet Tertiary System Gas Same ±6,427 (proposed)±7,400 (proposed)±5,189 (proposed)~2,635 psi N/A m n P s 2 6 5 6 t 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 1:13 pm, Sep 04, 2025 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.09.04 12:59:12 - 08'00' Dan Marlowe (1267) 325-545 * BOPE pressure test to 3500 psi. 48 hour notice to AOGCC for opportunity to witness. 10-407 MGR05SEP2025 DSR-9/10/25 TOC from CBL to be confirmed by AOGCC prior to perforating A.Dewhurst 18SEP25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.09.19 09:58:18 -08'00'09/19/25 RBDMS JSB 092625 Initial Completion Well: North Cook Inlet Unit A-06A Well Name: NCIU A-06A API Number: 50-883-20026-01-00 Current Status: New drill gas well Leg: Leg #3 (SE corner) Regulatory Contact: Juanita Lovett (8332) Permit to Drill Number: 225-071 First Call Engineer: Eric Dickerman (907) 564-4061 Second Call Engineer: Casey Morse (907) 777-8322 Maximum Expected BHP: 3,278 psi at 6,427’ TVD - 0.51 psi/ft – 10-401 Section 26, pg 34 Max. Potential Surface Pressure: 2,635 psi MPSP - 0.1 psi/ft gas grad. to surface – 10-401 Section 26, pg 34 Field/Pool: North Cook Inlet Unit, Tertiary System Gas Pool Applicable Frac Gradient: 0.78 psi/ft using 15.0 ppg EMW – 10-401 Section 26, pg 34 Shallowest Allowable Perf TVD: MPSP/(Frac grad. – Gas grad.) = 2,635 psi / (0.78 – 0.1 psi/ft) = 3,875’ TVD Brief Well Summary: Spartan 151 is currently drilling NCIU A-06A. The primary target is the Beluga sands, with a future option to test the Sterling sands. The well exited the existing 7” casing at 3,300’, and is currently drilling the 6-1/8” production hole to a target TD of ± 7,425’ MD. After milling the window, an FIT was performed to 14.7 ppg. The production interval will be cased with a 3-1/2” production liner. The upper completion is planned to be a 3-1/2” tieback. Objective: Initial completion post rig. Confirm CBL, actual Pool top and bottom, and shallowest allowable perf TVD approval from AOGCC before perforating. Wellbore information: x A 7” x 3-1/2” liner lap test, a 3-1/2” MIT-T, and a 7” x 3-1/2” MIT-IA will be performed to 2,050 psi on the rig per the approved 10-401. x The well will be completed with a tubing retrievable subsurface safety valve set at ± 400’. x Plan to run tubing string with live gas lift valves. x North Cook Inlet Unit, Tertiary System Gas Pool top = Top of Sterling sands, estimated at 3,587’ MD / 3,236’ TVD from prognosis. x North Cook Inlet Unit, Tertiary System Gas Pool Bottom = Base of Beluga sands. Initial Completion Well: North Cook Inlet Unit A-06A Coiled Tubing and Eline Procedure: 1. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment. 2. Pressure test BOP and PCE to 250 psi low / 3,500 psi high. a. Provide AOGCC with 48 hr witness notification for BOP test. 3. MU cleanout BHA. 4. RIH to PBTD and circulate the well from drilling mud to filtered inlet water. 5. Standback coiled tubing. 6. MIRU Eline. 7. Pressure test PCE to 250 psi low / 3,500 psi high. 8. Log CBL from PBTD to top of production liner (estimated at 3,100’). a. Submit CBL to AOGCC for approval prior to perforating. 9. RDMO Eline. 10. Stab coiled tubing lubricator back on well. 11. Pressure test PCE to 250 psi low / 3,500 psi high. 12. If Eline is unable to log CBL, RIH with CBL toolstring in carrier then log from PBTD to top of production liner (estimated at 3,100’). Submit CBL to AOGCC for approval. 13. RIH and blow well dry with nitrogen. 14. RDMO CTU. Eline Perf procedure – Pending AOGCC approval after CBL review 15. MIRU Eline and Nitrogen package. 16. Pressure test PCE and N2 treating iron to 250 psi low / 3,500 psi high. 17. Confirm CBL, actual Pool top and bottom, and shallowest allowable perf TVD approval from AOGCC before perforating. 18. Perforate target gas sands in the North Cook Inlet Unit Tertiary Systems Gas Pool per Reservoir Engineer/Geologist. a. Top pool = 3,587’ MD / 3,236’ TVD. b. Bottom pool = deeper than TD. c. Use Nitrogen to pressurize wellbore to target shooting pressure. 19. RDMO Eline and Nitrogen. CONTINGENCY Eline plug/patch: (if any zone makes unwanted solids or water) 20. RU Nitrogen to tubing and pressure test treating iron to 250 psi low / 3,500 psi high. 21. Pressure up on tubing to displace water back into formation. 22. MIRU Eline. 23. Pressure test PCE to 250 psi low / 3,500 psi high. 24. Set 3-1/2” CIBP or patch to shut off unwanted interval per Operations Engineer. 25. RDMO Eline and Nitrogen. CONTINGENCY Coiled Tubing Cleanout: (if any zone brings in excessive fill and needs to be cleaned out) 26. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment. 27. Pressure test BOP and PCE to 250 psi low / 3,500 psi high. a. Provide AOGCC with 48 hr witness notification for BOP test. Initial Completion Well: North Cook Inlet Unit A-06A 28. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to target depth per Operations Engineer. a. Working fluid will be 6% KCl (8.6 ppg). b. Take returns to surface from the coiled tubing by 3-1/2” annulus. c. Add foam and nitrogen as necessary to carry solids to surface. 29. RIH and blow well dry with nitrogen. 30. RDMO CTU. Operations: 31. Perform SVS test within 5 days. Attachments: 1. Proposed Wellbore Schematic 2. CT BOP Drawing 3. Nitrogen procedure Updated by DMA 09-04-25 PROPOSED SCHEMATIC North Cook Inlet Unit Tyonek Platform Well: NCI A-06A PTD: 225-071 API: 50-883-20026-01-00 JEWELRY DETAIL No.Depth Item 1 ±400’SSSV 2 ±1,900’GLM 3 ±3,050’GLM 4 ±3,100’Seal Stem 5 ±3,100’Liner hanger / LTP Assembly CASING DETAIL SIZE WT GRADE CONN MIN ID Top Btm 30”Welded 28.000 Surf 382’ 16”65 H-40 Welded 15.062 Surf 623’ 10-3/4”50 H-40 BTC 9.850 Surf 2,579’ 7”26 J-55 BTC 8.535 Surf ±3,300’TOW 3-1/2”9.2 L-80 Hyd 563 3.958 3,100’7,425’ 3-1/2”9.2 L-80 EUE 3.958 Surf 3,100’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Tertiary System Gas Pool ±3,587’ PBTD ±3,236’PBTD Future Proposed KLU A-1 Well Head Rig Up 1 1 1 1 4 1/16" 15K Lubricator - 10 ft 100" Gooseneck HR680 Injector Head 4 1/16" 10K Flow Cross, 2" 1502 10k Flanged Valves 4 1/16" 15K Lubricator - 10 ft API Flange Adapter 10K to 5K for riser/wellhead Hydraulic Stripper 4 1/6" 15K API Bowen CB56 15K 4 1/16" 10K Combi BOPs Blind/Shear Ram Pipe/Slip Ram 4 1/16" 10K bottom flange 4 1/16" 5K flanged Riser - 10 ft if necessary STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review 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 Nitrogen Tank. 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 supplier 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 Tank. 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: North Cook Inlet Unit Field, Tertiary System Gas Pool, NCIU A-06A Hilcorp Alaska, LLC Permit to Drill Number: 225-071 Surface Location: 1259' FNL, 1085' FWL, Sec 6, T11N, R9W, SM, AK Bottomhole Location: 2557' FSL, 1527' FEL, Sec 1, T11N, R10W, 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 11th day of August 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.08.11 09:12:26 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 7,425' TVD: 6,427' 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): 126.6 15. Distance to Nearest Well Open Surface: x-332104 y-2586719 Zone-4 N/A to Same Pool:1802' to NCIU A-04A 16. Deviated wells:Kickoff depth: 3,300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 36 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 6-1/8" 3-1/2" 9.2# L-80 Hyd 563 4,325' 3,100' 2,829' 7,425' 6,427' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): 4711 TVD 382' 623' 2397' 6866' Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 8/23/2025 6392' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 8328 Cement Volume MD Driven 382' 623'16"575 sx 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): 623' 2579' 1107 sx To be plugged Conductor/Structural 30"382' Authorized Title: Authorized Signature: Authorized Name: Production Liner 2579' 8016' Intermediate 8,045 6892 LengthCasing 4717 Size Plugs (measured): (including stage data) L - 727 ft3 / T - 101 ft3 6380 5,503 Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 3278 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 2635 2493' FNL, 463' FWL, Sec 6, T11N, R9W, SM, AK 2557' FSL, 1527' FEL, Sec 1, T11N, R10W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1259' FNL, 1085' FWL, Sec 6, T11N, R9W, SM, AK ADL 17589 / ADL 37831 NCIU A-06A North Cook Inlet Unit Tertiary System Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. To be plugged 709 sx 8016'7" 10-3/4" s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 3:48 pm, Jul 24, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.07.24 10:16:22 - 08'00' Sean McLaughlin (4311) 50-883-20026-01-00 * BOPE pressure test to 3000 psi. Annular to 2500 psi. 48 hour notice. * Email casing test and FIT digital data to AOGCC immediately upon completion for FIT. MGR03AUG2025 A.Dewhurst 04AUG25 DSR-7/24/25 225-071 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.08.11 09:12:37 -08'00'08/11/25 08/11/25 RBDMS JSB 081425 A-06A Drilling Program Tyonek Sean McLaughlin PTD June 30, 2025 NCI A-06A Drilling Program Contents 1. Well Summary.....................................................................................................................................2 2. Management of Change Information................................................................................................3 3. Tubular Program:...............................................................................................................................4 4. Drill Pipe Information:.......................................................................................................................4 5. Internal Reporting Requirements.....................................................................................................5 6. Current Wellbore Schematic.............................................................................................................6 7. Planned Wellbore Schematic.............................................................................................................8 8. Drilling Summary...............................................................................................................................9 9. Mandatory Regulatory Compliance / Notifications.......................................................................10 10. BOP N/U and Test.............................................................................................................................12 11. Preparatory Work and Mud Program............................................................................................12 12. Decomplete, Plug parent wellbore...................................................................................................14 13. Set Whipstock, Mill Window...........................................................................................................14 14. Drill 6-1/8” Hole Section...................................................................................................................16 15. Run 3-1/2” Production Liner...........................................................................................................17 16. Cement 3-1/2” Production Liner.....................................................................................................19 17. Wellbore Clean Up & Displacement...............................................................................................22 18. Run Completion Assembly...............................................................................................................22 19. BOP Schematic..................................................................................................................................23 20. Wellhead Schematic..........................................................................................................................24 21. Anticipated Drilling Hazards...........................................................................................................25 22. Jack up position ................................................................................................................................26 23. FIT Procedure...................................................................................................................................27 24. Choke Manifold Schematic..............................................................................................................28 25. Casing Design Information ..............................................................................................................30 26. 6-1/8” Hole Section MASP ...............................................................................................................31 27. Plot (NAD 27) (Governmental Sections).........................................................................................32 28. Slot Diagram......................................................................................................................................33 29. Directional Program (wp08) - Attached separately......................................................................34 Page 2 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 1. Well Summary Well NCI A-06A Drilling Rig Rig 151 Leg 3 Directional plan wp08 Pad & Old Well Designation Sidetrack of existing well A-06 (PTD#169-050) Planned Completion Type 3-1/2” 9.2# Liner, 3-1/2” Tubing Comp Target Reservoir(s)Beluga A-T Kick off point 3318’ MD (3300’ planned in wp08) Planned Well TD, MD / TVD 7425’ MD / 6427’ TVD PBTD, MD 7325’ MD AFE Number AFE Days AFE Drilling Amount Work String 4.5” 16.6# S-135 CDS40 RKB – AMSL 126.6’ MSL to ML 73.1’ Page 3 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 2. Management of Change Information Date: June 30, 2025 Subject: Changes to Approved Permit to Drill File #: NCI A-06A Drilling Program Significant modifications to Drilling Program for PTD will be documented and approved below. Significant changes to an approved PTD will be communicated and approved by the AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approved By Approval: Drilling Manager Date Prepared: Engineer Date Page 4 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 3. Tubular Program: Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Prod 6-1/8”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 ** Liner must overlap casing by at least 100’. 4. 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 Page 5 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 5. Internal Reporting Requirements 1. Fill out daily drilling report and cost report. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. This helps later when aggregating end of well reports. 2. Afternoon Updates x Submit a short operations update every day to Kenai/CIO Drilling <KenaiCIODrilling@hilcorp.com> 3. EHS Incident Reporting x Notify EHS field coordinator. i. Garrett St. Clair: C: (907) 252-7780 x Spills: i. Adrian Kersten: C: 907-564-4820 ii. Sean Mclaughlin x Report ALL spills to the water within 15 minutes. x Submit Hilcorp Incident report to contacts above within 24 hrs 4. Casing Tally x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com 5. Casing and Cmt report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com Page 6 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 6. Current Wellbore Schematic Page 7 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx Page 8 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 7. Planned Wellbore Schematic Page 9 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 8. Drilling Summary A-06 is a shut in gas well with all opportunities exhausted. Well planned to be sidetracked to down-space the producing Beluga formations. The 4-1/2” tubing will be cut and pulled prior to running a 7” cement retainer. The parent will be plugged with cement above and below the retainer. The parent wellbore will be sidetracked and new wellbore drilled to 7425’. A 3-1/2” L-80 prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with a 3-1/2” gas lift tie-back completion. Drilling operations are expected to commence approximately August 1, 2025. 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 pertaining to this drilling operation: Pre - Rig 1. Eline – Cut 4-1/2” tubing @ 3860’ Rig 2. Rig 151 will MIRU over Leg 3, Well A-06 (Sundry Ļ) 3. NU BOPE and test to 3000 psi. (MASP 2034psi) 4. Pull 4-1/2” tubing from the pre-rig cut at 3860’ 5. Set 7’ 23# cement retainer at 3850’, plug parent well with cement 6. Test 7” casing to 2050 psi. 7. Set 7” whipstock at 3318’ and 150R. Swap well to 9.0 ppg LSND mud. 8. Mill window with 20’ of new formation. (Permit To Drill Ļ) 9. Perform FIT to 14.7 ppg EMW 10. PU 4-3/4” motor drilling assembly and TIH to window. 11. Drill 6-1/8” production hole to 7425’ MD, performing short trips as needed 12. Run openhole logs on eline (ECS and FMI). Cleanout as needed 13. RIH w/ 3-1/2” liner. Set liner and cement. 14. Perform liner lap test to 2050 psi. 15. Run 3-1/2” completion. 16. Land hanger and test. 17. ND BOPE, NU tree and test void Reservoir Evaluation Plan: 1. Production Hole: Triple Combo LWD Perform liner lap test to 2050 psi. Test 7” casing to 2050 psi. Page 10 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 9. Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. o The highest reservoir pressure expected is 3278 psi in the Beluga S/T sands (6427' TVD). MASP is 2034 psi with 0.1psi/ft gas in the wellbore. o A casing test to 3000 psi is planned after plugging the parent x Rated Working Pressure (RWP) the BOPE and wellhead must meet or exceed: 3000 psi. x If the BOP is used to shut in on the well in a well control situation, ALL BOP components utilized for well control must be tested prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Page 11 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 6-1/8” x 13-5/8” Shaffer 5M annular x 13-5/8” 5M Shaffer SL Double gate x Blind ram in bottom cavity x Mud cross x 13-5/8” 5M Shaffer SL single gate x 3-1/16” 5M Choke Manifold x Standpipe, floor valves, etc Initial Test: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) x Primary closing unit: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex electric driven pump Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48 hours notice prior to full BOPE test. x Any other notifications required in APD conditions of approval. 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 / (C): 907-250-9193 / Email: bryan.mclellan@alaska.gov Melvin Rixse / Petroleum Engineer / (O): 907-793-1231 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 12 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 10. BOP N/U and Test 1. N/D Tree and adapter (BPV installed as part of pre-rig work), Install blanking plug 2. N/U to 16-3/4 5M clamp hub 3. N/U 13-5/8” x 5M BOP as follows (top down): x 13-5/8” x 5M Shaffer annular BOP. x 13-5/8” Shaffer Type “SL” Double ram. (2-7/8” X 5” VBR in top cavity, blind ram in btm cavity) x 13-5/8” mud cross x 13-5/8” Shaffer Type “SL” single ram. (2-7/8” X 5” VBR) x N/U pitcher nipple, install flowline. x Install (2) manual valves on kill side of mud cross. Manual valve used as inside or “master valve”. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. x 16-3/4” 5M Clamp hub adapter required 4. Test BOPE. x Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not build up beneath the TWC. Confirm the correct valves are opened!!! x Test VBRs on 3.5” and 4.5”test joints (3000 psi) x Test Annular on 3.5” test joint (2500 psi) x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 5. Pull Blanking plug and BPV 11. Preparatory Work and Mud Program 1. Mix 9.0 WBM mud for 6-1/8” hole section. 2. 6” liners installed in mud pump #1 and pump #2. (PZ-10’s) x Gardner Denver PZ-10’s Pumps are rated at 4932 psi (98%) with 6” liners and can deliver 422 gpm at 115 spm. x Pump range for drilling will be 150-300 gpm. This can be achieved with one or both pumps. Page 13 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 3. 6-1/8” Production hole mud program summary: x Primary weighting material to be used for the hole section will be barite to minimize solids. Ensure enough barite is on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. x Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. System Type: LNSD WBM Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 3318’- TD 8.8-10.3 40-53 6-15 13-24 8.5-9.5 11.0 System Formulation: 2% KCL/BDF-976/GEM GP Product Concentration Water KCl Caustic BARAZAN D+ DEXTRID LT PAC L BDF-976 GEM GP BARACARB 5/25/50 STEELSEAL 50/100/400 BAROFIBRE BAROTROL PLUS SOLTEX BAROID 41 ALDACIDE-G 0.905 bbl 7 ppb 0.2 ppb (9 pH) 1.0 ppb (as required 18 YP) 1-2 ppb 1 ppb 4 ppb 1.0% by volume 5 ppb (1.7 ppb of each) 5 ppb (1.7 ppb of each) 1.7 ppb 4.0 ppb 2 – 4 ppb as needed 0.1 ppb Page 14 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 4. Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP’s from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. 5. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation. 12. Decomplete, Plug parent wellbore Operation Steps: 1. Pull 4-1/2” tubing from the pre-rig cut at 3860’ 2. Set wear bushing in wellhead. Ensure ID of wear bushing > 6-1/8”. 3. PU 7” cement retainer and set at 3850’ 4. Pump 70 bbls of 15.3# below the retainer x 2x volume of 7” from 4731’ to 3850’ 5. Unsting from retainer and lay in ~200’ of cement above the retainer (~8 bbls) x Annular 7” cement at 2500’ per 05/27/1969 CBL 6. WOC, Tag cement 7. Pressure test 7” casing to 2050 psi. x 7” 23# J-55 Burst = 4360 psi 13. Set Whipstock, Mill Window Operation Steps: 1. Make up the WIS hydraulic set Whipstock. 2. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock assembly ¾Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly. ¾Avoid sudden starts and stops while running the whipstock. cement retainer and set at 3850’ Page 15 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx ¾Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly when releasing the work string to RIH. These precautions are required to avoid any weakening of the whipstock shear mechanisms and / or to avoid part / preset on the packer. 3. Orient whipstock as directed by the directional driller. The directional plan specifies 150 deg ROHS. 4. Set the top of the whipstock at ~3,318’ MD x 7” Collar at 3308’ x Ref log: NCIU A-06 CBL 05/27/1969 5. Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING THE PLANNED FIT/LOT). ¾Use ditch magnets to collect the metal shavings. Clean regularly. ¾Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and Kevlar gloves. ¾Work the upper mill through the window to confirm the window milling is complete and circulate well clean (circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface. 6. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a FIT to 14.7 ppg. ¾**Assuming the kick zone is at TD, a FIT of 14.7 ppg EMW gives a Kick Tolerance volume of 22 bbls with 10.3 ppg mud weight. 7. POOH and LD milling assembly ¾Once out of the hole, inspect mill gauge and record. ¾Flow check well for 10 minutes to confirm no flow: ¾Before pulling off bottom. ¾Before pulling the BHA through the BOPE. 8. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP equipment is operable. Email casing test and FIT digital data to AOGCC upon completion of FIT. - mgr Page 16 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 14. Drill 6-1/8” Hole Section 1. PU 7500’ of 4-1/2” CDS40 Drill pipe for drilling 6-1/8” hole section 2. P/U 4-3/4” Sperry Sun motor drilling assy x Drill 200’ of rathole prior to picking up LWD to avoid tool damage across the window. 3. Ensure BHA Components have been inspected previously. 4. Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 5. Ensure TF offset is measured accurately and entered correctly into the MWD software. 6. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at 150 - 300 gpm. 7. Production section will be drilled with a motor. Must keep up with 4 deg/100 DLS in the build and drop sections of the wellbore. 8. Primary bit will be the 6-1/8” Hycalog A1. Ensure to have a backup PDC bit available on location. 9. TIH to window. Shallow test MWD on trip in. 10. Circulate well with 9.0 ppg LNSD to warm up mud until good 9.0 ppg in and out. 11. Drill approx. 200’ rat hole to accommodate the LWD assembly. Ream window as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through shoe checking for drag. 12. Circulate Bottoms Up until MW in = MW out. 13. Trip to surface to pick up triple combo (DEN, POR, RES). 14. Drill 6-1/8” hole to 7425’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. x Adjust MW as necessary to maintain hole stability. x Ensure mud engineer set up to perform HTHP fluid loss. x Maintain API fluid loss < 6. x Take MWD surveys every stand drilled. x Minimize backreaming when working tight hole Page 17 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 15. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and pull a wiper trip back to the window. 16. TOH with drilling assembly, handle BHA as appropriate. 17. RU eline to run ECS (elemental capture spectroscopy) and FMI (formation image) logs 18. Clean out wellbore as needed. 15. Run 3-1/2” Production Liner 1. R/U Baker 3-1/2” liner running equipment. x Ensure 4-1/2” CDS-40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill liner while running. x Ensure all liner has been drifted and tally verified prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x Landing collar pup bucked up. x Centralizers will be run on 3-1/2” liner x Ensure proper operation of float shoe & FC. 4. Continue running 3-1/2” production liner to TD x Short joint run every 1000’ x Fill liner while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 18 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 5. Ensure to run enough liner to provide at least 100’ overlap inside casing. Ensure setting sleeve will not be set in a connection. Page 19 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 6. Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 7. M/U Baker ZXP liner top packer. Fill liner tieback sleeve with “XANPLEX”, ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 8. RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 9. RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 10. M/U top drive and fill pipe while lowering string every 10 stands. 11. Set slowly in and pull slowly out of slips. 12. Circulate 1-1/2 drill pipe and liner volume at 7” window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 15. P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 16. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. 16. Cement 3-1/2” Production Liner 1. Hold a pre-job safety meeting over the upcoming cmt operations. 2. Attempt to reciprocate the casing during cmt operations until hole gets sticky. 3. Pump 15 bbls 12.5 ppg spacer. 4. Test surface cmt lines to 4500 psi. 5. Pump remaining 10 bbls 12.5 ppg spacer. Page 20 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 6. Mix and pump per below recipe and volume with xx lbs/bbl of loss circulation fiber. Please independently verify cement volume with actual inputs. Ensure cmt is pumped at designed weight. Job is designed to pump 40% OH excess but if wellbore conditions dictate otherwise decrease or increase excess volumes. Cement volume is designed to bring cement to TOL. 7. Displacement fluid will be CLEAN drilling mud. Program displacement volume 104 bbls. Please independently verify with actual inputs. Slurry Information: 8. Drop DP dart and displace with clean 10.3 ppg WBM. 9. Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.3 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Cement Displacement = ((7425-3100- 80) * .0087) + (3100 * .01422) = 81 bbls - mgr Page 21 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 10. 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. Reduce pump rate as required to avoid packoff. 11. Bump the plug. Do not overdisplace by more than 2 bbls. 12. Pressure up to 4200 psi to release the running tool (HRD-E) from the liner 13. Bleed pressure to zero to check float equipment. 14. P/U, verify setting tool is released. 15. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 16. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17. 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. 18. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 19. POOH, LDDP. Backup release from liner running tool: 20. If the HRD-E 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. 21. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 22. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 22 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx Ensure to report the following on Wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if liner is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Note: Send Csg & cmt report + “As-Run” liner tally to sean.mclaughlin@hilcorp.com 17. Wellbore Clean Up & Displacement 1. No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. 2. Test liner lap to 2050 psi after cement has reached 500 psi compressive strength. 10 min operational assurance test. 18. Run Completion Assembly 1. Run 3-1/2” tubing completion assembly to above the liner top x Tubing will be 3-1/2” L-80 9.2# EUE x Baker S-5 SSSV to be placed between 400’ and 450’ MD x 2 live GLM’s will be run at 1500’ and 2900’ TVD (1 full joint between X-nip and bottom GLM pup) x Tripoint X NIP – just above the seal stem 2. Swap the well over to FIW x Circulate a hi-vis pill followed by a soap train per Baroid x Circulate FIW until clean-up is satisfactory. Page 23 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx x Leave FIW in the annulus. 3. Space out and land seal bore in tie back sleeve. RILDs. 4.Test IA to 2050 psi and tubing to 2050 psi. Charted 30 min. 5. Install BPV in wellhead. 6. ND BOPE, NU tree, test void 7. Rig Down 19. BOP Schematic Page 24 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 20. Wellhead Schematic Page 25 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 21. Anticipated Drilling Hazards Lost Circulation: Drill depleted reservoir may cause loss circulation events (as seen in the 2021 program on A-03A and A-01A) x Maintain sufficient volumes while drill. x Maintain ability to take on FIW during drilling phase x If a LC event occurs pumping cement will be the likely remedy Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual-composition carbon-based 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/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. x Minimize swab and surge pressures x Minimize back reaming through coals when possible H2S: H2S is not present in this hole section. Anticollision: No close approaches. Page 26 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 22. Jack up position Page 27 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 23. FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. Add casing pressure test data to graph if recent and available. 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 28 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 24. Choke Manifold Schematic Page 29 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx Page 30 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 25. Casing Design Information Page 31 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 26. 6-1/8” Hole Section MASP Page 32 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 27. Plot (NAD 27) (Governmental Sections) Page 33 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 28. Slot Diagram Page 34 PTD June, 30 2025 NCI A-06A Drilling Program PTD xxxxxx 29. Directional Program (wp08) - Attached separately !" #$$ % # % #! 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175 6500 6825 7150True Vertical Depth (650 usft/in)-1300 -975 -650 -325 0 325 650 975 1300 1625 1950 2275 2600 2925 3250 Vertical Section at 240.75° (650 usft/in) NCIU A-06A wp08 TD 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 0 4 5 A-06 10-3/4" x 15" 7" KOP 4-1/2" x 6-1/8" 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 4 2 5 NCIU A-06A wp08 KOP: 12.75º/100' : 3300' MD, 2991.06'TVD : 150° RT TF End Dir : 3313' MD, 3001.7' TVD Start Dir 4º/100' : 3413' MD, 3084.29'TVD End Dir : 4218.21' MD, 3768.68' TVD Total Depth : 7425' MD, 6427.23' TVD Top Sterling X Top Beluga A Top Beluga I Top Beluga M Beluga S/T Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: NCIU A-06 Water Depth: 101.00 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2586719.22 332104.19 61° 4' 36.2876 N 150° 56' 53.4001 W SURVEY PROGRAM Date: 2025-06-05T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 853.63 3300.00 N COOK INLET UNIT A-06 (NCI A-06) 3_CB-Film-GSS 3300.00 3500.00 NCIU A-06A wp08 (NCIU A-06A) 3_MWD_Interp Azi+Sag 3700.00 7425.00 NCIU A-06A wp08 (NCIU A-06A) 3_MWD+AX+Sag REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: NCIU A-06, True North Vertical (TVD) Reference:NCI A-06A @ 126.63usft Measured Depth Reference:NCI A-06A @ 126.63usft Calculation Method: Minimum Curvature Project:North Cook Inlet Site:North Cook Inlet Unit Well:Plan: NCIU A-06 Wellbore:NCIU A-06A Design:NCIU A-06A wp08 CASING DETAILS TVD TVDSS MD Size Name 2991.06 2864.43 3300.01 7 7" KOP 6427.23 6300.60 7425.00 4-1/2 4-1/2" x 6-1/8" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 3300.00 35.75 204.33 2991.06 -1019.60 -466.87 0.00 0.00 905.59 KOP: 12.75º/100' : 3300' MD, 2991.06'TVD : 150° RT TF 2 3313.00 34.32 205.80 3001.70 -1026.36 -470.03 12.75 150.00 911.65 End Dir : 3313' MD, 3001.7' TVD 3 3413.00 34.32 205.80 3084.29 -1077.13 -494.57 0.00 0.00 957.87 Start Dir 4º/100' : 3413' MD, 3084.29'TVD 4 4218.21 34.00 265.00 3768.68 -1307.22 -826.42 4.00 115.68 1359.84 End Dir : 4218.21' MD, 3768.68' TVD 5 7425.00 34.00 265.00 6427.23 -1463.51 -2612.81 0.00 0.00 2994.77 Total Depth : 7425' MD, 6427.23' TVD -2250-2100-1950-1800-1650-1500-1350-1200-1050-900-750-600-450-300-150South(-)/North(+) (300 usft/in)-2700 -2550 -2400 -2250 -2100 -1950 -1800 -1650 -1500 -1350 -1200 -1050 -900 -750 -600 -450 -300 -150 0West(-)/East(+) (300 usft/in)NCIU A-06A wp08 TD15001750200022502500275030003250350037504000425045004750A-0610-3/4" x 15"7" KOP4-1/2" x 6-1/8"150017502000225025002750300032503 5 0 0 3 75 0 4000 4 25 0 4 50 0 475 0 50 0 0 525 0 5 500 575 0 600 0 62 5 0 64 2 7 NCIU A-06A wp08KOP: 12.75º/100' : 3300' MD, 2991.06'TVD : 150° RT TFEnd Dir : 3313' MD, 3001.7' TVDStart Dir 4º/100' : 3413' MD, 3084.29'TVDEnd Dir : 4218.21' MD, 3768.68' TVDTotal Depth : 7425' MD, 6427.23' TVDCASING DETAILSTVDTVDSS MDSize Name2991.06 2864.43 3300.01 7 7" KOP6427.23 6300.60 7425.00 4-1/2 4-1/2" x 6-1/8"Project: North Cook InletSite: North Cook Inlet UnitWell: Plan: NCIU A-06Wellbore: NCIU A-06APlan: NCIU A-06A wp08WELL DETAILS: Plan: NCIU A-06Water Depth: 101.00+N/-S +E/-W Northing EastingLatittudeLongitude0.00 0.002586719.22 332104.19 61° 4' 36.2876 N 150° 56' 53.4001 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: NCIU A-06, True NorthVertical (TVD) Reference: NCI A-06A @ 126.63usftMeasured Depth Reference:NCI A-06A @ 126.63usftCalculation Method:Minimum Curvature &" ' ( $ " ! )" *+, )" ! - -. /("! 0% ! !" ! #$%&'!( ,!1 )* ,. 0, )" #$%&'!( % )" + ,! 0 (' 2 ,' &" 0 3 (',' $-%./01 !2 3$-%./ 3442 56 + 7+( 77 ( ! !! 4 ' ! $! $ 1! !! 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" ## (!" #$# #$ '% =- (.@- (. ,C! ,@)# ,# ###% 34!!# !#5 % # !6+!## % ##! #% 7 # ! 8*# !$+!" 7#9:*# !$+!" 7#)# !;*# !$+!! ##5# '5!# !6+!+6 ! ## ! ! #+ % %#!'5.!,%,% 3 % ,5 -$, 7 + -./*-! 01 ' + -./*121 ' 0.001.002.003.004.00Separation Factor3300 3600 3900 4200 4500 4800 5100 5400 5700 6000 6300 6600 6900 7200 7500 7800 8100 8400 8700 9000Measured Depth (600 usft/in)B-03B-03PB1NCIU B-03AA-06No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: NCIU A-06 NAD 1927 (NADCON CONUS)Alaska Zone 04Water Depth: 101.00+N/-S +E/-W Northing EastingLatittudeLongitude0.000.002586719.22 332104.19 61° 4' 36.2876 N150° 56' 53.4001 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: NCIU A-06, True NorthVertical (TVD) Reference: NCI A-06A @ 126.63usftMeasured Depth Reference:NCI A-06A @ 126.63usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-06-05T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool853.63 3300.00 N COOK INLET UNIT A-06 (NCI A-06) 3_CB-Film-GSS0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)3300 3600 3900 4200 4500 4800 5100 5400 5700 6000 6300 6600 6900 7200 7500 7800 8100 8400 8700 9000Measured Depth (600 usft/in)A-06NO GLOBAL FILTER: Using user defined selection & filtering criteria3300.00 To 7425.00Project: North Cook InletSite: North Cook Inlet UnitWell: Plan: NCIU A-06Wellbore: NCIU A-06APlan: NCIU A-06A wp08CASING DETAILSTVD TVDSS MD Size Name2999.69 2873.06 3300.01 7 7" KOP6367.71 6241.08 7425.00 4-1/2 4-1/2" x 6-1/8"3300.00 3700.00 NCIU A-06A wp08 (NCIU A-06A) 3_MWD_Interp Azi+Sag3700.00 7425.00 NCIU A-06A wp08 (NCIU A-06A) 3_MWD+AX+Sag 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. 225-071 NORTH COOK INLET TERTIARY GAS NCIU A-06A WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:N COOK INLET UNIT A-06AInitial Class/TypeDEV / PENDGeoArea820Unit11450On/Off ShoreOffProgramDEVWell bore segAnnular DisposalPTD#:2250710Field & Pool:NORTH COOK INLET, TERTIARY GAS - 564570NA1 Permit fee attachedYes ADL17589 and ADL378312 Lease number appropriateYes3 Unique well name and numberYes NORTH COOK INLET, TERTIARY GAS - 564570 - governed by CO 68A4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes This is a sidetrace just above the surface casing shoe.19 Surface casing protects all known USDWsYes Fully cemented production liner. 200' liner lap.20 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 & permafrostYes Spartan 151 has adequate tankage24 Adequate tankage or reserve pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows no close approaches.26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes 5M stack 1 annular, 3 ram , 1 flow cross29 BOPEs, do they meet regulationYes 5000 psi stack tested to 3500 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not expected in this well.35 Permit can be issued w/o hydrogen sulfide measuresYes Lower Sterling under-pressured of 8.1 ppg EMW. Max pore pressure anticipated as 9.8 ppg EMW near TD.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]ApprADDDate8/1/2025ApprMGRDate8/8/2025ApprADDDate7/28/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 8/11/2025