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Home My WebLink About225-094Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/20/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251120 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 23 50133206350000 214093 10/14/2025 AK E-LINE PPROF T41129 BR 09-86 50733204480000 193062 10/28/2025 AK E-LINE Perf T41130 BRU 213-26T 50283202040000 225038 10/30/2025 AK E-LINE Perf T41131 END 1-57 50029218730000 188114 11/16/2025 READ PressTempSurvey T41132 END 2-28B 50029218470200 203006 11/15/2025 READ PressTempSurvey T41133 END 2-30B 50029222280200 208187 11/18/2025 READ PressTempSurvey T41134 END 2-52 50029217500000 187092 10/28/2025 HALLIBURTON LDL T41135 KALOTSA 10 50133207320000 224147 11/7/2025 AK E-LINE Perf T41136 MPF-92 50029229240000 198193 11/8/2025 READ CaliperSurvey T41137 MPH-01 50029220610000 190086 11/7/2025 READ CaliperSurvey T41138 MPI-14 50029232140000 204119 11/8/2025 READ CaliperSurvey T41139 MPU H-01 50029220610000 190086 11/4/2025 AK E-LINE Drift/CBL/Caliper/Packer T41138 MPU I-14 50029232140000 204119 11/8/2025 AK E-LINE RigAssist T41139 MPU J-02 50029220710000 190096 11/6/2025 AK E-LINE Caliper/Gyro T41140 NCIU A-07A 50883200270100 225094 11/1/2025 AK E-LINE CBL T41141 NCIU A-07A 50883200270100 225094 11/4/2025 AK E-LINE Perf T41141 ODSN-01A 50703206480100 216008 10/24/2025 HALLIBURTON PACKER T41142 ODSN-25 50703206560000 212030 10/23/2025 HALLIBURTON PACKER T41143 ODSN-26 50703206420000 211121 11/4/2025 HALLIBURTON PERF T41144 PBU 02-10B 50029201630200 200064 10/27/2025 HALLIBURTON RBT T41145 PBU A-24B 50029207430200 225067 10/20/2025 BAKER MRPM T41146 PBU B-05E 50029202760500 225093 10/23/2025 HALLIBURTON RBT T41147 PBU B-05E 50029202760500 225093 10/23/2025 BAKER MRPM T41147 PBU B-20A 50029208420100 212026 10/16/2025 BAKER SPN T41148 PBU F-18B 50029206360200 225099 11/5/2025 HALLIBURTON RBT-COILFLAG T41149 PCU D-10 50283202080000 225082 10/31/2025 AK E-LINE Patch T41150 PCU D-10 50283202080000 225082 10/17/2025 AK E-LINE Perf T41150 PCU D-10 50283202080000 225082 10/22/2025 AK E-LINE Perf T41150 PCU D-10 50283202080000 225082 10/29/2025 AK E-LINE Perf T41150 T41141NCIU A-07A 50883200270100 225094 11/1/2025 AK E-LINE CBL NCIU A-07A 50883200270100 225094 11/4/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.20 13:27:19 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PCU D-11 50283202090000 225088 10/16/2025 AK E-LINE CBL T41151 PCU D-11 50283202090000 225088 10/24/2025 AK E-LINE Perf T41151 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.20 13:27:31 -09'00' 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: 11/11/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: NCIU A-07A PTD: 225-094 API: 50-883-20027-01-00 FINAL LWD FORMATION EVALUATION LOGS (10/17/2025 to 10/22/2025) x ROP, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) x Pressure While Drilling (PWD) x Final Definitive Directional Survey SFTP Transfer – Data Main Folders: Please include current contact information if different from above. 225-094 T41086 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.12 10:17:22 -09'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,402 N/A Casing Collapse Structural Conductor Surface 2,090psi Intermediate 3,270psi 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: 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: Initial Completion, N2 CO 68A N Cook Inlet Unit Tertiary System Gas Same 6,439 7,324 6,379 2,635psi 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 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 225-094 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20027-01-00 Hilcorp Alaska, LLC N Cook Inlet Unit A-07A Length Size Proposed Pools: L-80 TVD Burst 2,613 10,160psi MD 4,360psi 3,580psi 388' 2,366' 2,519' 388' 2,522' 6,437'3-1/2" 30" 10-3/4" 388' 7"2,710' 2,522' 7,399' Perforation Depth MD (ft): 2,710' See schematic 4,815' See schematic 10/30/2025 3-1/2" LTP & SSSV 2,584 (MD) 2,416 (TVD) & 413 (MD) 413 (TVD) No RUSH 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 9:31 am, Oct 28, 2025 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.10.28 09:15:52 - 08'00' Dan Marlowe (1267) 325-669 TS 10/28/25 DSR-10/30/25MGR29OCT25 * Service coil BOPE test to 3500 psi. 48 hour notice to AOGCC. * SSV/SSSV performance test within 5 days of stabilized production. 48 hour notice. * CBL to AOGCC immediately upon completion of log for review prior to perforating. 10-407 original completion 10/31/25 Initial Completion Well: North Cook Inlet Unit A-07A Well Name:NCIU A-07A API Number:50-883-20027-01-00 Current Status:Sidetrack, Gas Producer Leg:Leg #3 (SE corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:225-094 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 35 Max. Potential Surface Pressure:2,635 psi MPSP -0.1 psi/ft gas grad. to surface 10-401 Section 26, pg 35 Field/Pool: North Cook Inlet Unit, Tertiary System Gas Pool Applicable Frac Gradient:0.83 psi/ft using 16.0 ppg EMW 10-401 Section 26, pg 35 Shallowest Allowable Perf TVD: MPSP/(Frac grad. Gas grad.) = 2,635 psi / (0.83 0.1 psi/ft) =3,610 tvd Brief Well Summary: NCIU A-07A is the last planned rotary sidetrack for Spartan 151 in the 2025 season. The primary target is the Beluga sands, with a future option to test the Sterling sands. A 7 casing exit is planned at 2,710. After milling the window, an FIT is planned to 14.9 ppg. The 6-1/8 production hole has a target TD of ± 7,386 md. 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: A 7 x 3-1/2 liner lap test, a 3-1/2 tubing test, and a 7 casing test will be performed to 2,635 psi by Spartan 151 per the approved 10-401. The well will be completed with a tubing retrievable subsurface safety valve set at ± 400. Plan to run tubing string with live gas lift valves. North Cook Inlet Unit, Tertiary System Gas Pool top = Top of Sterling sands, estimated at 3,514 md / 3,243 tvd from prognosis. North Cook Inlet Unit, Tertiary System Gas Pool Bottom = Base of Beluga sands. See attached email for updated calculation based on 18 OCT 2025 FIT results. -A.Dewhurst 24OCT25 Initial Completion Well: North Cook Inlet Unit A-07A 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 2,510). 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, coil to RIH with CBL toolstring in carrier then log from PBTD to top of production liner (estimated at 2,510). 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 = 3,514 md / 3,243 tvd (from pre-drill prognosis, actual top will be confirmed with MWD logs). 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. Initial Completion Well: North Cook Inlet Unit A-07A a. Provide AOGCC with 48 hr witness notification for BOP test. 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 of placing well in service. Attachments: 1. Proposed Wellbore Schematic 2. CT BOP Drawing 3. Nitrogen procedure Updated By: JLL 10/27/25 PROPOSED SCHEMATIC North Cook Inlet Unit Tyonek Platform Well: NCI A-07A PTD: 225-094 API: 50-883-20027-01-00 PBTD: 7,324 TD: 7,402 4 30 RKB: MSL = 126.6 3 5/6 2 7 3-1/2 7Window @ 2,710 MD 10-3/4 5 1 1 X Casing &Tubing Detail SIZE WT GRADE CONN MIN ID TOP BTM (MD) 30 Welded 28.000 Surf 388 10-3/451 J-55 BTC 9.850 Surf 528 45.5 J-55 BTC 9.850 528 2,522 7 26 J-55 BTC 8.535 Surf 2,710TOW 3-1/2 9.2 L-80 Hyd 563 2.922 2,584 7,399 3-1/2 9.3 L-80 EUE-M 2.922 Surf 2,613 JEWELRY DETAILS No.Depth MD Depth TVD ID Item 1 413 413 2.812 TRMAXX-5E SLB TRSSV 2 1,530 1,516 2.867 3.5"MO-1, 2.867"drift 3 2,521 2,365 2.867 3.5"MO-1, 2.867"drift 4 2,570 2,405 2.81 X-Nipple, GX (2.81" drift) 5 2,582 2,415 4.170 Seal Stem 6 2,584 2,416 4.180 Liner hanger / LTP Assembly PERFORATION DETAILS See page 2 Depth Item 4,927 RA Marker Joint 5,533 RA Marker Joint 6,139 RA Marker Joint 6,740 RA Marker Joint CEMENT DETAILS 10-3/415 hole: Pumped 1020sxs 11.5ppg class G lead followed by 125sxs 15.6ppg class G tail.Assumed ToC to surface 7 9-5/8 Hole: Pumped 525sxs 13ppg class G primary stage. Saw 20bbls primary stage back to surface when circd through stage collar.Primary ToC at stage collar (5,211 MD) Second stage: Pumped 760sxs 14.9ppg class G second stage cement through stage collar at 5211 MD. Lost partial returns with 25bbls remaining in displacement. 5/23/20 CBL shows second stage ToC at 2,525 MD 3-1/2 Liner Pumped 139 bbls 12.5 PPG (372 sx) pf Lead, 27 bbls 15.3 PPG (123 sx) of Tail Full returns, plug bumped, circulated 25 bbl, 12.5 PPG Lead cement off top of LTP -TOC @ ~2,584 MD (TOL) Updated By: JLL 10/27/25 PROPOSED SCHEMATIC North Cook Inlet Unit Tyonek Platform Well: NCI A-07A PTD: 225-094 API: 50-883-20027-01-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Beluga_Aa ±4,877' ±4,881' ±4,499' ±4,502' ±4' Future Proposed Beluga_Ab ±4,892' ±4,903' ±4,511' ±4,521' ±11' Future Proposed Beluga_Ac ±4,905' ±4,908' ±4,522' ±4,525' ±3' Future Proposed Beluga_Ad ±4,943' ±4,953' ±4,553' ±4,561' ±10' Future Proposed Beluga_Ba ±5,003' ±5,027' ±4,601' ±4,619' ±24' Future Proposed Beluga_Bb ±5,082' ±5,092' ±4,662' ±4,669' ±10' Future Proposed Beluga_Bc ±5,121' ±5,131' ±4,692' ±4,699' ±10' Future Proposed Beluga_Ca ±5,218' ±5,226' ±4,766' ±4,772' ±8' Future Proposed Beluga_Cb ±5,263' ±5,266' ±4,800' ±4,803' ±3' Future Proposed Beluga_Cc ±5,271' ±5,282' ±4,807' ±4,815' ±11' Future Proposed Beluga_Cd ±5,293' ±5,295' ±4,823' ±4,825' ±2' Future Proposed Beluga_Ce ±5,317' ±5,322' ±4,842' ±4,846' ±5' Future Proposed Beluga_Da ±5,340' ±5,344' ±4,859' ±4,863' ±4' Future Proposed Beluga_Db ±5,406' ±5,410' ±4,910' ±4,913' ±4' Future Proposed Beluga_Dc ±5,415' ±5,419' ±4,917' ±4,920' ±4' Future Proposed Beluga_Dd ±5,442' ±5,446' ±4,938' ±4,941' ±4' Future Proposed Beluga_Ea ±5,473' ±5,477' ±4,961' ±4,964' ±4' Future Proposed Beluga_Eb ±5,491' ±5,502' ±4,975' ±4,984' ±11' Future Proposed Beluga_Ec ±5,585' ±5,593' ±5,047' ±5,053' ±8' Future Proposed Beluga_Ed ±5,614' ±5,616' ±5,069' ±5,071' ±2' Future Proposed Beluga_Ee ±5,637' ±5,641' ±5,087' ±5,090' ±4' Future Proposed Beluga_Ef ±5,663' ±5,668' ±5,107' ±5,111' ±5' Future Proposed Beluga_Fa ±5,687' ±5,690' ±5,125' ±5,128' ±3' Future Proposed Beluga_Fb ±5,704' ±5,709' ±5,138' ±5,142' ±5' Future Proposed Beluga_Fc ±5,772' ±5,778' ±5,190' ±5,195' ±6' Future Proposed Beluga_Ga ±5,811' ±5,815' ±5,220' ±5,223' ±4' Future Proposed Beluga_Gb ±5,852' ±5,866' ±5,252' ±5,262' ±14' Future Proposed Beluga_Ha ±5,976' ±6,005' ±5,347' ±5,369' ±29' Future Proposed Beluga_Hb ±6,008' ±6,013' ±5,371' ±5,375' ±5' Future Proposed Beluga_Hc ±6,031' ±6,037' ±5,389' ±5,393' ±6' Future Proposed Beluga_Hd ±6,070' ±6,081' ±5,419' ±5,427' ±11' Future Proposed Beluga_Ia ±6,112' ±6,138' ±5,451' ±5,471' ±26' Future Proposed Beluga_Ib ±6,172' ±6,182' ±5,497' ±5,504' ±10' Future Proposed Beluga_Ic ±6,207' ±6,225' ±5,524' ±5,537' ±18' Future Proposed Beluga_Ja ±6,285' ±6,304' ±5,583' ±5,598' ±19' Future Proposed Beluga_Jb ±6,327' ±6,330' ±5,616' ±5,618' ±3' Future Proposed Beluga_Ka ±6,412' ±6,424' ±5,681' ±5,690' ±12' Future Proposed Beluga_Kb ±6,453' ±6,456' ±5,712' ±5,714' ±3' Future Proposed Beluga_Kc ±6,488' ±6,499' ±5,739' ±5,747' ±11' Future Proposed Beluga_La ±6,568' ±6,583' ±5,800' ±5,812' ±15' Future Proposed Beluga_Lb ±6,611' ±6,618' ±5,833' ±5,838' ±7' Future Proposed Beluga_Ma ±6,661' ±6,665' ±5,871' ±5,874' ±4' Future Proposed Beluga_Mb ±6,678' ±6,700' ±5,884' ±5,901' ±22' Future Proposed Beluga_Mc ±6,725' ±6,729' ±5,920' ±5,924' ±4' Future Proposed Beluga_Na ±6,776' ±6,785' ±5,960' ±5,966' ±9' Future Proposed Beluga_Nb ±6,796' ±6,800' ±5,975' ±5,978' ±4' Future Proposed Beluga_Nc ±6,812' ±6,815' ±5,987' ±5,989' ±3' Future Proposed Beluga_No ±6,841' ±6,848' ±6,009' ±6,015' ±7' Future Proposed Beluga_Qa ±7,036' ±7,043' ±6,159' ±6,164' ±7' Future Proposed Beluga_Qb ±7,051' ±7,056' ±6,170' ±6,174' ±5' Future Proposed 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. 1 Dewhurst, Andrew D (OGC) From:Eric Dickerman <Eric.Dickerman@hilcorp.com> Sent:Tuesday, 28 October, 2025 11:34 To:Dewhurst, Andrew D (OGC) Cc:Rixse, Melvin G (OGC) Subject:RE: [EXTERNAL] NCIU A-07A Perf Sundry (325-641) Attachments:10-403 N Cook Inlet Unit A-07A PTD 225-094 2025-10-28.pdf Mr. Dewhurst and Mr. Rixse, A ached is the updated 10-403 form with Sec on 11 updated. The Proposed Schema c was revised to include the perforated intervals. The produc on liner cement job was pumped on 10/24. For the cement job, 139 bbl of 12.5 ppg lead was followed by 27 bbl of 15.3 ppg tail with full returns. The plug was bumped approximately 3 bbl early. A er se ng the liner top packer, 25 bbl of the 12.5 ppg lead cement was circulated o the liner top, indica ng that there should be cement expected up to the top of the 3-1/2 produc on liner. We plan to mobilize coiled tubing and eline to the pla orm in the next couple of days weather permi ng. Currently we es mate logging the CBL 10/31 - 11/1. Regards, Eric Dickerman Hilcorp CIO Ops Engineer Cell: 307-250-4013 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Friday, October 24, 2025 1:46 PM To: Eric Dickerman <Eric.Dickerman@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-07A Perf Sundry (325-641) Eric, Thank you for the directional survey, logs, and calculations. Would you please send me an updated 10- 403 form with the actual depths under Section 11 (present well condition) and a revised Proposed Schematic with the full details of the proposed perforated intervals, not just top and base? I will insert those pages into the application as a revision. Should be good to go after that. Thanks, Andy CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 From: Eric Dickerman <Eric.Dickerman@hilcorp.com> Sent: Friday, 24 October, 2025 09:10 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Cody Dinger <cdinger@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-07A Perf Sundry (325-641) Mr. Dewhurst, Understood. I appreciate the direc on as I have been wrestling with how to handle the post rig 10-403 submission myself. NCIU A-07A is the last drill well planned for Tyonek this year, however I will make sure to incorporate the submission change for next years drilling campaign (four wells planned to start mid April 2026). Regarding NCIU A-07A, please see the a ached direc onal survey and LWD forma on logs. TD was called on 10/22 at 7,392. The crew is currently picking up the 3-1/2 produc on liner. We expect to pump the produc on liner cement job this weekend, and will provide an update on the cement job early next week. The CBL is currently scheduled for ± 11/08 pending Spartan demobe and construc on project comple on. On 10/18 an FIT was performed to a 14.9 ppg equivalent mud weight (0.77 psi/). Maximum possible surface pressure = 2,635 psi from PTD section 26. Shallowest allowable perf TVD = 2,635 psi / (0.77 psi/ft 0.1 psi/ft) = 3,933 tvd. Top potential perf interval = 4,863 md / 4,492 tvd. Bottom potential perf interval = 7,290 md / 6,332 tvd. Top pool = 3,515 md / 3,248 tvd. Bottom pool = below TD. Please let me know if you have any ques ons. Thank you, Eric Dickerman Hilcorp CIO Ops Engineer Cell: 307-250-4013 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, October 23, 2025 10:45 AM To: Eric Dickerman <Eric.Dickerman@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Cody Dinger <cdinger@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: [EXTERNAL] NCIU A-07A Perf Sundry (325-641) 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. 3 Eric, We have had some recent internal discussions about how we want to handle perf sundries like this for new wells. I understand that by getting the sundry into us early, you get the operation on our radar. But its not practical for us to receive a sundry like this before the well is drilled; the application has no usable information. Going forward, we would like you to hold o on submitting perforation sundries until you have the following minimum information: Directional survey LWD logs Proposed perforated intervals Pool tops Shallowest perf calculation We will continue to approve perforation sundries before the CBL results have come in. That will continue to be a condition of approval that can be ful lled verbally/via email. I understand that this will reduce the time interval between sundry submission and start date. I believe we can prioritize these sundry requests and get them back to you on-time. For the rst few examples, I suggest agging the perf sundry with a rush when its submitted just so that it gets the extra attention. Give me a call if you would like to discuss this further. Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 4 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. 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, Suite 1400 Anchorage, AK, 99503 Re: North Cook Inlet Unit, Tertiary System Gas Pool, NCIU A-07A Hilcorp Alaska, LLC Permit to Drill Number: 225-094 Surface Location: 1250' FNL, 1086' FWL, Sec 6, T11N, R9W, SM, AK Bottomhole Location: 2057' FNL, 1724' FEL, Sec 6, T11N, 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, (SFHPSZ $. 8JMTPO Commissioner DATED this 23 day of September, 2025. Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.09.24 15:18:56 -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: 7,386' 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-332105 y- 2586728 Zone-4 N/A to Same Pool: 1240' to NCIU A-04A 16. Deviated wells: Kickoff depth: 2,710 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 40 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 4,876' 2,510' 2,356' 7,386' 6,427' Tieback 3-1/2" 9.2# L-80 EUE 2,510' Surface Surface 2,510' 2,356' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): N/A TVD 388' 2364' 6905' 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 7004' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 5002 Cement Volume MD Driven 388' 2522'10-3/4" 1145 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): 2522' 1285 sx To be plugged Conductor/Structural 30"388' Authorized Title: Authorized Signature: Authorized Name: Production Liner 8108' Intermediate 8126'6920' LengthCasing See Schematic Size Plugs (measured): (including stage data) L - 837 ft3 T - 101 ft3 Tieback Assy. 4109' 3627' 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 2278' FNL, 1302' FWL, Sec 6, T11N, R9W, SM, AK 2057' FNL, 1724' FEL, Sec 6, T11N, R9W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1250' FNL, 1086' FWL, Sec 6, T11N, R9W, SM, AK ADL 17589 NCIU A-07A 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 8108'7" 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) 10/7/2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.08.26 11:13:07 - 08'00' Sean McLaughlin (4311) By Grace Christianson at 2:33 pm, Aug 26, 2025 50-883-20027-01-00 * BOPE test to 3000 psi. Annular to 2500 psi. 48 hour notice to AOGCC. * AOGCC to witness tag (TOC ~ 2525' MD and pressure test (to 2635 psi) for cement abandonment plug. 48 hour notice. DSR-9/10/25 225-094 MGR08SEP2025 TS 9/16/25JLC 9/23/2025 Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.09.24 15:18:38 -08'00' 50-883-2007-01-00 09/24/25 09/24/25 RBDMS JSB 092625 A-07A Drilling Program Tyonek Sean McLaughlin PTD August 22, 2025 NCI A-07A 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.............................................................................................................................11 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...................................................................................................................15 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...............................................................................................................23 19. BOP Schematic..................................................................................................................................24 20. Wellhead Schematic..........................................................................................................................25 21. Anticipated Drilling Hazards...........................................................................................................26 22. Jack up position ................................................................................................................................27 23. FIT Procedure...................................................................................................................................28 24. Choke Manifold Schematic..............................................................................................................29 25. Casing Design Information ..............................................................................................................31 26. 6-1/8” Hole Section MASP...............................................................................................................32 27. Plot (NAD 27) (Governmental Sections).........................................................................................33 28. Slot Diagram......................................................................................................................................34 29. Directional Program (wp05) - Attached separately......................................................................35 Page 2 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 1. Well Summary Well NCI A-07A Drilling Rig Rig 151 Leg 3 Directional plan wp05 Pad & Old Well Designation Sidetrack of existing well A-07 (PTD#169-058) Planned Completion Type 3-1/2” 9.2# Liner, 3-1/2” Tubing Comp Target Reservoir(s) Beluga A-T Kick off point 2710’ MD Planned Well TD, MD / TVD 7386’ MD / 6427’ TVD PBTD, MD 7286’ MD AFE Number AFE Days AFE Drilling Amount Work String 4.5” 16.6# S-135 CDS40 RKB – AMSL 126.63’ MSL to ML 73.3’ Page 3 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 2. Management of Change Information Date: August 30, 2025 Subject: Changes to Approved Permit to Drill File #: NCI A-07A 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 August 22, 2025 NCI A-07A 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 August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 5. Internal Reporting Requirements 1. Fill out daily drilling report and cost report. Report covers operations from 6am to 6am Ensure time entry adds up to 24 hours total. Capture any out-of-scope work as NPT. This helps later when aggregating end of well reports. 2. Afternoon Updates Submit a short operations update every day to Kenai/CIO Drilling <KenaiCIODrilling@hilcorp.com> 3. EHS Incident Reporting Notify EHS field coordinator. i. Garrett St. Clair: C: (907) 252-7780 Spills: i. Adrian Kersten: C: 907-564-4820 ii. Sean Mclaughlin Report ALL spills to the water within 15 minutes. Submit Hilcorp Incident report to contacts above within 24 hrs 4. Casing Tally Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com 5. Casing and Cmt report Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com Page 6 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 6. Current Wellbore Schematic Page 7 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx Page 8 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 7. Planned Wellbore Schematic Page 9 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 8. Drilling Summary A-07 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 7386’. 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 October 7, 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 @ 3450’ Rig 2. Rig 151 will MIRU over Leg 3, Well A-07 3. NU BOPE and test to 3000 psi. (MASP 2635psi) 4. Set 7’ 23# cement retainer at 3350’, plug parent well with cement 5. Test 7” casing to 2635 psi. 6. Set 7” whipstock at 2710’ and 150L. Swap well to 9.0 ppg LSND mud. 7. Mill window with 20’ of new formation. 8. Perform FIT to 14.9 ppg EMW 9. PU 4-3/4” motor drilling assembly and TIH to window. 10. Drill 6-1/8” production hole to 7386’ MD, performing short trips as needed 11. RIH w/ 3-1/2” liner. Set liner and cement. 12. Perform liner lap test to 2635 psi. 13. Make polish mill run and LDDP 14. Run 3-1/2” completion. 15. Land hanger and test. 16. ND BOPE, NU tree and test void Reservoir Evaluation Plan: 1. Production Hole: Triple Combo LWD Page 10 PTD August 22, 2025 NCI A-07A 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. BOPs shall be tested at (2) week intervals during the drilling. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. 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 2635 psi with 0.1psi/ft gas in the wellbore. o A casing test to 2635 psi is planned after plugging the parent Rated Working Pressure (RWP) the BOPE and wellhead must meet or exceed: 3000 psi. 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. 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. Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) Page 11 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 6-1/8” 13-5/8” Shaffer 5M annular 13-5/8” 5M Shaffer SL Double gate Blind ram in bottom cavity Mud cross 13-5/8” 5M Shaffer SL single gate 3-1/16” 5M Choke Manifold Standpipe, floor valves, etc Initial Test: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) Primary closing unit: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex electric driven pump Required AOGCC Notifications: Well control event (BOPs utilized to shut in the well to control influx of formation fluids). 48 hours notice prior to full BOPE test. 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) 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 Page 12 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 3. N/U 13-5/8” x 5M BOP as follows (top down): 13-5/8” x 5M Shaffer annular BOP. 13-5/8” Shaffer Type “SL” Double ram. (2-7/8” X 5” VBR in top cavity, blind ram in btm cavity) 13-5/8” mud cross 13-5/8” Shaffer Type “SL” single ram. (2-7/8” X 5” VBR) N/U pitcher nipple, install flowline. Install (2) manual valves on kill side of mud cross. Manual valve used as inside or “master valve”. Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 16-3/4” 5M Clamp hub adapter required 4. Test BOPE. Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. 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!!! Test VBRs on 3.5” and 4.5”test joints (3000 psi) Test Annular on 3.5” test joint (2500 psi) 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) Gardner Denver PZ-10’s Pumps are rated at 4932 psi (98%) with 6” liners and can deliver 422 gpm at 115 spm. Pump range for drilling will be 150-300 gpm. This can be achieved with one or both pumps. Page 13 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 3. 6-1/8” Production hole mud program summary: 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. 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 2710’- 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 7ppb 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 August 22, 2025 NCI A-07A 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 3450’ 2. Set wear bushing in wellhead. Ensure ID of wear bushing > 6-1/8”. 3. PU 7” cement retainer and set at 3350’ 4. Pump 20 bbls of 15.3# below the retainer ~10 bbls to bottom perf 5. Unsting from retainer and lay in ~400’ of cement above the retainer (~16 bbls) Annular 7” cement at 2525’ per 05/23/2020 CBL 6.Provide AOGGC notice of the opportunity to witness test and tag 7. WOC, Tag cement 8. Pressure test 7” casing to 2635 psi. 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 Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly. Avoid sudden starts and stops while running the whipstock. 48 hour notice to AOGCC for opportunity to witness. - mgr Page 15 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx Recommend 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 LOHS. 4. Set the top of the whipstock at ~2710’ MD 7” Collar location per tally and 2020 CBL (top log depth is 2350’) 5. Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING THE PLANNED FIT/LOT). Use ditch magnets to collect the metal shavings. Clean regularly. Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and Kevlar gloves. Work 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 14.9 ppg. **Assuming the kick zone is at TD, a FIT of 14.9 ppg EMW gives a Kick Tolerance volume of 15 bbls with 10.3 ppg mud weight. The failure case is due to swab kick from high end mug weight. 7. POOH and LD milling assembly Once out of the hole, inspect mill gauge and record. Flow check well for 10 minutes to confirm no flow: Before pulling off bottom. Before 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. 14. Drill 6-1/8” Hole Section 1. PU 7500’ of 4-1/2” CDS40 Drill pipe for drilling 6-1/8” hole section * Email casing test and FIT digital data to AOGCC immediately upon completion of FIT. - mg r Page 16 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 2. P/U 4-3/4” Sperry Sun motor drilling assy 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 7386’ MD using motor assembly. Pump sweeps and maintain mud rheology to ensure effective hole cleaning. 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. Keep swab and surge pressures low when tripping. Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. Adjust MW as necessary to maintain hole stability. Ensure mud engineer set up to perform HTHP fluid loss. Maintain API fluid loss < 6. Take MWD surveys every stand drilled. Minimize backreaming when working tight hole Mud weight to be at least 10.1 ppg at 6800’ MD Page 17 PTD August 22, 2025 NCI A-07A 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. 15. Run 3-1/2” Production Liner 1. R/U Baker 3-1/2” liner running equipment. Ensure 4-1/2” CDS-40 crossover on rig floor and M/U to FOSV. R/U fill up line to fill liner while running. Ensure all liner has been drifted and tally verified prior to running. Be sure to count the total # of joints before running. Keep hole covered while R/U casing tools. Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 2. P/U shoe joint, visually verify no debris inside joint. 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). Landing collar pup bucked up. Centralizers will be run on 3-1/2” liner Ensure proper operation of float shoe & FC. 4. Continue running 3-1/2” production liner to TD Short joint run every 1000’, RA tag 1000’ and 2000’ back from shoe Fill liner while running using fill up line on rig floor. Use “API Modified” thread compound. Dope pin end only w/ paint brush. Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 18 PTD August 22, 2025 NCI A-07A 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 August 22, 2025 NCI A-07A 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 August 22, 2025 NCI A-07A 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. Please independently verify displacement with actual inputs. Slurry Information: 80' - mgr Displacement = (2510' * .01422) + ((7386-80-2510) * ((2.992^2)/1029.4)) = 77.4 bbls - mgr Page 21 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 8. Drop DP dart and displace with clean 10.1 - 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 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: 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 Page 22 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 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. Ensure to report the following on Wellview: 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 liner 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 Note: Send Csg & cmt report + “As-Run” liner tally to sean.mclaughlin@hilcorp.com 17. Wellbore Clean Up & Displacement 1. No cleanout of the 3-1/2” liner planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. 2. Test liner lap to 2635 psi after cement has reached 500 psi compressive strength. 10 min operational assurance test. Page 23 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 18. Run Completion Assembly 1. Run 3-1/2” tubing completion assembly to above the liner top Tubing will be 3-1/2” L-80 9.2# EUE Baker S-5 SSSV to be placed between 400’ and 450’ MD 1 live GLM’s will be run at 1500’ TVD (1 full joint between X-nip and bottom GLM pup) Tripoint X NIP – just above the seal stem 2. Swap the well over to FIW Circulate a hi-vis pill followed by a soap train per Baroid Circulate FIW until clean-up is satisfactory. Leave FIW in the annulus. 3. Space out and land seal bore in tie back sleeve. RILDs. 4.Test IA to 2635 psi and tubing to 2635 psi. Charted 30 min. 5. Install BPV in wellhead. 6. ND BOPE, NU tree, test void 7. Rig Down Page 24 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 19. BOP Schematic Page 25 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 20. Wellhead Schematic Page 26 PTD August 22, 2025 NCI A-07A 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) Maintain sufficient volumes while drill. Maintain ability to take on FIW during drilling phase 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. 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. Minimize swab and surge pressures Minimize back reaming through coals when possible H2S: H2S is not present in this hole section. Anticollision: No close approaches. Page 27 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 22. Jack up position Page 28 PTD August 22, 2025 NCI A-07A 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 29 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 24. Choke Manifold Schematic Page 30 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx Page 31 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 25. Casing Design Information Page 32 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 26. 6-1/8” Hole Section MASP Page 33 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 27. Plot (NAD 27) (Governmental Sections) Page 34 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 28. Slot Diagram Page 35 PTD August 22, 2025 NCI A-07A Drilling Program PTD xxxxxx 29. Directional Program (wp05) - Attached separately 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. NCIU A-07A NORTH COOK INLET 225-094 TERTIARY GAS WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:N COOK INLET UNIT A-07Initial Class/TypeDEV / PENDGeoArea820Unit11450On/Off ShoreOffProgramDEVWell bore segAnnular DisposalPTD#:2250940Field & Pool:NORTH COOK INLET, TERTIARY GAS - 564570NA1 Permit fee attachedYes Entire Well lies within ADL17589.2 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) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 30" driven to 388'18 Conductor string providedYes 10-3/4" existing surface casing to 2510' MD.19 Surface casing protects all known USDWsYes Parent well shows adequate surface casing integrity20 CMT vol adequate to circulate on conductor & surf csgYes Fully cemented 3-1/2" production liner hung in 7"21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsNo23 Casing designs adequate for C, T, B & permafrostYes Spartan has adequate tankage24 Adequate tankage or reserve pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan show no close approaches to offset wells26 Adequate wellbore separation proposedNA Sidetrack below surface casing27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes 13-5/8" BOPE stack. 1 annular, 3 ram, 1 flow cross29 BOPEs, do they meet regulationYes 5M psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not expected in this well.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.421 to 0.509 psi/ft (8.1 to 9.8 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]ApprTCSDate9/15/2025ApprMGRDate9/23/2025ApprTCSDate9/15/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate($8JLC 9/23/2025