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Home My WebLink About225-013Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/10/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260210 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 224-34T 50283202050000 225044 1/30/2026 AK E-LINE Perf T41349 CLU 11RD 50133205590100 225013 1/24/2026 AK E-LINE Perf T41350 CLU 11RD 50133205590100 225013 1/27/2026 AK E-LINE Plug/Perf T41350 KU 24-07RD2 50133203520200 225126 1/14/2026 AK E-LINE CBL T41351 KU 24-07RD2 50133203520200 225126 1/20/2026 AK E-LINE IPFOF T41351 MPI 2-74 50029237850000 224024 1/25/2026 AK E-LINE Whipstock T41352 MPU 1-36 50029236770000 220047 2/1/2026 AK E-LINE Packer T41353 MPU R-110 50029238260000 225085 10/24/2025 YELLOWJACKET RCBL T41354 NFU 14-25 50231200350000 210111 12/29/2025 YELLOWJACKET CBL T41355 SDI 3-15 50029217510000 187094 1/23/2026 AK E-LINE Whipstock T41356 SRU 214A-27 50133101580100 225133 2/4/2026 YELLOWJACKET SCBL T41357 SRU 231-33 50133101630100 223008 7/31/2025 YELLOWJACKET PLUG-PERF T41358 SRU 242-16 50133204050000 188157 1/24/2026 YELLOWJACKET PLUG-PERF T41359 SU 43-10 50133207390000 225107 1/19/2026 YELLOWJACKET GPT-PLUG- PERF T41360 SU 43-10 50133207390000 225107 12/31/2025 YELLOWJACKET SCBL T41360 Please include current contact information if different from above. T41350CLU 11RD 50133205590100 225013 1/24/2026 AK E-LINE Perf CLU 11RD 50133205590100 225013 1/27/2026 AK E-LINE Plug/Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.10 14:51:05 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/4/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260204 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 223-34T 50283202060000 225059 12/31/2025 AK E-LINE Perf T41308 BRU 244-27 50283201850000 222038 1/2/2026 AK E-LINE Perf T41309 CLU 11RD 50133205590000 225013 1/2/2026 YELLOWJACKET SCBL T41310 CLU 11RD 50133205590000 225013 12/19/2025 YELLOWJACKET SCBL T41310 END 1-25A 50029217220100 197075 11/7/2025 HALLIBURTON COILFLAG T41311 END 1-25A 50029217220100 197075 12/26/2025 READ PressTempSurvey T41311 END 2-40 50029225270000 194152 12/18/2025 READ PressTempSurvey T41312 END 2-52 50029217500000 187092 12/24/2025 HALLIBURTON MFC40 T41313 END 2-56A 50029228630100 198058 1/1/2026 HALLIBURTON COILFLAG T41314 END 2-56A 50029228630100 198058 1/19/2026 READ CaliperSurvey T41314 KALOTSA 3 50133206610000 217028 1/14/2026 YELLOWJACKET PERF T41315 KALOTSA 3 50133206610000 217028 1/9/2026 YELLOWJACKET PERF T41315 KALOTSA 8 50133207050000 222003 12/18/2025 YELLOWJACKET PERF T41316 KBU 44-06 50133204980000 200179 12/22/2026 YELLOWJACKET CBL T41317 KBU 44-06 50133204980000 200179 11/12/2025 YELLOWJACKET PLUG T41317 KU 24-07RD 50133203520100 205099 1/6/2026 AK E-LINE CBL T41318 KU 24-07RD 50133203520100 205099 1/6/2026 AK E-LINE Plug/Cement T41318 KU 24-07RD 50133203520100 205099 1/1/2026 AK E-LINE Plug/Cement/TubingPunch T41318 MPI-36 50029236770000 220047 1/19/2026 READ CaliperSurvey T41319 MPI-36 50029236770000 220047 1/19/2026 READ LeakDetectLog T41319 NCIU A-19 50883201940000 224026 1/7/2025 AK E-LINE Perf T41320 NFU 42-35 50231200460000 214170 1/8/2026 YELLOWJACKET PERF T41321 NIK OI24-08 50029234570000 211130 1/19/2026 HALLIBURTON COILFLAG T41322 ODSN-04 50703206700000 213037 1/20/2026 HALLIBURTON LDL T41323 ODSN-22 50703207080000 215054 12/20/2025 READ LeakDetection T41324 PBU 15-11D 50029206530400 225112 1/18/2026 HALLIBURTON RBT-COILFLAG T41325 PBU 15-43 50029226760000 196083 12/21/2025 HALLIBURTON RBT T41326 PBU B-30B 50029215420200 225009 1/24/2026 HALLIBURTON RBT-COILFLAG T41327 PBU C-33B 50029223730200 225096 12/16/2025 HALLIBURTON RBT-COILFLAG T41328 T41310CLU 11RD 50133205590000 225013 1/2/2026 YELLOWJACKET SCBL CLU 11RD 50133205590000 225013 12/19/2025 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 09:10:43 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PBU D-26B 50029215300200 206098 12/20/2025 HALLIBURTON ISAT T41329 PBU D-26B 50029215300200 206098 12/19/2025 BAKER SPN T41329 PBU F-21A 50029219490100 225019 1/18/2026 HALLIBURTON RBT-COILFLAG T41330 PBU J-21A 50029217050100 225106 1/21/2026 HALLIBURTON RBT-COILFLAG T41331 PBU L-291 50029237790000 224002 12/26/2025 HALLIBURTON RBT T41332 PBU L-291 50029237790000 224002 12/9/2025 YELLOWJACKET RCBL T41332 PBU S-107A 50029220440200 225083 12/8/2025 HALLIBURTON RBT-COILFLAG T41333 PBU S-201A 50029229870100 219092 1/21/2026 HALLIBURTON WFL-TMD3D T41335 PBU S-24B 50029220440200 203163 12/22/2025 HALLIBURTON RBT T41334 PBU S-24B 50029230230100 203163 12/23/2025 HALLIBURTON WFL-TMD3D T41334 SRU 223-15 50133207410000 225123 1/29/2026 YELLOWJACKET GPT-PERF T41336 SRU 223-15 50133207410000 225123 1/20/2026 YELLOWJACKET SCBL T41336 SRU 233-10 50133207400000 225113 12/30/2026 AK E-LINE CBL T41337 SRU 233-10 50133207400000 225113 1/10/2026 YELLOWJACKET SCBL T41337 SRU 233-10 50133207400000 225113 1/6/2026 YELLOWJACKET SCBL T41337 SRU 34-28 50133101580000 163007 1/7/2026 YELLOWJACKET Gamma Ray T41338 SU 32-16 50133207380000 225095 1/17/2026 YELLOWJACKET GPT-PLUG-PERF T41339 SU 32-16 50133207380000 225095 11/22/2025 YELLOWJACKET SCBL T41339 SU 43-10 50133207390000 225107 12/10/2025 YELLOWJACKET SCBL T41340 TBU A-12RD 50883200320100 171029 1/2/2026 AK E-LINE StripGun T41341 TBU D-24A 50733202240100 174064 12/4/2025 AK E-LINE TubingPunch T41342 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 09:11:00 -09'00' David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 01/27/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: CLU 11RD PTD: 225-013 API: 50-133-20559-01-00 FINAL LWD FORMATION EVALUATION (12/11/2025 to 12/23/2025) x DGR, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) x Pressure While Drilling (PWD) x Final Definitive Directional Survey FINAL LWD FOLDERS: Please include current contact information if different from above. 225-013 T41292 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.28 08:17:43 -09'00' 1 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Wednesday, January 14, 2026 9:03 AM To:Stefan Reed Subject:RE: CLU-11RD (PTD# 225-013) Cement Bond Log Stefan, Hilcorp has approval to proceed with the perforations per sundry 326-004. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Stefan Reed <stefan.reed@hilcorp.com> Sent: Monday, January 5, 2026 10:38 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: CLU-11RD (PTD# 225-013) Cement Bond Log Bryan, Attached is cement bond log for CLU-11RD (PTD# 225-013) as well as the current and proposed schematics. The log shows good cement bond through the 3-1/2” liner. The sundry for perf adds on this well will be submitted this week. Please let me know if you have any questions or need additional information. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC 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 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. 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): 8,161' N/A Casing Collapse Structural Conductor Surface 1,540 psi Intermediate 3,810 psi Intermediate 8,530 psi 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: Contact Email: Contact Phone: 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 YJ Ranger Liner Hanger & Baker Hughes BX SSSV 6,067 (MD) 5,042 (TVD) & 355 (MD) 355 (TVD) 7,087' 8,097' 7,026' Cannery Loop Beluga Gas 20" 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Cannery Loop Unit (CLU) 11RDCO 231A Same 5250'7" 1,331 6,279' N/A Length January 21, 2026 8,161'2,094' 3-1/2" 7,087' 6,279' Perforation Depth MD (ft): 4,280' 3-1/2" See Attached Schematic 6,330 psi 3,090 psi 136' 3412' 136' 1,602' 1,489' Size 136' 9-5/8"4,280' 1,602' MD 50-133-20559-01-00 Hilcorp Alaska, LLC Proposed Pools: L-80 TVD Burst 6,067' 11,220 psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL00365454 / ADL00359153 / ADL00324602 225-013 Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Stefan Reed, Operations Engineer AOGCC USE ONLY 10,160psi Other: Initial Completion, N2 stefan.reed@hilcorp.com 206-518-0400 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 326-004 By Grace Christianson at 2:11 pm, Jan 06, 2026 Submit CBL to AOGCC and obtain approval before perforating. DSR-1/7/26 10-407 TS 1/7/26BJM 1/8/26 01/09/26 Initial Completion Well: CLU-10RD2 Jan 2026 Well Name:CLU-11RD API Number:50-133-20559-01-00 Current Status:New Drill Well Gas Producer Permit to Drill Number:225-013 Second Call Engineer:Stefan Reed (907) 777-8433 (O) (206) 518-0400 (C) First Call Engineer:Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP:2031 psi @ 7,004 TVD (Based on 0.29 psi/ft gradient LB_2B Sands) Max. Potential Surface Pressure:1,331 psi (Based on 0.10 psi/ft gas gradient to surface) Applicable Frac Gradient:0.702 psi/ft using 13.5 ppg EMW FIT at the 7 surface casing shoe Shallowest Potential Perf TVD:MPSP/(0.702-0.1) = 1,331 psi / 0.602 = 2,211 TVD Top of Beluga (CO 231A):~6,208 MD/~5,181 TVD Well Status:New Drill Well Initial Completion Brief Well Summary CLU-11RD was sidetracked from CLU-11 and completed with Hicorp rig 147 in December 2025 targeting the Beluga sand in the Cannery Loop Field. The objective of this sundry is to add initial perforations and flow well post drilling. All sands are in the Beluga gas pool per CO 231A. Wellbore Conditions: - Max Deviation 45deg @ 2,881. - Min ID 2.812, SSSV @ 355 Work to be completed on PTD# 225-013 ( CAP Sundry #325-756): - Eline run CBL (Send log to state prior to perforating on this sundry) - CT cleanout well with water and displace with N2. Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 2,000 psi high 3. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 4. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: Below are proposed targeted sands in order of testing (bottom/up), but additional sand may be added depending on results of these perfs, between the proposed top and bottom perfs Sands Top MD Btm MD Top TVD Btm TVD Amt MB_2 ±7,048 ±7,060 ±5,999 ±6,011 ±12 MB_2 ±7,064 ±7,076 ±6,015 ±6,027 ±12 MB_3 ±7,107 ±7,127 ±6,057 ±6,077 ±20 MB_5 ±7,267 ±7,275 ±6,214 ±6,222 ±8 MB_6 ±7,383 ±7,392 ±6,327 ±6,336 ±9 MB_6 ±7,451 ±7,460 ±6,393 ±6,402 ±9 MB_7A ±7,531 ±7,538 ±6,471 ±6,478 ±7 MB_7A ±7,543 ±7,555 ±6,483 ±6,495 ±12 MB_7A ±7,566 ±7,582 ±6,505 ±6,521 ±16 Initial Completion Well: CLU-10RD2 Jan 2026 MB_8 ±7,590 ±7,600 ±6,529 ±6,539 ±10 MB_8 ±7,630 ±7,640 ±6,568 ±6,578 ±10 MB_8 ±7,648 ±7,657 ±6,585 ±6,594 ±9 LB ±7,687 ±7,695 ±6,623 ±6,631 ±8 LB_1 ±7,719 ±7,724 ±6,655 ±6,660 ±5 LB_1A ±7,740 ±7,747 ±6,675 ±6,682 ±7 LB_1B ±7,751 ±7,763 ±6,686 ±6,698 ±12 LB_1C ±7,764 ±7,782 ±6,699 ±6,717 ±18 LB_1D ±7,820 ±7,828 ±6,754 ±6,762 ±8 LB_1D ±7,836 ±7,847 ±6,769 ±6,780 ±11 LB_1E ±7,847 ±7,857 ±6,780 ±6,790 ±10 LB_1F ±7,898 ±7,919 ±6,830 ±6,851 ±21 LB_1G ±7,939 ±7,949 ±6,870 ±6,880 ±10 LB_2 ±7,975 ±7,989 ±6,906 ±6,920 ±14 LB_2B ±8,075 ±8,083 ±7,004 ±7,012 ±8 a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Pending well production, all perf intervals may not be completed ii. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations iii. Perforations are in the Beluga Gas Pool governed by CO 231A. 5. RDMO 6. Turn well over to production & flow test well 7. Test SVS as necessary once well has reached stable flow rates a. Notify state 24 hrs prior to testing within 5 days of stable production Attachments: 1. Current Schematic 2. Proposed Schematic 3. Standard Nitrogen Procedure _____________________________________________________________________________________ Updated by SAR 12-30-25 SCHEMATIC Cannery Loop Unit Pad # 3 Well: CLU-11RD API: 50-133-20559-01-00 PTD: 225-013 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / N/A 18.73 Surf 136' 13-3/8Surface 68 /L-80/ BTC 12.415 Surf 1,602 9-5/8"Intermediate 40 / L-80 / BTC 8.835 Surf 4,280(TOW) 7Intermediate 2 29 / P-110 / TXPBTC/LTC 6.184 Surf 6,279 3-1/2Prod liner 9.2 / L-80 / TH563 2.992 6,0678,161 3-1/2Tieback 9.2 / L-80 / EUE 8RD 2.992 Surf 6,067 JEWELRY DETAIL No Depth Item 1 16 Cactus CTF-ONE-CTL 11", 4" type H BPV profile, 2-3/8" NPT Control Line ports 2 355SSSV Baker Hughes BX profile SN 1948451 2.812 ID 3 6,073YJ 5.26'' Locating Bullet Seal Assembly spaced .65' off NoGo 2.93 ID 4 6,067YJ Ranger Liner Hanger and Scout Packer Assembly SBR (5.25" ID) OPEN HOLE / CEMENT DETAIL 8-1/2 Pumped 49bbl 10.5ppg FMP3000 spacer, 80bbl 12.5ppg Class G lead, 20bbl 15.3ppg Class G tail cement. Bumped plug, floats held. Lost 17bbls throughout job. CIP 10:50 12-17-25. Spacer Returns to surface no lead cement. 6 Pumped 41bbls 10.5ppg FMP300 spacer, 60bbls 12.5ppg Class G lead, 18.7bbls 15.3ppg Class G cement. Bumped plug floats held CIP 22:50 12-25-25. Lost 27.8bbls during job. Reciprocated until 80bbls into displacement. Notes 10 Short Joints w/ RA Tags 7,587, 7,076, 6,599 Deviation Max Deviation 45.6deg @ 2881, Max Dog Leg 7.9deg 860 _____________________________________________________________________________________ Updated by SAR 12-30-25 PROPOSED Cannery Loop Unit Pad # 3 Well: CLU-11RD API: 50-133-20559-01-00 PTD: 225-013 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / N/A 18.73 Surf 136' 13-3/8Surface 68 /L-80/ BTC 12.415 Surf 1,602 9-5/8"Intermediate 40 / L-80 / BTC 8.835 Surf 4,280(TOW) 7Intermediate 2 29 / P-110 / TXPBTC/LTC 6.184 Surf 6,279 3-1/2Prod liner 9.2 / L-80 / TH563 2.992 6,0678,161 3-1/2Tieback 9.2 / L-80 / EUE 8RD 2.992 Surf 6,067 JEWELRY DETAIL No Depth Item 1 16 Cactus CTF-ONE-CTL 11", 4" type H BPV profile, 2-3/8" NPT Control Line ports 2 355SSSV Baker Hughes BX profile SN 1948451 2.812 ID 3 6,073YJ 5.26'' Locating Bullet Seal Assembly spaced .65' off NoGo 2.93 ID 4 6,067YJ Ranger Liner Hanger and Scout Packer Assembly SBR (5.25" ID) OPEN HOLE / CEMENT DETAIL 8-1/2 Pumped 49bbl 10.5ppg FMP3000 spacer, 80bbl 12.5ppg Class G lead, 20bbl 15.3ppg Class G tail cement. Bumped plug, floats held. Lost 17bbls throughout job. CIP 10:50 12-17-25. Spacer Returns to surface no lead cement. 6 Pumped 41bbls 10.5ppg FMP300 spacer, 60bbls 12.5ppg Class G lead, 18.7bbls 15.3ppg Class G cement. Bumped plug floats held CIP 22:50 12-25-25. Lost 27.8bbls during job. Reciprocated until 80bbls into displacement. PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Top of CINGSA 5,973 MD/4,950 TVD Top of Beluga/Base of Cingsa 6,208 MD/5,181 TVD MB_2 7,048 7,060 5,999 6,011 12 Proposed TBD MB_2 7,064 7,076 6,015 6,027 12 Proposed TBD MB_3 7,107 7,127 6,057 6,077 20 Proposed TBD MB_5 7,267 7,275 6,214 6,222 8 Proposed TBD MB_6 7,383 7,392 6,327 6,336 9 Proposed TBD MB_6 7,451 7,460 6,393 6,402 9 Proposed TBD MB_7A 7,531 7,538 6,471 6,478 7 Proposed TBD MB_7A 7,543 7,555 6,483 6,495 12 Proposed TBD MB_7A 7,566 7,582 6,505 6,521 16 Proposed TBD MB_8 7,590 7,600 6,529 6,539 10 Proposed TBD MB_8 7,630 7,640 6,568 6,578 10 Proposed TBD MB_8 7,648 7,657 6,585 6,594 9 Proposed TBD LB 7,687 7,695 6,623 6,631 8 Proposed TBD LB_1 7,719 7,724 6,655 6,660 5 Proposed TBD LB_1A 7,740 7,747 6,675 6,682 7 Proposed TBD LB_1B 7,751 7,763 6,686 6,698 12 Proposed TBD LB_1C 7,764 7,782 6,699 6,717 18 Proposed TBD LB_1D 7,820 7,828 6,754 6,762 8 Proposed TBD LB_1D 7,836 7,847 6,769 6,780 11 Proposed TBD LB_1E 7,847 7,857 6,780 6,790 10 Proposed TBD LB_1F 7,898 7,919 6,830 6,851 21 Proposed TBD LB_1G 7,939 7,949 6,870 6,880 10 Proposed TBD LB_2 7,975 7,989 6,906 6,920 14 Proposed TBD LB_2B 8,075 8,083 7,004 7,012 8 Proposed TBD Notes 10 Short Joints w/ RA Tags 7,587, 7,076, 6,599 Deviation Max Deviation 45.6deg @ 2881, Max Dog Leg 7.9deg 860 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 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): 4,314' Casing Collapse Structural Conductor Surface 1,540 psi Intermediate 3,810 psi Production Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng N/A; N/A N/A; N/A 3,436' 4,314' 3,436' Cannery Loop Beluga Gas 20" 13-3/8" N/A; N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Cannery Loop Unit (CLU) 11RDCO 231A Same 1,413 N/A Length Anticipated Start Date: 12/25/25 Perforation Depth MD (ft): 4,280' (TOW) 6,330 psi 3,090 psi 136' 4,312' (TOW) 136' 1,602' Size 115' 9-5/8"4,280' (TOW) 1,581' MD Hilcorp Alaska, LLC Proposed Pools: TVD Burst 1,489' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 324602 / ADL 359153 / ADL 324602 225-013 50-133-20559-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Zach Browning AOGCC USE ONLY Tubing Grade: zachary.browning@hilcorp.com 208-301-0767 Drilling Manager 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: m n P s 66 t _ c N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.12.12 14:29:09 - 09'00' Sean McLaughlin (4311) 325-756 By Grace Christianson at 3:07 pm, Dec 12, 2025 5 yrs from end-date of sundried CT work. 10-407 BJM 12/12/25 TS 12/15/25JLC 12/19/2025 12/19/25 Change to Approved Well: CLU 11RD Date: 12/12/25 Well Name:CLU-11RD API Number:50-133-20559-01-00 Current Status:Laying down mills Estimated Start Date:12/25/25 Rig:Rig 147/Eline/Coil Reg. Approval Reqd?403 Date Reg. Approval Recvd: Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:225-013 (11RD) First Call Engineer:Zach Browning 208-301-0767 Second Call Engineer PTD Number:225-013 Attachments: CBL and Nitrogen Operations Program Current Schematic Change to Approved Program Request: Hilcorp is requesting a change to the approved drilling permit 225-013 for CLU-11RD. Hilcorp is requesting to add the post-rig Eline CBL logging and the Coil blowdown to the permit to drill. Current Status Laying down milling BHA / Picking up 8-1/2 drilling assembly. Change to Approved Well: CLU 11RD Date: 12/12/25 1.0 CBL and Nitrogen Operation (Post Rig Work) Pre-Sundry work: 1. Review all approved COAs from PTD 2. MIRU E-line and pressure control equipment 3. Log well with CBL tool (send results to AOGCC to review) 4. RDMO E-line Coiled Tubing Procedure 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 2500psi high a. Provide AOGCC 48hr notice for BOP test 3. MU cleanout BHA 4. RIH to PBTD, cleanout well as necessary (based on CBL depth) and swap well over to 8.4 ppg water a. If well is left with 9.4 ppg mud or less, mud may be circulated out with Nitrogen, based on Operations Engineer direction without swapping to water. 5. Once well is clean with 8.4 ppg water a. Reverse circulate water 6. RDMO CT 7. Leave N2 pressure on well when coil is rigged down Submit Completion sundry for perforating well. *** Suspend well close out drilling permit and associated sundrys with a 10-407 *** Attachments to be included 1. Coil Tubing BOP Diagram 2. Standard Nitrogen Operations Change to Approved Well: CLU 11RD Date: 12/12/25 Change to Approved Well: CLU 11RD Date: 12/12/25 _____________________________________________________________________________________ Updated by CJD 12-12-25 Current SCHEMATIC Cannery Loop Unit Pad # 3 Well: CLU-11RD API: 50-133-20559-01-00 PTD: TBD CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / N/A 18.73 Surf 136' 13-3/8Surface 68 /L-80/ BTC 12.415 Surf 1,602 9-5/8"Intermediate 40 / L-80 / BTC 8.835 Surf 4,380(TOW) IN CLU 11: Top CINGSA: 6281 MD; 4933TVD Base CINGSA: 6538 MD; 5170 TVD In CLU 11RD Proposed: WP06: Top CINGSA 5,951 MD / 4,931 TVD WP06: Base CINGSA 6,223 MD / 5,197 TVD 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 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): 9,305' Casing Collapse Structural Conductor Surface 1,540 psi Intermediate 3,810 psi Production 10,530 psi 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: Contact Email: Contact Phone: 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 zachary.browning@hilcorp.com 208-301-0767 Drilling Manager 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 Zach Browning AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 324602 225-013 50-133-20559-01-00 Hilcorp Alaska, LLC Proposed Pools: 9.3# / L-80 TVD Burst 9,284' 10,160 psi 1,489' Size 115' 9-5/8"5,574' 1,581' MD See Attached Schematic 6,330 psi 3,090 psi 136' 4,355' 136' 1,602' Anticipated Spud Date: 12/8/25 3-1/2" (cut) 9,284' Perforation Depth MD (ft): 5,595' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Cannery Loop Unit (CLU) 11RDCO 231A Same 7,894'3-1/2" 1,413 9,263' 4,306' Length N/A; N/A N/A; N/A 7,915' 4,306' 3,430' Cannery Loop Beluga Gas 20" 13-3/8" See Attached Schematic m n P s 66 t _ c N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.12.04 07:16:08 - 09'00' Sean McLaughlin (4311) 325-738 By Grace Christianson at 10:02 am, Dec 04, 2025 X 10-407 BJM 12/4/25 If this is the first well drilled by rig 147 after moving to the Kenai Peninsula in 2025, the initial BOP test must be to 5000 psi, subsequent tests to 2500 psi. All annular tests to 2500 psi. All other conditions of approval on the PTD still apply. A.Dewhurst 04DEC25 12/04/25 Well Prognosis Well: CLU 11RD Date: 12/03/25 Well Name:CLU-11RD API Number:50-133-20559-01-00 Current Status:Preparing to move Rig 147 from CCI Estimated Start Date:12/08/25 Rig:Rig 147 Reg. Approval Reqd?403 Date Reg. Approval Recvd: Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:225-013 (11RD) First Call Engineer:Zach Browning 208-301-0767 Second Call Engineer CLU 11 PTD Number:206-058 Attachments: 1.Updated PTD Drilling Program Pages: 2 (Well Summary), 3 (MOC), 8 (Drilling/Completion Summary), 10 (BOP Equipment/Requirements), 12 (BOP NU/Test), 15 (Drill 8-1/2 Hole Section), 17 (Run Int Csg), 19 (Cmt Int Csg), 20 (Drill 6 Hole), 28(BOP Schematic), 29 (Wellhead Schematic) 2.Current Schematic Change to Approved Program Request: Hilcorp is requesting a change to the approved drilling permit 225-013 for CLU-11RD. CLU-11RD was originally permitted with a Vetco 13-5/8 Multibowl and Cactus 13-5/8 x 11 Tubing head. This configuration required the 7 casing to be set on slips and the tubing head to be NU after running casing. The proposed change is to use a Cactus 13-5/8 x 11 Tubing head and Cactus 11 Multibowl. This equipment was not previously available due to well timing. This configuration allows the 7 casing to be set on a mandrel hanger. Additionally, the 7 can be run through the Cactus Multibowl, allowing full wellhead to be NU prior to the rig moving over the well. This removes an open containment activity during well operations. However, due to wellhead height, the single gate ram will be removed from the start of the well, rather than for production only as previously planned. The BOPE configuration still meets the requirements of 20 AAC 25.035 (MASP=1413psi). The updated drilling program pages are attached with this wellhead and BOPE configuration and the necessary procedure steps related to these changes. No other changes are being requested to the permit to drill currently. Current Status Rig 147 is at CCI. CLU is being prepared for the rig to move over later this week or this weekend to drill CLU 11RD. Estimated spud date is 12/8/25. Page 2 Version 2 December 3, 2025 CLU 11RD Drilling Procedure PTD# 225-013 1.0 Well Summary Well CLU 11RD Rig 147 Pad & Old Well Designation Cannery Loop Pad 3 Sidetrack Planned Completion Type 3-1/2 Production Liner w/Tieback (monobore) Target Reservoir(s) Beluga Planned Well TD, MD / TVD 8155 MD / 7089 TVD PBTD, MD / TVD 8055 MD AFE Number AFE Days AFE Amount Maximum Anticipated Pressure (Surface) 1413 psi Maximum Anticipated Pressure (Downhole/Reservoir) 2000 psi Work String 4-1/2 16.6# S-135 CDS-40 RKB 53.4 Ground Elevation 35.4 BOP Equipment 11 5M Annular BOP 11 5M Double Ram 11 5M Single Ram Page 3 Version 2 December 3, 2025 CLU 11RD Drilling Procedure PTD# 225-013 2.0 Management of Change Information Page 8 Version 2 December 3, 2025 CLU 11RD Drilling Procedure PTD# 225-013 8.0 Drilling / Completion Summary CLU 11RD is an S-shaped sidetrack development well to be drilled from Cannery Loop Pad 3. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Beluga sands. The base plan is a slant wellbore with a kickoff point at ~4280 MD. An Intermediate casing string will be run and cemented across the CINGSA gas storage pool. Maximum hole angle will be ~43 deg. and TD of the well will be 8155 TMD/ 7089 TVD. Vertical separation will be 3307 ft. Drilling operations are expected to commence approximately December 2025. The Hilcorp Rig # 147 will be used to drill the wellbore then run casing and cement. 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. Planned Pre Rig operations: - Abandon the CLU 11RD - Decomplete 3-1/2 tubing - CBL of the 9-5/8 casing - Test casing to 2500 psi General sequence of operations: 1. Rig 147 will MIRU over CLU 11RD 2. NU BOPE and test to 2500 psi. (MASP 1413psi) 3. Set 9-5/8 40# whipstock at 4280 and 60R TF. Swap well to 9.0 ppg mud. 4. Mill window with 20 of new formation. 5. Perform FIT to 12.0 ppg EMW 6. MU 8-1/2 bit with 6-3/4 tools (Triple Combo) 7. Drill 8-1/2 Intermediate hole to 6258 MD 8. Run 7 Intermediate casing. TOC planned to 3300 MD 9. Run packoff and test. 10. WOC, Split the wellhead, set slips and PO, test the break 11. Rig up eline and run CBL. Perform casing test to 3700 psi 12. MU 6 bit with 4-3/4 tools (Triple Combo) 13. Drill out casing shoe and preform FIT to 12 ppg EMW. 14. Drill 6 production hole to 8155 MD 15. RIH w/ 3-1/2 liner. Set liner and cement. Circ wellbore clean. 16. Perform Clean out run to polish bore, LDDP 17. Perform liner lap test to 2500 psi. Page 10 Version 2 December 3, 2025 CLU 11RD Drilling Procedure PTD# 225-013 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2 and 6 11 x 5M Annular BOP 11 x 5M Double Ram o Blind ram in btm cavity Mud cross 11 x 5M Single Ram (remove while drilling production hole) 3-1/8 5M Choke Line 2-1/16 x 5M Kill line 3-1/8 x 2-1/16 5M Choke manifold Standpipe, floor valves, etc Initial Test: 250/2500 (Annular 2500 psi) Subsequent Tests: 250/2500 (Annular 2500 psi) Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: Well control event (BOPs utilized to shut in the well to control influx of formation fluids). 24 hours notice prior to testing BOPs. Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email: bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 12 Version 2 December 3, 2025 CLU 11RD Drilling Procedure PTD# 225-013 with 5-1/2 liners. 11.0 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 11 x 5M BOP as follows: BOP configuration from Top down: 11 x 5M annular BOP/11 x 5M double ram /11 x 5M mud cross Double ram should be dressed with 2-7/8 x 5 variable bore rams 7 fixed bore rams in top cavity,blind ram in btm cavity. Single ram should be dressed with 2-7/8 x 5 variable bore rams N/U bell nipple, install flowline. Install (2) manual valves & a check valve on kill side of mud cross. Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 3. Run BOPE test plug. 4. Test BOPE. Test BOP to 250/2500 psi for 5/10 min. 7 test joint required for FBR Test VBRs with 4-1/2 and 3-1/2 test joint Test annular to 250/2500 psi for 5/10 min with a 3-1/2 test joint Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 5. Mix 9.0 ppg 6% KCL PHPA mud system. 6. Rack back as much 4-1/2 DP in derrick as possible to be used while drilling the hole section. Page 15 Version 2 December 3, 2025 CLU 11RD Drilling Procedure PTD# 225-013 CINGSA gas storage reservoir between 5951 6223 MD. Critical Casing Shoe: Geologist to confirm that the CINGSA gas storage interval has been drilled and casing shoe is set at the base of the UB 1/2. 10. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU. 11. Clean out wellbore as necessary 12. TOH with drilling assembly, handle BHA as appropriate. 13. Confirm 7 FBR previously installed in BOP stack and tested with 7 test joint. 14. Shut the blind ram and changeout 2-7/8 x 5 VBRs for 7 FBR. Test to 250psi low / 2500psi high with 7 test joint. 14.0 Run 7 Intermediate Casing 1. R/U and pull wear bushing. 2. R/U Parker 7 casing running equipment. Ensure 7 TXP and LTC x CDS40 XO on rig floor and M/U to FOSV. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. Ensure all casing has been drifted to 6 on the location prior to running. Note that 29# drift is 6.125 Be sure to count the total # of joints on the location before running. Keep hole covered while R/U casing tools. Record ODs, IDs, lengths, S/Ns of all components w/ vendor & model info. 3. P/U shoe joint, visually verify no debris inside joint. 4. Continue M/U & thread locking 80 shoe track assembly consisting of: 7 Float Shoe 1 joint 7 BTC, 1 Centralizer 10 from bottom w/ stop ring 7 Float Collar 1 joint 7 BTC, 1 Free floating centralizer 7 Landing collar 5. Continue running 7 intermediate casing Centralization: 1 centralizer every joint to the window Page 17 Version 2 December 3, 2025 CLU 11RD Drilling Procedure PTD# 225-013 6. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 7. Slow in and out of slips. 8. Lower string to planned depth and land hanger confirm a connection is not across wellhead profile. 9. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Stage up pump slowly and monitor losses closely while circulating. 10. After circulating, lower string and confirm connection is not across the wellhead. Cement to surface is not expected. However, in the event cement is circulated out ensure hose is in place to take returns to the cellar. 15.0 Cement 7 Intermediate Casing 1. Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume is available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. Determine which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. Ensure adequate amount of water for mix fluid is heated and available in the water tanks. Confirm positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses Review test reports and ensure pump times are acceptable. Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 2. Document efficiency of all possible displacement pumps prior to cement job. 3. Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 4. R/U cement line (if not already done so). 5. Fill surface cement lines with water and pressure test. 6. Pump remaining 60 bbls 10.5 ppg tuned spacer. Page 19 Version 2 December 3, 2025 CLU 11RD Drilling Procedure PTD# 225-013 a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, and cementers during the entire job. 11. Ensure rig pump is used to displace cement. 12. Displacement volume is in Table above. 13. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 14. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 1 shoe track volume, ±4 bbls before consulting with Drilling Engineer. 15. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 16. Not expected, but be prepared for cement returns to surface. Cement returns to be taken to cellar. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. 17. R/D cement equipment. Flush out wellhead with FW. 18.Back out and L/D landing joint. Flush out wellhead with FW. 19.M/U pack-off running tool and pack-off to bottom of landing joint. Set casing hanger packoff. 20.Lay down landing joint and pack-off running tool. 21.Test packoff to minimum 3700psi. 22.WOC to 500psi compressive strength. Confirm no flow of OA. Split the 13-3/8 casing spool. Set 7 slips, cut casing, install pack off. 23.Nipple up 13-3/8 spool and test to 2500 psi. 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 casing is reciprocated or rotated during the job Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold Page 20 Version 2 December 3, 2025 CLU 11RD Drilling Procedure PTD# 225-013 Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note if pre flush or cement returns at surface & volume Note time cement in place Note calculated top of cement Add any comments which would describe the success or problems during the cement job Send final As-Run casing tally & casing and cement report to sean.mclaughlin@hilcorp.com and cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 16.0 Drill 6 Hole Section 1. Swap 7 FBR to 2-7/8 x 5 VBR, test with 4-1/2 and 3-1/2 test joints to 2500 psi.Test all breaks. Pull test plug, run and set wear bushing. 2.Run CBL across the 7 casing. (1000 psi compressive strength required prior to CBL) DE to submit log to CINGSA AOGCC approval of CBL required prior to drilling ahead. 3. Ensure BHA components have been inspected previously. 4. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 5. TIH, conduct shallow hole test of MWD and confirm all LWD functioning properly. 6. Ensure TF offset is measured accurately and entered correctly into the MWD software. 7. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 8. Workstring will be 4.5 16.6# S-135 CDS40. Ensure to have enough 4-1/2 DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 9. 6 hole section mud program summary: Starting mud weight for the production interval is 9.0 ppg or the intermediate interval mud weight at TD, whichever is heavier. Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the drillers console, Co Man office, and Toolpusher office. Page 29 Version 2 December 3, 2025 CLU 11RD Drilling Procedure PTD# 225-013 21.0 BOP Schematic Single Gate to be removed for production hole due to wellhead height. Page 30 Version 2 December 3, 2025 CLU 11RD Drilling Procedure PTD# 225-013 22.0 Wellhead Schematic State/Prov:Alaska Country:USA 35.0'Date Completed:5/18/2006 Ground Level (above MSL):RKB (above GL):21.0' Revised By:D Ambruz Schematic Revision Date:3/11/2025 ngle @KOP and Depth:± 3° / 220 ft @ 650' MD Angle/Perfs:4º 1ºMaximum Deviation:45.6º @ 2,883' Well Name & Number:Cannery Loop #11 Lease:ADL-324602 County or Parish:Kenai Peninsula Borough TD 9,305' MD 7,915 TVD Excape System Details - 11 Excape modules placed -Green control line fired module 1 -Yellow control line fired modules 2 thru 7 -Red contol line fired modules 8 thru 11 - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB)( Beluga Zones): Mod-11 6,593' - 6,603' Not Shot UBE 6,726' - 6,746' (7/7/15) (Isolated) Mod-10 7,373' - 7,383' (Perfed 5/1/07) (Isolated) Perf: 7,383' - 7,400' (Perfed 5/1/07) (Isolated) Mod- 9 7,472' - 7,482' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 8 7,686' - 7,696' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 7 7,868' - 7,878' Not Shot Mod- 6 7,929' - 7,939' (Perfed 4/1/07) (Isolated) Perf: 7,939' - 7,946' (Perfed 4/1/07) (Isolated) Mod- 5 8,208' - 8,218' (Frac'd 9/28/06) (Isolated) Mod- 4 8,384' - 8,394' (Frac'd 9/28/06) (Isolated) Mod- 3 8,496' - 8,506' (Frac'd 9/28/06) (Isolated) Mod- 2 8,606' - 8,616' (Frac'd 9/28/06) (Isolated) Mod- 1 9,085' - 9,095' (Frac'd 9/28/06) (Isolated) Top of Cement (Bond Log) @ 4,440' MD Excape System Details - 10 Conventional flappers- Mod-1 no flapper - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module-11 6,613'Module-10 7,390'Module- 9 7,490'Module- 8 7,703' (Broken CT 9/28/2006)Module- 7 7,886'Module- 6 7,948'Module- 5 8,227' (Broken CT 9/28/2006)Module- 4 8,403' (Broken CT 9/28/2006)Module- 3 8,515'Module- 2 8,625' (Broken CT 9/28/2006) Permit #: 206-058API #: 50-133-20559-00Property Des:ADL-324602KB Elevation:56' (21'AGL)Lat:60°33' 10.707" NLong: 151°13' 07.001" WSpud Date: 04/28/2006TD Reached: 05/11/2006Rig Released:05/15/2006 CLU-11 Pad-3 2,491' FSL, 2,291' FWL Sec. 4, T5N, R11W, S.M. Tree cxn = 6-1/2" Otis PBTD 4,306' MD 3,430' TVD Velocity String 1-3/4" HO70FF (0.125" WT) Install 7/21/07; Partially removed Top Bottom MD 7,912' 8,185' TVD 6,522' 6,795' BHA: 2.5" OD x 1.5" ID grapple connector 2.5" OD x 1.5" ID x 10' weight bar w/ drain 2.5" OD x 1.135" ID NoGo profile nipple 2.48" OD x 1.5" guide nose Slickline tag EOVstrg 8225' (4/18/12) Conductor 20" X-52 131 ppf Top Bottom MD 0' 136' TVD 0' 136' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,602' TVD 0' 1,489' 16" hole Cmt w/ 516 sks (228 bbls) of 12.0 ppg, Type 1 cmt Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,595' TVD 0' 4,355' 12-1/4" hole Cmt w/ 95 sks (36 bbls) 12.5 ppg class G Lead, & 237 sks (49 bbls) 15.8 ppg class G Tail Production Tubing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 4,406' 9,284' TVD 3,500' 7,894' 8-1/2" hole Cmt w/ 1,550 sks (325 bbls) of 15.8 ppg, class G cmt VELOCITY STRING FISH: Top of Coil:1-3/4" coil @ 7,912' cut with radial torch, milled down with 2.75" mill on 6/13/15 (Fill on backside of coil) Fish:4.1' of 1.0" wt bar lost 6/06/15 @ 7,919' Fish:4.0' of 1.0" wt bar lost 6/04/15 @ 8,162' Plug:PXN plug set 5/16/15 @ 8,209' Sterling C1 Interval: SCHEMATIC Cast Iron Bridge Plug @ 7,840' Dump bail 10' of cement UBE Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date UB-B 6,583' 6,592' 2-3/8" 5 Isolated 02-12-16 UB-B 6,591' 6,601' 2-1/2" 5 Isolated 04-21-21 Cast Iron Bridge Plug @ 6,700' Dump bail 10' of cement TOC 6,690' 02/10/16 UB-B @ 6 700' CINGSA Base 6,538 MD 5,170 TVD 9-5/8" CIBP Set @ 4350' w/ 25' cement - TOC @ 4306' (2/21/25) Cut tubing @ 4406' (2/14/25)3-1/2" CIBP @ 6553' w/ 25' of cement - TOC 6528' (2/13/25) I t di t C CINGSA Top 6,282 MD 4,933 TVD 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 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): 9,305' Casing Collapse Structural Conductor Surface 1,540 psi Intermediate 3,810 psi Production 10,530 psi 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: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng N/A; N/A N/A; N/A 7,915' 4,306' 3,430' Cannery Loop Beluga Gas 20" 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Cannery Loop Unit (CLU) 11CO 231A Same 7,894'3-1/2" 1,413 9,263' 4,306' Length Anticipated Spud Date: 12/15/25 3-1/2" (cut) 9,284' Perforation Depth MD (ft): 5,595' See Attached Schematic 6,330 psi 3,090 psi 136' 4,355' 136' 1,602' Size 115' 9-5/8"5,574' 1,581' MD Hilcorp Alaska, LLC Proposed Pools: 9.3# / L-80 TVD Burst 9,284' 10,160 psi 1,489' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 324602 206-058 50-133-20559-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Sean Mclaughlin AOGCC USE ONLY Tubing Grade: sean.mclaughlin@hilcorp.com 907-223-6784 Drilling Manager 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: m n P s 66 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 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.10.23 07:57:53 - 08'00' Sean McLaughlin (4311) 325-662 By Grace Christianson at 9:50 am, Oct 23, 2025 SFD 10/31/2025BJM 10/31/25 SFD CLU 11RD SFD 10-407 50-133-20559-01-00 SFD Request to change rig for CLU 11RD. DSR-10/30/25 225-013 SFD 11/03/25 Well Prognosis Well: CLU 11 Date: 10/20/25 Well Name:CLU-11 API Number:50-133-20559-00-00 Current Status:Moving Rig 147 from BRU Estimated Start Date:12/15/25 Rig:Rig 147 Reg. Approval Reqd?403 Date Reg. Approval Recvd: Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:225-013 (11RD) First Call Engineer:Sean Mclaughlin 907-223-6784 Second Call Engineer CLU 11 PTD Number:206-058 Attachments: 1.Wellbore Schematic 2.BOPE Schematic 3.Choke Schematic Change to Approved Program Request: Hilcorp is requesting a change to the approved drilling permit 225-013 for CLU-11RD. CLU-11RD was originally permitted to be drilled with Rig 169. However, Hilcorp is planning to drill CLU-11RD with rig 147. No other changes are being requested to the permit to drill currently. Current Status Rig 147 is being moved from BRU to Kenai, once it arrives it will go under a short maintenance program. Once completed, the rig will move to CLU to drill CLU 11RD, estimated spud date 12/15/25. Hilcorp is requesting a change to the approved drilling permit 225-013 for CLU-11RD. No other changes are being requested to the permit to drill State/Prov:Alaska Country:USA 35.0'Date Completed:5/18/2006 Ground Level (above MSL):RKB (above GL):21.0' Revised By:D Ambruz Schematic Revision Date:3/11/2025 ngle @KOP and Depth:± 3° / 220 ft @ 650' MD Angle/Perfs:4º 1ºMaximum Deviation:45.6º @ 2,883' Well Name & Number:Cannery Loop #11 Lease:ADL-324602 County or Parish:Kenai Peninsula Borough TD 9,305' MD 7,915 TVD Excape System Details - 11 Excape modules placed -Green control line fired module 1 -Yellow control line fired modules 2 thru 7 -Red contol line fired modules 8 thru 11 - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB)( Beluga Zones): Mod-11 6,593' - 6,603' Not Shot UBE 6,726' - 6,746' (7/7/15) (Isolated) Mod-10 7,373' - 7,383' (Perfed 5/1/07) (Isolated) Perf: 7,383' - 7,400' (Perfed 5/1/07) (Isolated) Mod- 9 7,472' - 7,482' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 8 7,686' - 7,696' (Frac'd 9/28/06, Cmt Sqzd 4/3/07) Mod- 7 7,868' - 7,878' Not Shot Mod- 6 7,929' - 7,939' (Perfed 4/1/07) (Isolated) Perf: 7,939' - 7,946' (Perfed 4/1/07) (Isolated) Mod- 5 8,208' - 8,218' (Frac'd 9/28/06) (Isolated) Mod- 4 8,384' - 8,394' (Frac'd 9/28/06) (Isolated) Mod- 3 8,496' - 8,506' (Frac'd 9/28/06) (Isolated) Mod- 2 8,606' - 8,616' (Frac'd 9/28/06) (Isolated) Mod- 1 9,085' - 9,095' (Frac'd 9/28/06) (Isolated) Top of Cement (Bond Log) @ 4,440' MD Excape System Details - 10 Conventional flappers- Mod-1 no flapper - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module-11 6,613'Module-10 7,390'Module- 9 7,490'Module- 8 7,703' (Broken CT 9/28/2006)Module- 7 7,886'Module- 6 7,948'Module- 5 8,227' (Broken CT 9/28/2006)Module- 4 8,403' (Broken CT 9/28/2006)Module- 3 8,515'Module- 2 8,625' (Broken CT 9/28/2006) Permit #: 206-058API #: 50-133-20559-00Property Des:ADL-324602KB Elevation:56' (21'AGL)Lat:60°33' 10.707" NLong: 151°13' 07.001" WSpud Date: 04/28/2006TD Reached: 05/11/2006Rig Released:05/15/2006 CLU-11 Pad-3 2,491' FSL, 2,291' FWL Sec. 4, T5N, R11W, S.M. Tree cxn = 6-1/2" Otis PBTD 4,306' MD 3,430' TVD Velocity String 1-3/4" HO70FF (0.125" WT) Install 7/21/07; Partially removed Top Bottom MD 7,912' 8,185' TVD 6,522' 6,795' BHA: 2.5" OD x 1.5" ID grapple connector 2.5" OD x 1.5" ID x 10' weight bar w/ drain 2.5" OD x 1.135" ID NoGo profile nipple 2.48" OD x 1.5" guide nose Slickline tag EOVstrg 8225' (4/18/12) Conductor 20" X-52 131 ppf Top Bottom MD 0' 136' TVD 0' 136' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,602' TVD 0' 1,489' 16" hole Cmt w/ 516 sks (228 bbls) of 12.0 ppg, Type 1 cmt Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,595' TVD 0' 4,355' 12-1/4" hole Cmt w/ 95 sks (36 bbls) 12.5 ppg class G Lead, & 237 sks (49 bbls) 15.8 ppg class G Tail Production Tubing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 4,406' 9,284' TVD 3,500' 7,894' 8-1/2" hole Cmt w/ 1,550 sks (325 bbls) of 15.8 ppg, class G cmt VELOCITY STRING FISH: Top of Coil:1-3/4" coil @ 7,912' cut with radial torch, milled down with 2.75" mill on 6/13/15 (Fill on backside of coil) Fish:4.1' of 1.0" wt bar lost 6/06/15 @ 7,919' Fish:4.0' of 1.0" wt bar lost 6/04/15 @ 8,162' Plug:PXN plug set 5/16/15 @ 8,209' Sterling C1 Interval: SCHEMATIC Cast Iron Bridge Plug @ 7,840' Dump bail 10' of cement UBE Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date UB-B 6,583' 6,592' 2-3/8" 5 Isolated 02-12-16 UB-B 6,591' 6,601' 2-1/2" 5 Isolated 04-21-21 Cast Iron Bridge Plug @ 6,700' Dump bail 10' of cement TOC 6,690' 02/10/16 UB-B @ 6 700' CINGSA Base 6,538 MD 5,170 TVD 9-5/8" CIBP Set @ 4350' w/ 25' cement - TOC @ 4306' (2/21/25) Cut tubing @ 4406' (2/14/25)3-1/2" CIBP @ 6553' w/ 25' of cement - TOC 6528' (2/13/25) I t di t C CINGSA Top 6,282 MD 4,933 TVD Page 29 Version 1 October 20, 2025 CLU 11RD Drilling Procedure PTD# 225-013 21.0 BOP Schematic Single Gate to be removed for production hole due to wellhead height. Page 33 Version 1 October 20, 2025 CLU 11RD Drilling Procedure PTD# 225-013 25.0 Choke Manifold Schematic 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: Cannery Loop Unit, Beluga Gas Pool, CLU-11RD Hilcorp Alaska, LLC Permit to Drill Number: 225-013 Surface Location: 2491' FSL, 2291' FWL, Sec 4, T5N, R11W, SM, AK Bottomhole Location: 660' FSL, 475' FEL, Sec 5, T5N, R11W, 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 13th day of March 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.13 14:02:49 -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: 8,154' TVD: 7,089' 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): 53.4' 15. Distance to Nearest Well Open Surface: x-280668 y-2396065 Zone-4 35.4 to Same Pool: 2469' to CLU 15 16. Deviated wells:Kickoff depth: 4,300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 46 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 8-1/2" 7" 29# P-110 TXP 6,258' Surface Surface 6,258' 5,232' 6" 3-1/2" 9.2# L-80 Hyd 563 2,096' 6,058 5,036' 8,154' 7,089' Tieback 3-1/2" 9.2# L-80 EUE 8RD 6,058 Surface Surface 6,058 5,036' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): 7912' TVD 136' 1489' 4355' 7894' 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 CLU-11RD Cannery Loop Unit Beluga Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Will be plugged PreDrill 332 sx 9284'3-1/2" 9-5/8" 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 Tieback Assy. 1413 705' FSL, 351' FEL, Sec 5, T5N, R11W, SM, AK 660' FSL, 475' FEL, Sec 5, T5N, R11W, SM, AK LOCI 78-156 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 2491' FSL, 2291' FWL, Sec 4, T5N, R11W, SM, AK ADL 365454 / ADL 359153 / ADL 324602 18. Casing Program:Top - Setting Depth - BottomSpecifications 2000 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) 523 ft3 377 ft3 6690'5314' Effect. Depth MD (ft):Effect. Depth TVD (ft): 9305'7915' LengthCasing 6700' Size Will be plugged PreDrill Conductor/Structural 20"115' Authorized Title: Authorized Signature: Authorized Name: Production Liner 5574' 9263' Intermediate Driven 136' 1602'13-3/8"516 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): 1581' 5595' 1550 sx 3/23/2024 2991' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 616 Cement Volume MD s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Gavin Gluyas at 3:46 pm, Feb 11, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.02.11 15:24:06 - 09'00' Sean McLaughlin (4311) 3/23/2025 280,663.58 50-133-20559-01-00 2,396,073.97 Variance to 20 AAC 25.030(e) approved. See section 9.0 A.Dewhurst 12MAR25 225-013 BOP test to 2500 psi. Submit FIT/LOT data within 48 hrs of obtaining results. DSR-2/18/25BJM 3/12/25 SFD Submit 7" CBL and obtain approval before drilling 6-1/8" hole. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.13 14:03:04 -08'00' 03/13/25 03/13/25 RBDMS JSB 031425 CLU 11RD Drilling Program Cannery Loop February 6, 2025 CLU 11RD Drilling Procedure Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Current Schematic (Plugging Plan) .............................................................................................6 7.0 Planned Wellbore Schematic........................................................................................................7 8.0 Drilling / Completion Summary...................................................................................................8 9.0 Mandatory Regulatory Compliance / Notifications....................................................................9 10.0 R/U and Preparatory Work........................................................................................................11 11.0 BOP N/U and Test........................................................................................................................12 12.0 Set Whipstock / Mill Window.....................................................................................................12 13.0 Drill 8-1/2” Hole Section..............................................................................................................14 14.0 Run 7” Intermediate Casing.......................................................................................................15 15.0 Cement 7” Intermediate Casing.................................................................................................17 16.0 Drill 6” Hole Section....................................................................................................................20 17.0 Run 3-1/2” Production Liner......................................................................................................22 18.0 Cement 3-1/2” Production Liner................................................................................................25 19.0 3-1/2” Liner Tieback Polish Run................................................................................................28 20.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................28 21.0 BOP Schematic.............................................................................................................................29 22.0 Wellhead Schematic.....................................................................................................................30 23.0 Anticipated Drilling Hazards......................................................................................................31 24.0 Hilcorp Rig 169 Layout...............................................................................................................32 25.0 Choke Manifold Schematic.........................................................................................................33 26.0 Casing Design Information.........................................................................................................33 27.0 8-1/2” Hole Section MASP..........................................................................................................35 28.0 6” Hole Section MASP.................................................................................................................36 29.0 Spider Plot (660’).........................................................................................................................37 30.0 Surface Plat (As-Built NAD27 & NAD83).................................................................................38 Page 2 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 1.0 Well Summary Well CLU 11RD Rig 169 Pad & Old Well Designation Cannery Loop – Pad 3 Sidetrack Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Beluga Planned Well TD, MD / TVD 8155 MD / 7089’ TVD PBTD, MD / TVD 8055’ MD AFE Number AFE Days AFE Amount Maximum Anticipated Pressure (Surface)1413 psi Maximum Anticipated Pressure (Downhole/Reservoir)2000 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 53.4 Ground Elevation 35.4 BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 2.0 Management of Change Information Page 4 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 3.0 Tubular Program: Hole Section OD (in) ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) 8-1/2”7 6.184 6.125 7.875 29 P110 TXP & LTC 11,220 8530 929 6”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 *Ensure at least 100’ of overlap between casing and liner 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellview. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update x Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 2. Spills: x Notify Drlg Manager 1. Sean McLaughlin: C: 907-223-6784 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to Sean.McLaughlin@hilcorp.com,andcdinger@hilcorp.com 5.6 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 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 6.0 Current Schematic (Plugging Plan) Page 7 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 7.0 Planned Wellbore Schematic Page 8 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 8.0 Drilling / Completion Summary CLU 11RD is an S-shaped sidetrack development well to be drilled from Cannery Loop Pad 3. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Beluga sands. The base plan is a slant wellbore with a kickoff point at ~4300’ MD. An Intermediate casing string will be run and cemented across the CINGSA gas storage pool. Maximum hole angle will be ~43 deg. and TD of the well will be 8155’ TMD/ 7089’ TVD. Vertical separation will be 3307 ft. Drilling operations are expected to commence approximately March 2025. The HilcorpRig # 169 will be used to drill the wellbore then run casing and cement. 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. Planned Pre Rig operations: - Abandon the CLU 11RD - Decomplete 3-1/2” tubing - CBL of the 9-5/8” casing - Test casing to 2500 psi General sequence of operations: 1. Rig 169 will MIRU over CLU 11RD 2. NU BOPE and test to 2500 psi. (MASP 1413psi) 3. Set 9-5/8” 40# whipstock at 4300’ and 60R TF. Swap well to 9.0 ppg mud. 4. Mill window with 20’ of new formation. 5. Perform FIT to 12.0 ppg EMW 6. MU 8-1/2” bit with 6-3/4” tools (Triple Combo) 7. Drill 8-1/2” Intermediate hole to 6258’ MD 8. Run 7” Intermediate casing. TOC planned to 3300’ MD 9. WOC, Split the wellhead, set slips and PO, test the break 10. Rig up eline and run CBL. Perform casing test to 3700 psi 11. MU 6” bit with 4-3/4” tools (Triple Combo) 12. Drill out casing shoe and preform FIT to 12 ppg EMW. 13. Drill 6” production hole to 8155’ MD 14. RIH w/ 3-1/2” liner. Set liner and cement. Circ wellbore clean. 15. Perform Clean out run to polish bore, LDDP 16. Perform liner lap test to 2500 psi. 17. Run 3-1/2” tie back completion. An Intermediate casing string will bepp run and cemented across the CINGSA gas storage pool. , CBL Page 9 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 18. Land hanger and test.MIT-T to 2500 psi, MIT-IA to 2500 psi 19. ND BOPE, NU tree and test void Reservoir Evaluation Plan: Intermediate Hole: Triple Combo Production Hole: Triple Combo 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of CLU 11RD. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be 250/2500 psi & subsequent tests of the BOP equipment will be to 250/2500 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x VARIENCE REQUEST: Test 7” intermediate to 3700 psi (50% of 26# L-80 burst). The 29# P110 casing is being run because it is currently in stock in Kenai and is not needed for design requirements. Also, the shoe track will be 26# L80. The MASP for the well is 1413 psi. Variance to 20 AAC 25.030(e) approved. -bjm Page 10 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2” and 6” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram (remove while drilling production hole) x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/2500 (Annular 2500 psi) Subsequent Tests: 250/2500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to testing BOPs. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email:bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 11 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 10.0 R/U and Preparatory Work 1. Level pad and ensure enough room for layout of rig footprint and R/U. 2. Layout Herculite on pad to extend beyond footprint of rig. 3. R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 4. After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 5. 8-1/2” hole section mud program summary: Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 4300’- 6258’8.8– 9.5 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for 8.8 – 9.5 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 6. Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes Page 12 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx with 5-1/2” liners. 11.0 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 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 7” fixed bore rams in top cavity,blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 3. Run BOPE test plug. 4. Test BOPE. x Test BOP to 250/2500 psi for 5/10 min. x 7” test joint required for FBR x Test VBR’s with 4-1/2” and 3-1/2 test joint x Test annular to 250/2500 psi for 5/10 min with a 3-1/2” test joint x Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 5. Mix 9.0 ppg 6% KCL PHPA mud system. 6. Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. 12.0 Set Whipstock / Mill Window Operation Steps: 1. Pull test plug. Set wear bushing in wellhead. Ensure ID of wear bushing > 8.5”. 2. Make up the WIS Mechanical set Whipstock. Page 13 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 3. 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. 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. 4. Orient whipstock as directed by the directional driller. The directional plan specifies 60 deg ROHS. 5. Set the top of the whipstock at ~4300’ MD (confirm depth after RWO) x 9-5/8” Collars TBD x Ref log: CBL of 9-5/8” planned after pulling tubing x Parent well plugged to TBD 6. 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. 7. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a FIT to 12.0 ppg. ¾**Assuming the kick zone is at TD, a FIT of 12.0 ppg EMW gives a Kick Tolerance volume of 68 bbls with 9.0 ppg mud weight. ¾Monitor OA during FIT and report and change in pressure. TOC behind the 9-5/8” TBD. 8. 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. CBL found TOC outside 9-5/8" casing found at ~4000' md with some poorer cement up to 3880' md. See attached emails from Sean McLaughlin. -bjm Page 14 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx ¾Before pulling the BHA through the BOPE. 9. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP equipment is operable. 13.0 Drill 8-1/2” Hole Section 1. P/U 6-3/4” Sperry Sun motor drilling assy w/ triple combo tools (DEN, POR, RES) and 8-1/2” bit 2. Ensure BHA components have been inspected previously. 3. Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 4. Ensure TF offset is measured accurately and entered correctly into the MWD software. 5. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at ~400 gpm. 6. Production section will be drilled with a motor. Must keep up with 3 deg/100 DLS in the build section of the wellbore. 7. TIH to window. Shallow test MWD on trip in. 8. Circulate well with 8.8 ppg mud to warm up mud until good 8.8 ppg in and out. 9. Drill 8-1/2” hole to 6258’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x 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. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. x Minimize backreaming when working tight hole x CINGSA gas storage reservoir between 5951’ – 6223’ MD. x Critical Casing Shoe: Geologist to confirm that the CINGSA gas storage interval has been drilled and casing shoe is set at the base of the UB 1/2. 10. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU. Critical Casing Shoe: Geologist to confirm that the CINGSA gas storage interval hasgg been drilled and casing shoe is set at the base of the UB 1/2. ggg CINGSA gas storage reservoir between 5951’ – 6223’ MD.gg Page 15 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 11. Clean out wellbore as necessary 12. TOH with drilling assembly, handle BHA as appropriate. 13. Confirm 7” FBR previously installed in BOP stack and tested with 7” test joint. 14.0 Run 7” Intermediate Casing 1. R/U and pull wear bushing. 2. R/U Parker 7” casing running equipment. x Ensure 7”TXP and LTC x CDS40 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Ensure all casing has been drifted to 6” on the location prior to running. x Note that 29# drift is 6.125” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 3. P/U shoe joint, visually verify no debris inside joint. 4. Continue M/U & thread locking 80’ shoe track assembly consisting of: 7” Float Shoe 1 joint – 7” BTC, 1 Centralizer 10’ from bottom w/ stop ring 7” Float Collar 1 joint – 7” BTC, 1 Free floating centralizer 7” Landing collar 5. Continue running 7” intermediate casing x Centralization: x 1 centralizer every joint to the window x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 16 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx Page 17 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 6. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 7. Slow in and out of slips. 8. Lower string to planned depth and confirm a connection is not across wellhead profile. 9. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Stage up pump slowly and monitor losses closely while circulating. 10. After circulating, lower string and confirm connection is not across the wellhead. Cement to surface is not expected. However, in the event cement is circulated out ensure hose is in place to take returns to the cellar. 15.0 Cement 7” Intermediate Casing 1. Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x Determine which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x Confirm positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 2. Document efficiency of all possible displacement pumps prior to cement job. 3. Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 4. R/U cement line (if not already done so). 5. Fill surface cement lines with water and pressure test. 6. Pump remaining 60 bbls 10.5 ppg tuned spacer. 7. Mix and pump cement per below calculations, confirm actual cement volumes with cementer after TD is reached. Page 18 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 8. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to 3300. Estimated Cement Volume: 9. Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger, and continue with the cement job. 10. After pumping cement, drop wiper plug and displace cement with mud out of mud pits. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, and cementers during the entire job. Verified cement calcs. -bjm Page 19 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 11. Ensure rig pump is used to displace cement. 12. Displacement volume is in Table above. 13. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 14. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 1 shoe track volume, ±4 bbls before consulting with Drilling Engineer. 15. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 16. Not expected, but be prepared for cement returns to surface. Cement returns to be taken to cellar. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. 17. R/D cement equipment. Flush out wellhead with FW. 18. WOC to 500psi compressive strength. Confirm no flow of OA. Split the 13-3/8” casing spool. Set 7” slips, cut casing, install pack off. 19. Nipple up 13-3/8” spool and test to 2500 psi. Ensure to report the following on wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to sean.mclaughlin@hilcorp.com and cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 20 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 16.0 Drill 6” Hole Section 1. Swap 7” FBR to 2-7/8” x 5” VBR, test with 4-1/2” and 3-1/2” test joints to 2500 psi.,.Test all breaks. Pull test plug, run and set wear bushing. 2.Run CBL across the 7” casing. (1000 psi compressive strength required prior to CBL) x DE to submit log to CINGSA 3. Ensure BHA components have been inspected previously. 4. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 5. TIH, conduct shallow hole test of MWD and confirm all LWD functioning properly. 6. Ensure TF offset is measured accurately and entered correctly into the MWD software. 7. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 8. Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 9. 6” hole section mud program summary: Starting mud weight for the production interval is 9.0 ppg or the intermediate interval mud weight at TD, whichever is heavier. Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 6258’- 8155’9.0 – 9.5 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation:6% KCL EZ Mud DP Submit field copy of CBL to AOGCC as soon as practical. SFD Run CBL across the 7” casing. Page 21 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 9.5 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 10. TIH w/ 4-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 11. R/U and test casing to 3700 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 7” 26# L-80 burst is 7240 psi / 2 = 3620 psi. (Test to 26# L- 80 requirement due to shoe track) 12. Drill out shoe track and 20’ of new formation. 13. CBU and condition mud for FIT. 14. Conduct FIT to 12 ppg (8.5 ppg BHP, 9.2 ppg MW = unlimited bbl KTV) 15. Drill 6” hole section to 8155’ MD / 7089’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~200-270 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. Halfway through to interval make a wiper trip to the shoe. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. x LC Risk is UB3/4: Minimize ECD, Surge, and ROP when drilling through the UB3/4 to reduce LC risk. Include background LCM and Black Products in the mud 16. At TD; pump sweeps, CBU, and pull a wiper trip back to the 7” shoe. 17. TOH with the drilling assy, standing back enough drill pipe for the upcoming liner run 18. POOH LDDP and BHA. 19. Ensure 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint Page 22 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 17.0 Run 3-1/2” Production Liner 1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” Liner x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 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 (1) Joint with Baker landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 4. Continue running 3-1/2” production liner x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint to the 7” window. Leave the centralizers free floating. 5. Continue running 3-1/2” production liner Page 23 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx Page 24 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 6. Run in hole w/ 3-1/2” liner to the 7” shoe. 7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 11. Set casing slowly in and out of slips. 12. PU 3-1/2” X 7” liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 15. Stage pump rates up slowly to circulating rate. Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 25 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 18.0 Cement 3-1/2” Production Liner 1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of cementing equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 3. Pump 5 bbls spacer. 4. Test surface cmt lines to 4500 psi. 5. Pump remaining spacer. 6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Page 26 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx Estimated Total Cement Volume: 7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 8. Displace cement at max rate of 4 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 9. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 10. Bump the plug and pressure up to up as required by Hanger provider to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 11. Slack off total liner weight plus 30k to confirm hanger is set. Verified cement calcs. -bjm Page 27 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 12. Do not overdisplace by more than 2x shoe track volume. Shoe track volume is 0.7 bbls. 13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. 15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17. Pressure up drill pipe to 500 psi and pick up to remove the packoff bushing from the nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Ensure to report the following on wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Page 28 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 19.0 3-1/2” Liner Tieback Polish Run 1. No liner cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. 2. Test liner lap to 2500 psi after cement has reached 500 psi compressive strength. 10 min operational assurance test. 3. PU liner tieback polish mill assy and RIH on drillpipe. 4. RIH to top of liner assembly and establish parameters. Polish tieback receptacle. 5. POOH, and LDDP and polish mill. 20.0 3-1/2” Tieback Run, ND/NU, RDMO 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 8rd x SSSV required ~350’ 2. Swap the well over to CI Water 3. Space out and land seal bore in tie back sleeve. RILDs. 4. Test IA to 2500 psi and tubing to 2500 psi. Charted 30 min. 5. Install BPV in wellhead. 6. ND BOPE, NU tree, test void 7. Rig Down Page 29 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 21.0 BOP Schematic Single Gate to be removed for production hole due to wellhead height. Page 30 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 22.0 Wellhead Schematic Page 31 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 23.0 Anticipated Drilling Hazards 8-1/2 and 6” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal pressures are present in this hole section. Page 32 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 24.0 Hilcorp Rig 169 Layout Page 33 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 25.0 Choke Manifold Schematic 26.0 Casing Design Information Page 34 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx Page 35 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 27.0 8-1/2” Hole Section MASP Page 36 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 28.0 6” Hole Section MASP MD TVD Planned Top: 6,259 5,232 Planned TD: 8,155 7,089 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad KOP 3426 1578 Depleted gas 8.9 0.46 Top CINGSA 4913 1930 Depleted gas 7.6 0.39 Base CINGSA 5179 1930 Depleted gas 7.2 0.37 Int TD (UB1/2) 5232 1930 Depleted gas 7.1 0.37 UB4 5389 400 Depleted gas 1.4 0.07 MB 7A Lower 6438 400 Depleted gas 1.2 0.06 Lower Beluga 6580 900 Depleted gas 2.6 0.14 TD (Lower Beluga 2B) 7197 2000 Depleted gas 5.4 0.28 Offset Well Pressure (MW) Well Year MW TVD CLU-10RD2 2024 8.8 - 9.1 3470' - 5147' CLU-10RD2 2024 8.9 - 9.25 5147' - 7394' Assumptions: 1. Field test data suggests the Fracture Gradient at the casing shoe is btwn 12.0 and 15.0 ppg EMW. 2. Planned mud density for the hole section is 9.2 ppg. 3. Calculations assume 0.1 ppg gas to surface Fracture Pressure at the KOP considering a full column of gas from shoe to surface: 5232 (ft) x 0.78(psi/ft)= 4081 psi 4081 (psi) - [0.1(psi/ft)*5232(ft)]= 3558 psi MASP from pore pressure during production mode (Complete evacuation to gas) 7089 (ft) x 0.28(psi/ft)= 1985 psi 1985(psi) - 0.1(psi/ft)*7089(ft) 1276 psi Summary: 1. MASP while drilling production hole is governed by gas to surface Maximum Anticipated Surface Pressure Calculation 6" Hole Section WELL: CLU 11RD wp06 FIELD: Cannery Loop Page 37 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 29.0 Spider Plot (660’) Page 38 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx 30.0 Surface Plat (As-Built NAD27 & NAD83) Page 39 Version 0.0 February 6, 2025 CLU 11RD Drilling Procedure PTD# xxx-xxx ! "# $ %&%% '( 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600 8000True Vertical Depth (800 usft/in)0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 Vertical Section at 236.40° (800 usft/in) CLU 11RD wp03 tgt01 3 5 0 0 4 0 0 0 45005 0 0 0 55006 0 0 0 6 5 0 0 7 0 0 0 7500 8000 8500 9000 9305 Cannery Loop Unit 11 7" x 8-1/2" 3-1/2" x 6-1/8" 3 5 0 0 4 0 0 0 45005 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 1 5 5 CLU 11RD wp07 KOP: 12.3º/100' : 4300' MD, 3426.03'TVD : 60° RT TF End Dir : 4317' MD, 3437.92' TVD Start Dir 4º/100' : 4337' MD, 3451.78'TVD End Dir : 5213' MD, 4208.03' TVD Total Depth : 8154.58' MD, 7089.4' TVD Top CINGSA Base CINGSA UB1/2 UB4 MB 7A Lower Lower Beluga Lower Beluga 2B 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: Cannery Loop Unit 11 Ground Level: 35.30 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2396073.97 280663.58 60° 33' 10.707 N 151° 13' 7.001 W SURVEY PROGRAM Date: 2024-09-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 191.30 4300.00 CLU 11 MWD (Cannery Loop Unit 11) 3_MWD 4300.00 4700.00 CLU 11RD wp07 (Plan: Cannery Loop 11RD) 3_MWD_Interp Azi+Sag 4700.00 6258.00 CLU 11RD wp07 (Plan: Cannery Loop 11RD) 3_MWD+IFR1+MS+Sag 6258.00 8154.58 CLU 11RD wp07 (Plan: Cannery Loop 11RD) 3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 4931.30 4878.00 5951.39 Top CINGSA 5197.30 5144.00 6222.95 Base CINGSA 5278.30 5225.00 6305.64 UB1/2 5407.30 5354.00 6437.33 UB4 6456.30 6403.00 7508.25 MB 7A Lower 6598.30 6545.00 7653.22 Lower Beluga 7000.30 6947.00 8063.62 Lower Beluga 2B REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: Cannery Loop Unit 11, True North Vertical (TVD) Reference:CLU 11RD As-Built @ 53.30usft (HEC 169) Measured Depth Reference:CLU 11RD As-Built @ 53.30usft (HEC 169) Calculation Method:Minimum Curvature Project:Kenai C.I.U. Site:Cannery Loop Unit #3 Pad Well:Plan: Cannery Loop Unit 11 Wellbore:Plan: Cannery Loop 11RD Design:CLU 11RD wp07 CASING DETAILS TVD TVDSS MD Size Name 5232.00 5178.70 6258.37 7 7" x 8-1/2" 7089.40 7036.10 8154.58 3-1/2 3-1/2" x 6-1/8" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 4300.00 45.09 232.12 3426.03 -1393.94 -1823.60 0.00 0.00 2290.31 KOP: 12.3º/100' : 4300' MD, 3426.03'TVD : 60° RT TF 2 4317.00 46.14 234.65 3437.92 -1401.19 -1833.35 12.30 60.00 2302.44 End Dir : 4317' MD, 3437.92' TVD 3 4337.00 46.14 234.65 3451.78 -1409.53 -1845.12 0.00 0.00 2316.86 Start Dir 4º/100' : 4337' MD, 3451.78'TVD 4 5213.00 11.61 249.89 4208.03 -1629.45 -2196.52 4.00 174.72 2731.25 End Dir : 5213' MD, 4208.03' TVD 5 7653.32 11.61 249.89 6598.40 -1798.35 -2657.74 0.00 0.00 3208.88 CLU 11RD wp03 tgt01 6 8154.58 11.61 249.89 7089.40 -1833.04 -2752.48 0.00 0.00 3306.99 Total Depth : 8154.58' MD, 7089.4' TVD -2100 -2025 -1950 -1875 -1800 -1725 -1650 -1575 -1500 -1425 -1350 -1275 -1200 -1125 -1050 South(-)/North(+) (150 usft/in)-2850 -2775 -2700 -2625 -2550 -2475 -2400 -2325 -2250 -2175 -2100 -2025 -1950 -1875 -1800 -1725 -1650 -1575 -1500 West(-)/East(+) (150 usft/in) CLU 11RD wp03 tgt01 3 0 0 0 3 2 5 0 3 5 0 0 3 7 5 0 4 0 0 0 4 2 5 0 4 5 0 0 4 7 5 0 Cannery Loop Unit 11 7" x 8-1/2" 3-1/2" x 6-1/8" 3 0 0 0 3 2 5 0 35 0 0 3750 40004250450047505000525055005750600062506500675070007090CLU 11RD wp07 KOP: 12.3º/100' : 4300' MD, 3426.03'TVD : 60° RT TF End Dir : 4317' MD, 3437.92' TVD Start Dir 4º/100' : 4337' MD, 3451.78'TVD End Dir : 5213' MD, 4208.03' TVD Total Depth : 8154.58' MD, 7089.4' TVD CASING DETAILS TVD TVDSS MD Size Name 5232.00 5178.70 6258.37 7 7" x 8-1/2" 7089.40 7036.10 8154.58 3-1/2 3-1/2" x 6-1/8" Project: Kenai C.I.U. 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eparation Factor4500 4800 5100 5400 5700 6000 6300 6600 6900 7200 7500 7800 8100 8400 8700 9000 Measured Depth Cannery Loop Unit 11 CLU S-7 wp16.1 No-Go Zone - Stop Drilling Collision Avoidance Required Collision Risk Procedures Req. NOERRORS WELL DETAILS:Plan: Cannery Loop Unit 11 NAD 1927 (NADCON CONUS)Alaska Zone 04 Ground Level: 35.30 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2396073.97 280663.58 60° 33' 10.707 N 151° 13' 7.001 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: Cannery Loop Unit 11, True North Vertical (TVD) Reference: CLU 11RD As-Built @ 53.30usft (HEC 169) Measured Depth Reference:CLU 11RD As-Built @ 53.30usft (HEC 169) Calculation Method:Minimum Curvature SURVEY PROGRAM Date: 2024-09-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 191.30 4300.00 CLU 11 MWD (Cannery Loop Unit 11) 3_MWD 4300.00 4700.00 CLU 11RD wp07 (Plan: Cannery Loop 11RD) 3_MWD_Interp Azi+Sag 4700.00 6258.00 CLU 11RD wp07 (Plan: Cannery Loop 11RD) 3_MWD+IFR1+MS+Sag 6258.00 8154.58 CLU 11RD wp07 (Plan: Cannery Loop 11RD) 3_MWD+IFR1+MS+Sag 0.00 35.00 70.00 105.00 140.00 175.00 Centre to Centre Separation (60.00 usft/in)4500 4800 5100 5400 5700 6000 6300 6600 6900 7200 7500 7800 8100 8400 8700 9000 Measured Depth Cannery Loop Unit 11 GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference 4300.00 To 8155.36 Project: Kenai C.I.U. Site: Cannery Loop Unit #3 Pad Well: Plan: Cannery Loop Unit 11 Wellbore: Plan: Cannery Loop 11RD Plan: CLU 11RD wp07 Ladder / S.F. Plots CASING DETAILS TVD TVDSS MD Size Name 5232.00 5178.70 6258.37 7 7" x 8-1/2" 7089.40 7036.10 8154.58 3-1/2 3-1/2" x 6-1/8" ! "# $ %&%% '( Superseded by updated directional plan wp07 (SHL coordinate correction only change). -A.Dewhurst 12MAR25 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600 8000True Vertical Depth (800 usft/in)0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 Vertical Section at 236.40° (800 usft/in) CLU 11RD wp03 tgt01 3 5 00 4 0 0 0 45005 0 0 0 55006 0 0 0 6 5 0 0 7 0 0 0 7 500 8000 8500 9000 9305 Cannery Loop Unit 11 7" x 8-1/2" 3-1/2" x 6-1/8" 3 5 0 0 4 0 0 0 45005 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 50 0 8 0 0 0 8 1 5 5 CLU 11RD wp06 KOP: 12.3º/100' : 4300' MD, 3426.06'TVD : 60° RT TF End Dir : 4317' MD, 3437.95' TVD Start Dir 4º/100' : 4337' MD, 3451.8'TVD End Dir : 5212.95' MD, 4208' TVD Total Depth : 8154.56' MD, 7089.4' TVD Top CINGSA Base CINGSA UB1/2 UB4 MB 7A Lower Lower Beluga Lower Beluga 2B 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: Cannery Loop Unit 11 Ground Level: 35.40 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2396065.82 280668.53 60° 33' 10.628 N 151° 13' 6.899 W SURVEY PROGRAM Date: 2024-09-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 191.40 4300.00 CLU 11 MWD (Cannery Loop Unit 11) 3_MWD 4300.00 4700.00 CLU 11RD wp06 (Plan: Cannery Loop 11RD) 3_MWD_Interp Azi+Sag 4700.00 6258.00 CLU 11RD wp06 (Plan: Cannery Loop 11RD) 3_MWD+IFR1+MS+Sag 6258.00 8154.56 CLU 11RD wp06 (Plan: Cannery Loop 11RD)3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 4931.40 4878.00 5951.46 Top CINGSA 5197.40 5144.00 6223.02 Base CINGSA 5278.40 5225.00 6305.72 UB1/2 5407.40 5354.00 6437.41 UB4 6456.40 6403.00 7508.34 MB 7A Lower 6598.40 6545.00 7653.30 Lower Beluga 7000.40 6947.00 8063.70 Lower Beluga 2B REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: Cannery Loop Unit 11, True North Vertical (TVD) Reference:CLU 11RD @ 53.40usft Measured Depth Reference:CLU 11RD @ 53.40usft Calculation Method:Minimum Curvature Project:Kenai C.I.U. Site:Cannery Loop Unit #3 Pad Well:Plan: Cannery Loop Unit 11 Wellbore:Plan: Cannery Loop 11RD Design:CLU 11RD wp06 CASING DETAILS 6258.35 8154.56 TVD TVDSS MD Size Name 5232.00 5178.60 7 7" x 8-1/2" 7089.40 7036.00 3-1/2 3-1/2" x 6-1/8" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 4300.00 45.09 232.12 3426.06 -1393.90 -1823.55 0.00 0.00 2290.24 KOP: 12.3º/100' : 4300' MD, 3426.06'TVD : 60° RT TF 2 4317.00 46.14 234.65 3437.95 -1401.14 -1833.30 12.30 60.00 2302.37 End Dir : 4317' MD, 3437.95' TVD 3 4337.00 46.14 234.65 3451.80 -1409.49 -1845.06 0.00 0.00 2316.79 Start Dir 4º/100' : 4337' MD, 3451.8'TVD 4 5212.95 11.61 249.88 4208.00 -1629.39 -2196.45 4.00 174.72 2731.16 End Dir : 5212.95' MD, 4208' TVD 5 7653.30 11.61 249.88 6598.40 -1798.35 -2657.74 0.00 0.00 3208.88 CLU 11RD wp03 tgt01 6 8154.56 11.61 249.88 7089.40 -1833.05 -2752.49 0.00 0.00 3307.01 Total Depth : 8154.56' MD, 7089.4' TVD -2100 -2025 -1950 -1875 -1800 -1725 -1650 -1575 -1500 -1425 -1350 -1275 -1200 -1125 -1050 South(-)/North(+) (150 usft/in)-2850 -2775 -2700 -2625 -2550 -2475 -2400 -2325 -2250 -2175 -2100 -2025 -1950 -1875 -1800 -1725 -1650 -1575 -1500 West(-)/East(+) (150 usft/in) CLU 11RD wp03 tgt01 3 0 0 0 3 2 5 0 3 5 0 0 3 7 5 0 4 0 0 0 4 2 5 0 4 5 0 0 4 7 5 0 Cannery Loop Unit 11 7" x 8-1/2" 3-1/2" x 6-1/8" 3 0 0 0 3 2 5 0 3 5 0 0 3 7 5040004250450047505000525055005750600062506500675070007090CLU 11RD wp06 KOP: 12.3º/100' : 4300' MD, 3426.06'TVD : 60° RT TF End Dir : 4317' MD, 3437.95' TVD Start Dir 4º/100' : 4337' MD, 3451.8'TVD End Dir : 5212.95' MD, 4208' TVD Total Depth : 8154.56' MD, 7089.4' TVD CASING DETAILS TVD TVDSS MD Size Name 5232.00 5178.60 6258.35 7 7" x 8-1/2" 7089.40 7036.00 8154.56 3-1/2 3-1/2" x 6-1/8" Project: Kenai C.I.U. Site: Cannery Loop Unit #3 Pad Well: Plan: Cannery Loop Unit 11 Wellbore: Plan: Cannery Loop 11RD Plan: CLU 11RD wp06 WELL DETAILS: Plan: Cannery Loop Unit 11 Ground Level: 35.40 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2396065.82 280668.53 60° 33' 10.628 N 151° 13' 6.899 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: Cannery Loop Unit 11, True North Vertical (TVD) Reference: CLU 11RD @ 53.40usft Measured Depth Reference:CLU 11RD @ 53.40usft Calculation Method:Minimum Curvature Superseded by updated directional plan wp07 (SHL coordinate correction only change). -A.Dewhurst 12MAR25 )! * ! + ,! -. ,! / / 0! 12 !"#"#$ # %&'(#) 3 *(+ 1 ,! %&'(#) 4 2 ,! , -# 1 * 5 * )! 1 6 ** ./0123 #4 5 ./015 65654 7(' ! $ 8,) 88 ) * 3 ! 4 2 3 7 3 5 03! #) ! #) #) 9:(+ ;:<+ / .+ //+' /=( &&.(. &(( +(9>/=.5 &9>.'0, / / 3 7 3 4 2 3 #) 879+/ 849+ ! #) #) #)5 0 #) #) ((( ((( / .+ (+&=/ /=( ++=& &'(/270 #)(&( +(9>(+/=5 &9>+=.., / ! :;< 32 :-< * "3 :;< 1 4*13 ! ?@@!/(/' <(</(/& == 0' && (/000='0'+ 2. " 4 3 *(+ 5 . !! 2 *:-.< :,< 849+ :,< ! :;< 879+/ :,< - = 2' (((( /+'(((((((=(( &! :;< "> *2 :;< 879+/ :,< - ! :;< 849+ :,< 1 2 :,< . ! 2 :,< 33 :;9,< ? :;9,< - :;9,< ! -. * , ((((((((((((: =/&&: ..( '/+(+///'&(.' (((( 0/++ +((('00+&/(: =(: '(' '0.&/'+&'+'' 0(( ='&& ((((((((((((: ='&(+: '(.'. '&=(/'+&'+'' 0(( .='( 0'0/0':.''((:/ .+'&: +/..' /(=((/'.==+& //.&' &'+( ((((((((((((:/ +&00': 0.=&+ &.='(/'.==+0 +&(+ &'&(( ((((((((((((:/ 0&/'.: =(&0 (=.'(/'.==+= &'&+0 (+(( Superseded by updated directional plan wp07 (SHL coordinate correction only change). -A.Dewhurst 12MAR25 * Differs from coordinates provided on surveyor's plat by 8' N/S and 5' E/W. 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(&'/ .' ='=( /0=(.' / (&(0 ' (.'( '&/( //& : /0& : ++0+=//+(/0= .00&./ .' =/++ 00('= / (.'=( ' (=/'( ''+( /+.0& : (/' : 0(/.'//(/0= .'='/ .' 0.&// /+&( / .+ ' '&'( '&( &( : /=. : 00=//(/0= .(+'0/ .' 0+.= /++/(0 / =/== ' /(='( '&( +(0 : &'=. : 00/&&/(/0= =0/0/ .' 0''(+ (0(// / //+= ' /0('( '&(( '(&' : =(= : =(+.=//'(/0= =++/ .' 0=& &0'/&' / /+.& ' (((( '&(. '/+(+ : ..( : =/&&////0= =.&+/ .' 0(+(( 0/++(0 / /.(/' $=%(C9D@(D1(@%D-.; -- ' 0(( '+' '0.& : '(' : =(/'+&/0= =(.+=/ .' +.=.' ='&&/( / (/0 7 @(ED1(@(E%FD-. ' 0(( '+' '&=( : '(.'. : ='&(+/'+&/0= 0.00+/ .' +.(= .='(((( / +0. @C9D@((ED1(@%AD-. ' '(((( '+ '.+'' : '&( : =='(/'../0= 0+(.+/ .' ++&== ''(''(( / +/ ' &(((( .+& &0+ : '0/.' : .+((/&&./0= 0(&+0/ .' +/.(+ &00+'(( / '/0+' ' +(((( &+0 +&(( : &(0& : .=++(/+/0= +&'''/ .' &.&0. &.+.('(( / '==0 ' 0(((( 0( 0'. : &0&. :/ (/.+/00 /0= +(0&/ .' &++// +=((.'(( / &''= ' =(((( /00' =/(/ : &+'(= :/ (0'=&/=/+/0= &+&+/ .' &'(& 0++./'(( / &.0' ' .(((( /0. .(0 : &=+&/ :/ /(+/.+0 /0= &/0&'/ .' &=0+ =&+.0 '(( / +0& & ((((( .=& ' ((= : +('0= :/ '''//'+/0= '.'=&/ .' &(( .'.0='(( / +0'/ & (((( &.& ' (.= : +=0. :/ 00+/'''+/0= '+0/&/ .' '=0+' (''.'(( / 0('0 & /(((( /( ' .& : +/='+ :/ ..+/'.(0 /0= '''==/ .' '0=&' '.'(( / 0/=&0 & //.& + ' /(=(( : +/.. :/ .+'&/'.==/0= ''/0/ .' '00'+' &'+('(( / 0+ 7 %FD1@AD-. & (((( + ' /./0 : +&'/ :/ //./'.==/0= '/&=/ .' '00'' /.=0 ((( / 0'=/( & '(((( + ' ./ : +'/' :/ /=/'.==/0= '(+0=/ .' '+&0' 0=((( / 0+00= & &(((( + ' '=.= : +'./0 :/ /&(0/'.==/0= =00+/ .' '&=+(' '&0=((( / 0=0+ & +(((( + ' &=0 : +&+. :/ /+.+/'.==/0= +=0/ .' '&/(' &0((( / =(+. & 0(((( + ' +=&(= : ++ :/ /==&//'.==/0= '.0(/ .' ''&'+' ++=((( / =/+& & =(((( + ' 0=(' : +0((' :/ (0'//'.==/0= (+=/ .' '===' 0/.+'((( / ='+(= Superseded by updated directional plan wp07 (SHL coordinate correction only change). -A.Dewhurst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uperseded by updated directional plan wp07 (SHL coordinate correction only change). -A.Dewhurst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uperseded by updated directional plan wp07 (SHL coordinate correction only change). -A.Dewhurst 12MAR25 !"#$ #% && #%&&' &""( &&')* +',% !"#$-#% &&-#%&&'- &&')* ."'#/ 0'1,.$+2 3$%"(**454**4"61*7""8&*"95&&7&"8*(932 ' ,.% &&':"; + ,%4&"* +< $'. =%&>? $%; $ $ ++ $</6 & + !"#"$ $ @% @%%& Superseded by updated directional plan wp07 (SHL coordinate correction only change). -A.Dewhurst 12MAR25 +#% &&- &&')* 35-35-', :< $ '. 1 +2 < ' 1 +2 6 1 +2 :< $ '. + $ $ ++ $</6 & + 5 ,%4&"* +< $'. ."'#/ 0'1,.$+2 +',% !"#$-#% &&-#%&&'- &&')* < $ '. 1 +2 ?$ < 3, ' () *+*' () *+ ",,&,+ -."//&/- ,&%% ,.,+&,/ "&00-."//&/-' * -$ ' () *+*' () *+ %%+&" %.,0%&% //+&"% 0.,,&- %&--%.,0%&%' * ' () *+*' () *+ %%+&1 -.& //+&" 0.,0&- %&%+-.&' * !"#$ ' ()1*' ()1*' "//&"% "0& "1+&/ +&+ "&/10"0&' * ' ()1*' ()1*' "/%&%" /%&"1-&-, /%,&- "-&%/%& * ' ()1*' ()1*' "-&// ++%&"%&/% +01&%" "1&%%/++%&' * ' ()/*' ()/*' "%,&"- "00&-0 "%&" ",%&%- &,"/"00&-0 ' * ' ()/*' ()/*' "%,&01 /%&"%"& /%-&, "0&%%/%& * ' ()/*' ()/*' "+%&% ++%&"-1&% +0"&1" "/&,/"++%&' * ' ()"*' ()"*' /"&1- ,0&+/ 1"&-- ,/+&- /&-/,0&+/ * ' ()"*' ()"*' "&1/ ".0+%& ,&"1 ".,"&,/ 1&+,0".0+%&' * ' ()"%*' ()"%*')" ""&1+ ".0&01 "&/1 ".0&%/ ""&",".0&01 ' * ' ()"%*' ()"%*')" ""&/0 ".%& "&1 ".,0&%% "&++0".%& * ' ()"%*' ()"%*')" "1-&0 ".%+%& ""0&0% ".-/0&% +&-"/".%+%&' * ' ()""*' ()""*';"&44 -(;";;4 ;;"&44 - ' ()""*' ()""*'";;-((;;;>*;;;6 - Superseded by updated directional plan wp07 (SHL coordinate correction only change). -A.Dewhurst 12MAR25 +#% &&- &&')* 1 +2 @ 1 +2 0A# 0@ ","&/ /.1&1234 /.1& /.+& ')""- 12342 5! 6 /.+& -.%0& ')""- 1234!"!3 ! 6 -.%0& 0."%/&%- ')""- 1234!"!3 ! 6 7 8 9(*& 8 :& ' 8 8 $ & ' ; $#< $* =& 6 :: & 8 863787'8 9 8 7& Superseded by updated directional plan wp07 (SHL coordinate correction only change). -A.Dewhurst 12MAR25 0.00 1.50 3.00 4.50 Separation Factor4500 4800 5100 5400 5700 6000 6300 6600 6900 7200 7500 7800 8100 8400 8700 9000 Measured Depth CLU S-7 wp16.1 Cannery Loop Unit 11 No-Go Zone - Stop Drilling Collision Avoidance Required Collision Risk Procedures Req. NOERRORS WELL DETAILS:Plan: Cannery Loop Unit 11 NAD 1927 (NADCON CONUS)Alaska Zone 04 Ground Level: 35.40 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2396065.82 280668.53 60° 33' 10.628 N 151° 13' 6.899 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: Cannery Loop Unit 11, True North Vertical (TVD) Reference: CLU 11RD @ 53.40usft Measured Depth Reference:CLU 11RD @ 53.40usft Calculation Method:Minimum Curvature SURVEY PROGRAM Date: 2024-09-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 191.40 4300.00 CLU 11 MWD (Cannery Loop Unit 11) 3_MWD 4300.00 4700.00 CLU 11RD wp06 (Plan: Cannery Loop 11RD) 3_MWD_Interp Azi+Sag 4700.00 6258.00 CLU 11RD wp06 (Plan: Cannery Loop 11RD) 3_MWD+IFR1+MS+Sag 6258.00 8154.56 CLU 11RD wp06 (Plan: Cannery Loop 11RD) 3_MWD+IFR1+MS+Sag 0.00 35.00 70.00 105.00 140.00 175.00 Centre to Centre Separation (60.00 usft/in)4500 4800 5100 5400 5700 6000 6300 6600 6900 7200 7500 7800 8100 8400 8700 9000 Measured Depth Cannery Loop Unit 11 GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference 4300.00 To 8155.36 Project: Kenai C.I.U. Site: Cannery Loop Unit #3 Pad Well: Plan: Cannery Loop Unit 11 Wellbore: Plan: Cannery Loop 11RD Plan: CLU 11RD wp06 Ladder / S.F. Plots CASING DETAILS TVD TVDSS MD Size Name 5232.00 5178.60 6606.59 7 7" x 8-1/2" 6761.53 6708.13 8154.56 3-1/2 3-1/2" x 6-1/8" Superseded by updated directional plan wp07 (SHL coordinate correction only change). -A.Dewhurst 12MAR25 Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME:______________________________________ PTD:_____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD:__________________________POOL:____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in nogreater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. KENAI C.L.U. 225-013 CLU-11RD BELUGA GAS 1 McLellan, Bryan J (OGC) From:Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent:Tuesday, March 11, 2025 7:22 AM To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] CLU-11RD CBL Attachments:CLU-11_CBL_19-February-2025.pdf; RE: [EXTERNAL] CLU 11RD (PTD 225-013) - Question Bryan, The whipstock set will be closer to 4275’ MD. The TOC behind the 9-5/8” is around 4000’ with some poorer quality cement above that. The sidetrack plan was not altered after viewing the results of the log. I have also attached the communication with Steve about the sidetrack depth and cement. sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, March 10, 2025 4:50 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] CLU-11RD CBL Sean, Has Hilcorp run the 9-5/8” CBL in CLU-11 yet? If so please send the log. How will the results of the log impact the sidetrack plan? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 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. 1 McLellan, Bryan J (OGC) From:Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent:Thursday, February 27, 2025 4:20 PM To:Davies, Stephen F (OGC); Cody Dinger Cc:Dewhurst, Andrew D (OGC); McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] CLU 11RD (PTD 225-013) - Question Attachments:CLU-11_CBL_19-February-2025.pdf Hi Steve, The whipstock set depth is largely driven by the abandonment of the parent well. In the case of CLU-11 the tubing was able to be recovered from 4406’. The CIBP and cement were required giving a top plugging depth of 4306’. The whipstock set will be closer to 4275’ MD. The casing was logged after the abandonment. The TOC behind the 9-5/8” is around 4000’ with some poorer quality cement above that. Marathon drilled the surface hole on CLU 11 with directional and maybe GR. Sometimes GR was in the Inteq NaviTrack but I don’t see a log for the surface hole in the Ʊles. Regards, sean From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Thursday, February 27, 2025 3:33 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] CLU 11RD (PTD 225-013) - Question Sean, Cody: While revisiƟng Hilcorp’s CLU 11RD Permit to Drill applica Ɵon along with the logs and well records for CLU 11 this aŌernoon, I found I’d made a mistake and overlooked that the CBL in CLU 11 was run inside the 3-1/2” producƟon casing and not the intermediate casing. So, please ignore the discussion about the CBL in my email below. (There is indeed cement outside of that casing string up to about 4,440’ MD.) However, re-checking my cement volume calcula Ɵons for the 9-5/8” intermediate casing string in CLU 11, I sƟll esƟmate that the top of cement will fall below Hilcorp’s planned window at 4,300’ MD. So, my quesƟons have changed only slightly: QuesƟons (Revised): x What criteria were used to select the planned kick-oī depth of 4300’ MD? x Is suĸcient cement present for the exisƟng 9-5/8” casing at this depth to isolate the planned window? x If so, what is Hilcorp’s esƟmated depth for the top of this cement? How was this determined? Please provide supporƟng details. x If not, will the lack of cement aīect the integrity of planned well CLU 11RD or isola Ɵon of the shallower strata? CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 x If Hilcorp has resisƟvity or porosity curves for the surface hole in CLU 11, could Hilcorp please provide copies of those curves to AOGCC in .las format? Thanks Again for Your Help and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain conƱdential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without Ʊrst saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Davies, Stephen F (OGC) Sent: Thursday, February 27, 2025 9:33 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] CLU 11RD (PTD 225-013) - Question Sean, Cody: While conƟnuing to review this PTD applicaƟon, I noƟced that CLU 11RD will be kicked oī through a window to be cut through the 9-5/8” casing of exisƟng well CLU 11. The planned top of this window is about 4,300’ MD. While reviewing the cemenƟng records for the parent well CLU 11, I noƟced that the top of cement for that casing string appears to lie beneath about 4,440’ MD on the cement evaluaƟon log (below). AOGCC’s records for CLU 11 not include mud log lithologic descripƟons or resisƟvity curves shallower than about 5,600’ MD, but in nearby well CLU 04 (about 1,800’ away at this depth) this porƟon of the geologic secƟon appears to contain scaƩered, sand-rich intervals. QuesƟons: x What criteria were used to select the planned kick-oī depth of 4300’ MD? x Is suĸcient cement bond present behind the exis Ɵng casing at this depth? x If so, how was this determined? x If not, will the lack of cement bonding aīect the integrity of planned well CLU 11RD? x If Hilcorp has resisƟvity or porosity curves for the surface hole in CLU 11, could Hilcorp please provide copies of those curves to AOGCC in .las format? Thanks for Your Help and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain conƱdential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without Ʊrst saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 3 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Monday, February 17, 2025 5:01 PM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Cody Dinger <cdinger@hilcorp.com> Cc: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: [EXTERNAL] CLU 11RD (PTD 225-013) - Question Hi Steve, Cody is out for the week. I don’t know why legacy surveys are oƯ for CLU-11. There is good correlation between old and new for the other wells on the pad, CLU11 is an outlier. Even the last 2006 as built survey was oƯ in the 4 north plane. In this case it seems best to go with the recent 2025 survey. It is the best data we have. I have revised the directional plan for the change in surface location. Regards, sean From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Monday, February 17, 2025 12:53 PM To: Cody Dinger <cdinger@hilcorp.com> Cc: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] CLU 11RD (PTD 225-013) - Question Hi Cody, While reviewing this PTD form, I noƟced that the coordinates shown on the 401 Form and Direc Ɵonal survey diīer by a few feet from those shown in the NAD 27 ASP Z4 secƟon of the surveyor’s as-built plat. To ensure accuracy of all databases, could Hilcorp please conĮrm which lat/long and ASP coordinates are correct? Thanks and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain conƱdential and/or privileged information. The CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 5 unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without Ʊrst saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Cody Dinger <cdinger@hilcorp.com> Sent: Tuesday, February 11, 2025 3:29 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: CLU 11RD 10-401 Hello, Attached is the application for permit to drill CLU 11RD and associated directional plan. Thank you! Cody Dinger Hilcorp Alaska, LLC Drilling Tech 907-777-8389 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. 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: 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. WELL PERMIT CHECKLIST Company Hilcorp Alaska, LLC Well Name:CANNERY LOOP UNIT 11RD Initial Class/Type DEV / PEND GeoArea 820 Unit 10320 On/Off Shore On Program DEVField & Pool Well bore seg Annular DisposalPTD#:2250130 NA1 Permit fee attached Yes FEE-Privat, ADL0365454, ADL0359153, and ADL03246022 Lease number appropriate Yes3 Unique well name and number Yes KENAI C.L.U., BELUGA GAS - 449575 - governed by CO 231A4 Well located in a defined pool Yes5 Well located proper distance from drilling unit boundary NA6 Well located proper distance from other wells Yes7 Sufficient acreage available in drilling unit Yes8 If deviated, is wellbore plat included Yes9 Operator only affected party Yes10 Operator has appropriate bond in force Yes11 Permit can be issued without conservation order Yes12 Permit can be issued without administrative approval Yes13 Can permit be approved before 15-day wait NA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For serv 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) NA Sidetrack18 Conductor string provided Yes19 Surface casing protects all known USDWs NA20 CMT vol adequate to circulate on conductor & surf csg Yes 7" TOC @ 3300' md, 1000' inside previous casing string.21 CMT vol adequate to tie-in long string to surf csg Yes22 CMT will cover all known productive horizons Yes23 Casing designs adequate for C, T, B & permafrost Yes24 Adequate tankage or reserve pit Yes25 If a re-drill, has a 10-403 for abandonment been approved Yes26 Adequate wellbore separation proposed NA27 If diverter required, does it meet regulations Yes28 Drilling fluid program schematic & equip list adequate Yes29 BOPEs, do they meet regulation Yes MPSP = 1413 psi, BOP rated to 5000 psi (BOP test to 2500 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 shutdown No33 Is presence of H2S gas probable NA34 Mechanical condition of wells within AOR verified (For service well only) Yes H2S not anticipated35 Permit can be issued w/o hydrogen sulfide measures Yes Most reservoirs are underpressured to severely underpressured (1.2 ppg EMW gradient)36 Data presented on potential overpressure zones NA37 Seismic analysis of shallow gas zones NA38 Seabed condition survey (if off-shore) NA39 Contact name/phone for weekly progress reports [exploratory only] Appr ADD Date 3/12/2025 Appr BJM Date 3/10/2025 Appr ADD Date 3/12/2025 Administration Engineering Geology Geologic Commissioner:Date:Engineering Commissioner:Date Public Commissioner Date *&:JLC 3/13/2025