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Home My WebLink About225-095Hilenrp A 14; kw, LIB Date: 02/13/2026 David Douglas Hilcorp Alaska, LLC a R 5 - 06 5 Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400 Anchorage, AK 99503 I �� Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com To: Alaska Oil & Gas Conservation Commission Petroleum Geology Assistant 333 W 7th Ave Ste 100 Anchorage, AK 99501 RECEIVED FEB 13 2026 DATA TRANSMITTAL AOGCC Well: SU 32-16 PTD: 225-095 API: 50-133-20738-00-00 Washed and Dried Well Samples (11/08/2026) 30' Frequency B Set (4 Boxes): WELL BOX SAMPLE INTERVAL (FEET / MD) SU 32-16 BOX 1 OF 4 2790' - 4140' MD SU 32-16 BOX 2 OF 4 4140' - 5550' MD SU 32-16 BOX 3 OF 4 5550' - 7110' MD SU 32-16 BOX 4 OF 4 1 7110' - 8585' MD Please include current contact information if different from above. Please acknowledge rece�by signing and returning one copy of this transmittal. Received 8:! Date: 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 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. T41339SU 32-16 50133207380000 225095 1/17/2026 YELLOWJACKET GPT-PLUG-PERF SU 32-16 50133207380000 225095 11/22/2025 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 09:11:00 -09'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Ryan Lemay Cc:Chad Helgeson; Scott Warner; Juanita Lovett; Donna Ambruz Subject:RE: SU 32-16 / CBL / New Well Completion / PTD 225-095 Date:Wednesday, December 3, 2025 4:27:00 PM Ryan, Hilcorp has approval to proceed with perfs per the approved sundry. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Lemay <ryan.lemay@hilcorp.com> Sent: Wednesday, December 3, 2025 9:03 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Chad Helgeson <chelgeson@hilcorp.com>; Scott Warner <Scott.Warner@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: SU 32-16 / CBL / New Well Completion / PTD 225-095 Good morning Bryan, Attached is the CBL on the 3.5” completion executed on new Drill SU 32-16. Please let me know if you have any questions or need any additional information in reviewing and approving the completion sundry submitted on 11/21/25. We are expected to wrap up drilling on SU 43-10 sometime this weekend so should be ready for coil blowdown and completion operations on SU 32-16 by early next week. Thanks, Ryan LeMay Operations Engineer Swanson River / Beaver Creek Cell: (661) 487-0871 E-mail: Ryan.lemay@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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: 12/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL Well: SU 32-16 PTD: 225-095 API: 50-133-20738-00-00 FINAL MUDLOGS - EOW DRILLING REPORTS (11/01/2025 to 11/08/2025) 1. FINAL EOW REPORT 2. DAILY REPORTS 3. DIGITAL DATA (LAS) 4. LITHOLOGY DESCRIPTIONS 5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS) Formation Log LWD Combo Log Gas Ratio Log Drilling Dynamics Log SFTP Transfer - Main Folder Contents: Please include current contact information if different from above. 225-095 T41173 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.12.03 08:11:41 -09'00' David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 12/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Well: SU 32-16 PTD: 225-095 API: 50-133-20738-00-00 FINAL LWD FORMATION EVALUATION LOGS (10/29/2025 to 11/08/2025) DGR, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) Pressure While Drilling Final Definitive Directional Survey Main Folder Contents: Please include current contact information if different from above. 225-095 T41172 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.12.02 15:30:43 -09'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion 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): 8,585' N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Chad Helgeson, Operations Engineer Contact Email:chelgeson@hilcorp.com Contact Phone: 907-777-8405 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL394294|Pvt Fee 225-095 50-133-20738-00-00 Hilcorp Alaska, LLC Proposed Pools: 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 9.2# / L-80 TVD Burst 2,592' 10,160psi 2,366' 80' 2,782' MD 9-7/8" See Attached Schematic 2,980psi 6,890psi 80'80' 2,782' December 8, 2025 Tieback 3-1/2" 8,583' Perforation Depth MD (ft): Sterling Unit (SU) 32-16CO 824 Same 7,049'6-3/4" ~2242psi Sterling Sterling Undefined Gas Size See Attached Schematic 5,984' N/A Length Hydraulic DHL Pkr, Scout Pkr; NA 2,581' MD / 2,237' TVD, 2,599' MD / 2,249' TVD; N/A, N/A 7,051' 8,521' 6,988' 16" m n P s 66 t n 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 Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.11.20 16:23:28 - 09'00' Noel Nocas (4361) 325-718 By Grace Christianson at 8:46 am, Nov 21, 2025 TS 11/24/25BJM 12/2/25 DSR-11/21/25 10-407 Production from the Sterling and Beluga formations cannot be commingled downhole without an order from the AOGCC authorizing it. Submit CBL and obtain AOGCC approval before perforating. JLC 12/3/2025 12/03/25 Well Prognosis Well Name: SU 32-16 API Number: 50-133-20738-00-00 Current Status: New Drill Well Permit to Drill Number: 225-095 Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) First Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8863 (C) Maximum Expected BHP: ~2902 psi @ 6596 TVD (Based on 0.44 psi/ft gradient) Max. Potential Surface Pressure: ~2242 psi (0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.771 psi/ft using 14.84 ppg EMW FIT @ 7-5/8 SC shoe - 2366 ft TVD Shallowest Potential Perf TVD: MPSP/(0.771-0.1) = 2242 psi / 0.671 =3,341 TVD Well Status: New Drill Well Initial Completion Brief Well Summary Sterling Unit 32-16 is an S-shaped directional grassroots development well drilled from Sterling Pad and completed in November 2025 targeting the Sterling and Beluga Sands. The objective of this sundry is to perforate and flow the new drill well. Wellbore Conditions: - Max Inclination 51° at 2677 MD (well builds & holds 47-50 deg from ~2000 to ~5380) - Max DLS °/100 7° at 1,930 MD - T & IA PT to 3000 psi (30 min) on 11/10/25 - Min ID- 2.900 3-1/2 packer ID - Liner is full of ~9.7 ppg 6% KCl mud - Tubing and IA are displaced to 8.4 ppg CIW Work to be completed on PTD# 225-095 Step 20.0: Eline Run CBL o Send results to AOGCC to review prior to perforating CT Mud displacement & CT N2 blowdown Procedure: 1. Review all approved COAs 2. MIRU E-Line and pressure control equipment 3. PT lubricator to 250 psi low / 2,500 psi high 4. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 5. 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 sands may be added/removed depending on results of these perfs, between the proposed top and bottom perfs Sands Top MD Btm MD Top TVD Btm TVD Amt ST B4 ±6,808' ±6,811' ±5,300' ±5,303' ±3' ST C1 ±6,958' ±6,982' ±5,448' ±5,472' ±24' ST C1 ±7,054' ±7,069' ±5,543' ±5,557' ±15' UB4 ±7,185' ±7,205' ±5,671' ±5,691' ±20' Well Prognosis UB4 ±7,231' ±7,241' ±5,717' ±5,727' ±10' UB4 ±7,252' ±7,257' ±5,737' ±5,742' ±5' UB5 ±7,301' ±7,309' ±5,786' ±5,794' ±8' UB5 ±7,323' ±7,331' ±5,807' ±5,815' ±8' UB7 ±7,508' ±7,521' ±5,990' ±6,002' ±13' UB7 ±7,547' ±7,561' ±6,028' ±6,042' ±14' MB1 ±7,664' ±7,675' ±6,143' ±6,154' ±11' MB1 ±7,680' ±7,688' ±6,159' ±6,167' ±8' MB1 ±7,701' ±7,723' ±6,180' ±6,201' ±22' MB1 ±7,742' ±7,757' ±6,220' ±6,235' ±15' MB1 ±7,795' ±7,804' ±6,272' ±6,281' ±9' MB3 ±7,935' ±7,947' ±6,410' ±6,422' ±13' MB4 ±8,111 ±8,123 ±6,584 ±6,596 ±12' 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. Set 25ft of cement if setting plug over hydrocarbons or at geologic formation change, i.e. Beluga to Sterling Sand 6. RDMO 7. Turn well over to production & flow test well 8. 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 Updated by DMA 11-13-25 CURRENT SCHEMATIC Sterling SU 32-16 PTD: 225-095 API: 50-133-20738-00-00 PBTD = 8,521 MD / 6,988 TVD TD = 8,585 MD / 7,051 TVD RKB to GL = 18.95 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 80' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875Surf 2,782 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.9922,5998,583 3-1/2Production Tieback 9.3 L-80 EUE 2.992Surf 2,592 3/4 16 7-5/8 9-7/8 hole 3-1/2 JEWELRY DETAIL No. Depth Item 1 19Cactus CTF-ONE-CTL 11 x 4-1/2 Hanger w/ 4 Type H BPV profile 2 2,581Retrievable Hydraulic DHL Packer (58K Release) 2.992 ID 3 2,599YJ Scout Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 4 2,622Bullet Seal assembly 2.31 off no-go at 2,621 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 175 bbl of 12 ppg lead cement followed by 37 bbls 15.8 tail cement. Bumped plug @ 120 bbls. 60 bbls of returned spacer & 90 bbls of lead cement to surface, 0 bbls of losses during job. 3-1/2 248 bbl (590 sx) 12 ppg lead cement @ 4 BPM followed by 24 bbl (129 sx) 15.3 tail cement @ 3 BPM, bumped plug @ 84.3 bbls. 30 bbls of returned spacer & 78 bbls of lead cement to surface, 0 bbls of losses. TOC @ xxxx based on CBL on 12 /x/25 6-3/4 hole Notes: 10 Short jt w/ RA tags 8010, 7561, 6989 10 Short joints 6479, 5373 Deviation 51 deg @ 2677, holds 47-50 deg from 2000-5380 Max dogleg 7deg @ 1930 1 2 Updated by DMA 11-20-25 PROPOSED Sterling SU 32-16 PTD: 225-095 API: 50-133-20738-00-00 PBTD = 8,521 MD / 6,988 TVD TD = 8,585 MD / 7,051 TVD RKB to GL = 18.95 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 80' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875Surf 2,782 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.9922,5998,583 3-1/2Production Tieback 9.3 L-80 EUE 2.992Surf 2,592 3/4 16 7-5/8 9-7/8 hole 3-1/2 JEWELRY DETAIL No. Depth Item 1 19Cactus CTF-ONE-CTL 11 x 4-1/2 Hanger w/ 4 Type H BPV profile 2 2,581Retrievable Hydraulic DHL Packer (58K Release) 2.992 ID 3 2,599YJ Scout Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 4 2,622Bullet Seal assembly 2.31 off no-go at 2,621 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 175 bbl of 12 ppg lead cement followed by 37 bbls 15.8 tail cement. Bumped plug @ 120 bbls. 60 bbls of returned spacer & 90 bbls of lead cement to surface, 0 bbls of losses during job. 3-1/2 248 bbl (590 sx) 12 ppg lead cement @ 4 BPM followed by 24 bbl (129 sx) 15.3 tail cement @ 3 BPM, bumped plug @ 84.3 bbls. 30 bbls of returned spacer & 78 bbls of lead cement to surface, 0 bbls of losses. TOC @ xxxx based on CBL on 12 /x/25 6-3/4 hole Notes: 10 Short jt w/ RA tags 8010, 7561, 6989 10 Short joints 6479, 5373 Deviation 51 deg @ 2677, holds 47-50 deg from 2000-5380 Max dogleg 7deg @ 1930 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Undefined Pool Top Beluga Sand @ 7,137 MD & 5,652 TVD ST B4 ±6,808'±6,811'±5,300'±5,303'±3'Proposed TBD ST C1 ±6,958'±6,982'±5,448'±5,472'±24'Proposed TBD ST C1 ±7,054'±7,069'±5,543'±5,557'±15'Proposed TBD UB4 ±7,185'±7,205'±5,671'±5,691'±20'Proposed TBD UB4 ±7,231'±7,241'±5,717'±5,727'±10'Proposed TBD UB4 ±7,252'±7,257'±5,737'±5,742'±5'Proposed TBD UB5 ±7,301' ±7,309' ±5,786' ±5,794' ±8' Proposed TBD UB5 ±7,323' ±7,331' ±5,807' ±5,815' ±8' Proposed TBD UB7 ±7,508' ±7,521' ±5,990' ±6,002' ±13' Proposed TBD UB7 ±7,547' ±7,561' ±6,028' ±6,042' ±14' Proposed TBD MB1 ±7,664' ±7,675' ±6,143' ±6,154' ±11' Proposed TBD MB1 ±7,680' ±7,688' ±6,159' ±6,167' ±8' Proposed TBD MB1 ±7,701' ±7,723' ±6,180' ±6,201' ±22' Proposed TBD MB1 ±7,742' ±7,757' ±6,220' ±6,235' ±15' Proposed TBD MB1 ±7,795' ±7,804' ±6,272' ±6,281' ±9' Proposed TBD MB3 ±7,935' ±7,947' ±6,410' ±6,422' ±12' Proposed TBD MB3 ±8,111±8,123' ±6,584' ±6,596' ±12' Proposed TBD 1 2 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________STERLING UNIT 32-16 JBR 12/11/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 Tested with 3-1/2" & 4-1/2" Test joints. Hydraulic choke F/P bad seal. Annular tested to 2500 psi. Test Results TEST DATA Rig Rep:Kenneth PorterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley Rig Owner/Rig No.:Hilcorp 169 PTD#:2250950 DATE:11/2/2025 Type Operation:DRILL Annular: 250/2500Type Test:INIT Valves: 250/5000 Rams: 250/5000 Test Pressures:Inspection No:bopJDH251103150824 Inspector Josh Hunt Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6.5 MASP: 2760 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 FPHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 2 7/8'' x 5''P #2 Rams 1 Blinds P #3 Rams 1 2 7/8'' x 5''P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8''P HCR Valves 2 3 1/8'' & 2 1/1 P Kill Line Valves 1 2 1/16''P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1700 200 PSI Attained P25 Full Pressure Attained P94 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P4@2450 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P15 #1 Rams P5 #2 Rams P4 #3 Rams P4 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1         Test chart attached BOPE Test - Hilcorp 169 Sterling Unit 32-16 (PTD 2250950) AOGCC Insp # bopJDH251103150824 11/2/2025 P.I. Supv jbr Comm: Rig Coil Tubing Unit?No Rig Contractor Rig Representative Operator Operator Representative Well Permit to Drill #225-095 Sundry Approval # Operation Inspection Location Working Pressure, W/H Flange P Pit Fluid Measurement P Working Pressure P P Flow Rate Sensor P Operating Pressure P P Mud Gas Separator P Fluid Level/Condition P P Degasser P Pressure Gauges P P Separator Bypass P Sufficient Valves P P Gas Detectors P Regulator Bypass P P Alarms Separate/Distinct P Actuators (4-way valves)P P Choke/Kill Line Connections P Blind Ram Handle Cover P P Reserve Pits P Control Panel, Driller P P Trip Tank P Control Panel, Remote P P Firewall P P 2 or More Pumps P P Kelly or TD Valves P Independent Power Supply P P Floor Safety Valves P N2 Backup P P Driller's Console P Condition of Equipment P P Flow Monitor P Flow Rate Indicator P Pit Level Indicators P Valves P PPE P Gauges P Remote Hydraulic Choke P Well Control Trained P Gas Detection Monitor P FOV Upstream of Chokes P Housekeeping P Hydraulic Control Panel P Targeted Turns P Well Control Plan P Kill Sheet Current P Bypass Line P FAILURES:0 CORRECT BY: COMMENTS CHOKE MANIFOLD Sterling Pad MUD SYSTEM Sterling Unit 32-16 Drilling CLOSING UNIT ALASKA OIL AND GAS CONSERVATION COMMISSION RIG INSPECTION REPORT HCR Valve(s) Manual Valves Annular Preventer Working Pressure, BOP Stack Stack Anchored Choke Line Kill Line Targeted Turns Pipe Rams Blind Rams Kenneth Porterfield Josh Riley Locking Devices, Rams BOP STACK Josh Hunt 11/2/2025INSPECT DATE AOGCC INSPECTOR Hilcorp 169 Nabors Hilcorp Alaska LLC MISCELLANEOUS Flange/Hub Connections Drilling Spool Outlets Flow Nipple Control Lines RIG FLOOR 2025-1102_Rig_Hilcorp169_Sterling_32-16_jh rev. 4-19-2023    STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION DIVERTER Test Report for: Reviewed By: P.I. Suprv Comm ________STERLING UNIT 32-16 JBR 12/11/2025 MISC. INSPECTIONS: GAS DETECTORS: DIVERTER SYSTEM:MUD SYSTEM: P/F P/F P/F Alarm Visual Alarm Visual Time/Pressure Size Number of Failures:0 Remarks:Everything looked gtreat. Tested with 4-1/2" test joint. TEST DATA Rig Rep:Kenneth PorterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley Contractor/Rig No.:Hilcorp 169 PTD#:2250950 DATE:10/28/2025 Well Class:DEV Inspection No:divJDH251029131154 Inspector Josh Hunt Inspector Insp Source Related Insp No: Test Time:1 ACCUMULATOR SYSTEM: Location Gen.:P Housekeeping:P Warning Sign P 24 hr Notice:P Well Sign:P Drlg. Rig.P Misc:NA Methane:P P Hydrogen Sulfide:P P Gas Detectors Misc:NA NA Designed to Avoid Freeze-up?P Remote Operated Diverter?P No Threaded Connections?P Vent line Below Diverter?P Diverter Size:21.25 P Hole Size:9.875 P Vent Line(s) Size:16 P Vent Line(s) Length:111 P Closest Ignition Source:86 P Outlet from Rig Substructure:101 P Vent Line(s) Anchored:0 P Turns Targeted / Long Radius:0 P Divert Valve(s) Full Opening:0 P Valve(s) Auto & Simultaneous: Annular Closed Time:22 P Knife Valve Open Time:2 P Diverter Misc:0 NA Systems Pressure:P3050 Pressure After Closure:P1900 200 psi Recharge Time:P15 Full Recharge Time:P70 Nitrogen Bottles (Number of):P4 Avg. Pressure:P2425 Accumulator Misc:NA0 P PTrip Tank: P PMud Pits: P PFlow Monitor: NA NAMud System Misc:           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: Sterling Unit Field, Sterling Undefined Gas Oil, SU 32-16 Hilcorp Alaska, LLC Permit to Drill Number: 225-095 Surface Location: 2312' FSL, 449' FEL, Sec 9, T5N, R10W, SM, AK Bottomhole Location: 1462' FNL, 2022' FEL, Sec 16, T5N, R10W, SM, AK Dear Mr. McLaughlin: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 6th day of October 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.10.06 14:59:26 -08'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 8,585' TVD: 7,042' 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): 241.7' 15. Distance to Nearest Well Open Surface: x-314622 y-2390035 Zone-4 223.7' to Same Pool: N/A 16. Deviated wells: Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 50 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 80' Surface Surface 80' 80' 9-7/8" 7-5/8" 29.7# L-80 GBCD 2,765' Surface Surface 2,765' 2,348' 6-3/4" 3-1/2" 9.2# L-80 Hyd 563 6,020' 2,565' 2,219' 8,585' 7,042' Tieback 3-1/2" 9.2# L-80 EUE 2,404' Surface Surface 2,565' 2,219' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng SU 32-16 Sterling Unit (Federal, Terminated) Sterling Undefined Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 1391 ft3 / T - 131 ft3 1432 554' FNL, 1672' FEL, Sec 16, T5N, R10W, SM, AK 1462' FNL, 2022' FEL, Sec 16, T5N, R10W, SM, AK LOCI 25-004 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 2312' FSL, 449' FEL, Sec 9, T5N, R10W, SM, AK Private Fee / ADL 394294 18. Casing Program:Top - Setting Depth - BottomSpecifications 3465 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) Driven L - 916 ft3 / T - 128 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): LengthCasing Size Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate Drilling Manager Sean Mclaughlin 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): 10/16/2025 2175' to nearest property owner Nathan Sperry nathan.sperry@hilcorp.com 907-777-8450 Tieback Assy. 789 Cement Volume MD s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 2:32 pm, Aug 29, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.08.29 12:31:25 - 08'00' Sean McLaughlin (4311) 225-095 2760 psi -bjm TS 9/29/25 BJM 10/6/25 DSR-9/10/25 50-133-20738-00-00 TS 9/29/25 Initial BOP test to 5000 psi. Subsequent BOP tests to 3000 psi. All annular tests to 2500 psi. CT BOP test to 3000 psi Submit FIT/LOT data within 48 hrs of obtaining results. 220' *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.10.06 14:59:45 -08'00' 10/06/25 10/06/25 RBDMS JSB 100825 SU 32-16 Drilling Program Sterling Unit August 25, 2025 SU 32-16 Drilling Procedure Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Planned Wellbore Schematic........................................................................................................6 7.0 Drilling / Completion Summary...................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications....................................................................8 9.0 R/U and Preparatory Work........................................................................................................10 10.0 N/U 21-1/4” 2M Diverter.............................................................................................................11 11.0 Drill 9-7/8” Hole Section..............................................................................................................13 12.0 Run 7-5/8” Surface Casing..........................................................................................................15 13.0 Cement 7-5/8” Surface Casing....................................................................................................18 14.0 BOP N/U and Test........................................................................................................................21 15.0 Drill 6-3/4” Hole Section..............................................................................................................22 16.0 Run 3-1/2” Production Liner......................................................................................................25 17.0 Cement 3-1/2” Production Liner................................................................................................28 18.0 3-1/2” Liner Tieback Polish Run................................................................................................32 19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................33 20.0 CBL and Nitrogen Operation (Post Rig Work)........................................................................34 21.0 Diverter Schematic ......................................................................................................................37 22.0 BOP Schematic.............................................................................................................................38 23.0 Wellhead Schematic.....................................................................................................................39 24.0 Anticipated Drilling Hazards......................................................................................................40 25.0 Hilcorp Rig 169 Layout...............................................................................................................42 26.0 FIT/LOT Procedure ....................................................................................................................43 27.0 Rig 169 Choke Manifold Schematic...........................................................................................44 28.0 Casing Design Information.........................................................................................................45 29.0 6-3/4” Hole Section MASP..........................................................................................................46 30.0 Spider Plot w/ 660’.......................................................................................................................47 31.0 Surface Plat As-Built...................................................................................................................48 Page 2 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 1.0 Well Summary Well SU 32-16 Pad & Old Well Designation Sterling Pad – Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Middle Beluga Planned Well TD, MD / TVD 8585 MD / 7042’ TVD PBTD, MD / TVD 8505’ MD AFE Drilling Days 20 Maximum Anticipated Pressure (Surface)1432 psi Maximum Anticipated Pressure (Downhole/Reservoir)3465 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 241.70’ Ground Elevation 223.70’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Superseded 2760 psi based on max reservoir pressure minus 0.1 psi/ft gas grad. -bjm Page 3 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 2.0 Management of Change Information Superseded Page 2 Rev 1 October 1, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 1.0 Well Summary Well SU 32-16 Pad & Old Well Designation Sterling Pad – Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s) Middle Beluga Planned Well TD, MD / TVD 8585 MD / 7042’ TVD PBTD, MD / TVD 8505’ MD AFE Drilling Days 20 Maximum Anticipated Pressure (Surface) 2760 psi Maximum Anticipated Pressure (Downhole/Reservoir) 3465 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 241.70’ Ground Elevation 223.70’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Rev 1 October 1, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 2.0 Management of Change Information Page 4 Rev 0.0 August 25, 2025 SU 32-16 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) Cond 16”15.01”14.822”-84 X-56 Weld 2980 1410 - Surface 9-7/8”7-5/8”6.875”6.750”8.500”29.7 L-80 GBCD 6890 4790 683 Prod 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 ** Liner must overlap surface casing by at least 100’. 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 Rev 0.0 August 25, 2025 SU 32-16 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 nathan.sperry@hilcorp.com,andcdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com,and cdinger@hilcorp.com Page 6 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 6.0 Planned Wellbore Schematic Page 7 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 7.0 Drilling / Completion Summary SU 32-16 is an S-shaped directional grassroots development well to be drilled from Sterling Pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the middle Beluga sands. The base plan is an S-shaped directional wellbore with a kickoff point at ~500’ MD. Maximum hole angle will be ~50 deg. and TD of the well will be 8565’ TMD/ 7042’ TVD, ending with 10 deg inclination. Drilling operations are expected to commence approximately October 16 th, 2025. The Hilcorp Rig # 169 will be used to deliver the well. Surface casing will be run to 2765’ MD / 2348’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a cement evaluation log (CBL/VDL or temperature log for example)maybe runto determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 169 to wellsite 2. N/U diverter and test. 3. Drill 9-7/8” hole to 2765’. Run and cmt 7-5/8” surface casing. 4. Test casing to 3500 psi. Perform 14.0# FIT 5. ND diverter, N/U & test 11” x 5M BOP to 3000 psi 6. Drill 6-3/4” hole section to 8585’ MD. 7. Run and cmt 3-1/2” production liner. 8. Displace well to inhibited completion fluid. 9. POOH and LDDP. 10. RIH and land 3-1/2” tieback string in liner top. 11. Test IA to 3000; Test tubing to 3000 psi 12. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: Surface hole: GR/RES Production Hole: Triple combo and mudlogging (30’ sample frequency). For the mud logged interval, a set of cuttings must be submitted to the AOGCC as per 20 AAC 25.071. -TS 9/26/25 mudlogging (30’ sample frequency). Page 8 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 8.0 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 SU 32-16. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. 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. Initial test to 5000 psi Page 9 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only 6-3/4” 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 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: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (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) 5000 psi Page 10 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install landing ring on conductor. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.8 Mix mud for 9-7/8” hole section. 9.9 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. Page 11 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 10.0 N/U 21-1/4” 2M Diverter 10.1 N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x NOTE:Ensure closing time on diverter annular is in line with API RP 64: 2..1.1.Annular element ID 20” or smaller: Less than 30 seconds 2..1.2.Annular element ID greater than 20”: Less than 45 seconds 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking. x A prohibition on ignition sources or running equipment. x A prohibition on staged equipment or materials. x Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. Page 12 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 10.5 Estimated diverter line orientation (orientation is subject to change on location): Page 13 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 11.0 Drill 9-7/8” Hole Section 11.1 P/U 9-7/8” directional drilling assy: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 4-1/2” Workstring & HWDP will come from Hilcorp. 11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 9-7/8” hole section to 2,765’ MD / 2,348’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1300’ unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale x Take MWD surveys every stand drilled (60’ intervals). 11.5 9-7/8” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 14 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH Surface 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.6 At TD, pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.7 TOH with the drilling assy, handle BHA as appropriate. Page 15 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker 7-5/8” casing running equipment. x Ensure 7-5/8” Casing x CDS 40 XO 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 on the location prior to running. 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. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 7-5/8” surface casing 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 (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 16 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Page 17 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 18 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 13.0 Cement 7-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. 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. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls spacer. Test surface cmt lines. 13.5 Pump remaining spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 75% lead and tail open hole excess. Job will consist of lead & tail, TOC brought to surface. Superseded Page 19 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx Estimated Total Cement Volume: 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.6 bbls. Superseded Page 18 Rev 1 October 1, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 13.0 Cement 7-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. 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. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls spacer. Test surface cmt lines. 13.5 Pump remaining spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 75% lead and tail open hole excess. Job will consist of lead & tail, TOC brought to surface. Slurry Design: Lead Slurry Tail Slurry (500’) System Extended Conventional Density 12 lb/gal 15.8 lb/gal Yield 2.44 ft3/sk 1.16 ft3/sk Mixed Water 14.40 gal/sk 5.03 gal/sk Mixed Fluid 14.40 gal/sk 5.03 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A CalSeal Accelerator D-Air 5000 Anti Foam VersaSet Thixotropic Calcium Chloride Accelerator D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add. FDP-C1446-21 Slurry Conditioner BridgeMaker II Lost Circulation Page 19 Rev 1 October 1, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx Estimated Total Cement Volume: 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.6 bbls. Page 20 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. 13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.14 R/D cement equipment. Flush out wellhead with FW. 13.15 Back out and L/D landing joint. Flush out wellhead with FW. 13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.17 Lay down landing joint and pack-off running tool. Ensure to report the following on 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 cdinger@hilcorp.com and nathan.sperry@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 21 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 14.0 BOP N/U and Test 14.1 ND Diverter line and diverter 14.2 N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test Packoff to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: 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 2-7/8” x 5” variable 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. 14.4 Land out test plug (if not installed previously). x Test BOP to 250/3000 psi for 5/10 min. x Test VBR’s with 3-1/2” and 4-1/2” test joints x Test annular to 250/2500 psi for 10/10 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. 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 9.0 ppg 6% KCL PHPA mud system. 14.7 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. Initial BOP test to 5000 psi -bjm Page 22 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 15.0 Drill 6-3/4” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH and conduct shallow hole test of MWD to confirm all LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 6-3/4” hole section mud program summary: Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT Production 8.8 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0 Page 23 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx System Formulation: 6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0–9.9ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. x Triple Combo LWD tools required (DEN, POR, RES) 15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst.7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 14.0 ppg EMW. x The minimum to drill ahead is 13.6ppg. A 13.6ppg with 9.46 ppg reservoir pressure and 10.0 ppg MW will provide > 20 bbls KT. 15.14 Drill 6-3/4” hole section to TD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 400 - 500 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 1300’ unless hole conditions dictate otherwise. x Trip back to the 7-5/8” shoe about ½ way through the hole section 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. 15.15 At TD, pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 15.16 TOH with the drilling assy, standing back drill pipe. 15.17 LD BHA. Page 24 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 15.18 RIH to TD, pump sweep, CBU and condition mud for casing run. 15.19 POOH LDDP and BHA. 15.20 Ensure 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint. Page 25 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 16.0 Run 3-1/2” Production Liner 16.1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” HYD 563 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. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. 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 YJOC 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 16.4. 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 7-5/8” shoe. Leave the centralizers free floating. 16.5. Continue running 3-1/2” production liner Page 26 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx Page 27 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 16.6. Run in hole w/ 3-1/2” liner to the 7-5/8” casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. PU 3-1/2” X 7-5/8” YJOC liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 16.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.15. Stage pump rates up slowly to circulating rate.Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 28 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 17.0 Cement 3-1/2” Production Liner 17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s 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. 17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 17.3. Pump 5 bbls spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Superseded Page 28 Rev 1 October 1, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 17.0 Cement 3-1/2” Production Liner 17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s 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. 17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 17.3. Pump 5 bbls spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Slurry Design: Lead Slurry Tail Slurry (500’) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss HR-5 Retarder HR-5 Retarder D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add. FDP-C1446-21 Slurry Conditioner SA-1015 Suspension Agent BridgeMaker II Lost Circulation Page 29 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx Estimated Total Cement Volume: 17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 17.9. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Page 30 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 17.10. Bump the plug and pressure up to up as required by service company procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).Hold pressure for 3-5 minutes. 17.11. Slack off total liner weight plus 30k to confirm hanger is set. 17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls. 17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. 17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17.17. Pressure up drill pipe to 500 psi and pick up to remove the bushing from the liner. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 17.18. 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. 17.19. 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. 17.20. 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 Page 31 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 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 cdinger@hilcorp.com and sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 32 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 18.0 3-1/2” Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle. 18.3. POOH, and LDDP and polish mill. 18.4. If not completed, test 3-1/2” casing to 3000 psi and chart for 30 minutes Page 33 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 19.0 3-1/2” Tieback Run, ND/NU, RDMO 19.1 PU 3-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 EUE. Ensure any jewelry is picked up per tally. x Run SSSV to ~150’ MD x No CIM, or GLM required. 19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 19.3 Circulate inhibited completion fluid. 19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance of seals from no-go. 19.5 Install packoff and test hanger void. 19.6 Test 3-1/2” liner and tieback to 3000 psi and chart for 30 minutes. 19.7 Test 7-5/8” x 3-1/2” annulus to 3000 psi and chart for 30 minutes. 19.8 Install BPV in wellhead 19.9 N/D BOPE 19.10 N/U dry-hole tree and test 19.11 RDMO Hilcorp Rig #169 Superseded Not shown on diagram. -bjmx py Run SSSV to ~150’ MD x N Page 33 Rev 1 October 1, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 19.0 3-1/2” Tieback Run, ND/NU, RDMO 19.1 PU 3-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 EUE. Ensure any jewelry is picked up per tally. x No CIM, or GLM required. 19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 19.3 Circulate inhibited completion fluid. 19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance of seals from no-go. 19.5 Install packoff and test hanger void. 19.6 Test 3-1/2” liner and tieback to 3000 psi and chart for 30 minutes. 19.7 Test 7-5/8” x 3-1/2” annulus to 3000 psi and chart for 30 minutes. 19.8 Install BPV in wellhead 19.9 N/D BOPE 19.10 N/U dry-hole tree and test 19.11 RDMO Hilcorp Rig #169 Page 34 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 20.0 CBL and Nitrogen Operation (Post Rig Work) Pre-Sundry work: 1. Review all approved COAs 2. MIRU E-line and pressure control equipment 3. Log well with CBL tool in 2-1/2” liner (send results to AOGCC to review) 4. RDMO E-line Coiled Tubing Procedure 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3500psi high a. Provide AOGCC 48hr notice for BOP test 3. MU cleanout BHA 4. RIH to PBTD, cleanout well as necessary (based on CBL depth) and swap well over to 8.4 ppg water a. If well is left with 9.4 ppg mud or less, mud may be circulated out with Nitrogen, based on Operations Engineer direction without swapping to water. 5. Once well is clean with 8.4 ppg water a. Reverse circulate water 6. RDMO CT 7. Leave N2 pressure on well when coil is rigged down Submit Completion sundry for perforating well. Attachments to be included 1. Coil Tubing BOP Diagram 2. Standard Nitrogen Operations Page 35 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx Page 36 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx Page 37 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 21.0 Diverter Schematic Page 38 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 22.0 BOP Schematic Page 39 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 23.0 Wellhead Schematic Page 40 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 24.0 Anticipated Drilling Hazards 9-7/8” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 – 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help ensure good cement to surface after running the casing, condition the mud to a YP of 25 – 30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 41 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022, ensure all LCM inventory is fully stocked before drilling out surface casing. 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 temperatures are present in this hole section. Page 42 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 25.0 Hilcorp Rig 169 Layout Page 43 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 26.0 FIT/LOT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 44 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 27.0 Rig 169 Choke Manifold Schematic Page 45 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 28.0 Casing Design Information Page 46 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 29.0 6-3/4” Hole Section MASP Page 47 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 30.0 Spider Plot w/ 660’ Page 48 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 31.0 Surface Plat As-Built Page 49 Rev 0.0 August 25, 2025 SU 32-16 Drilling Procedure PTD xxx-xxx 6WDQGDUG3URSRVDO5HSRUW $XJXVW 3ODQ68ZSD +LOFRUS$ODVND//& 6WHUOLQJ8QLW 6WHUOLQJ8QLW3DG 3ODQ68 68 04759501425190023752850332538004275475052255700617566507125True Vertical Depth (950 usft/in)-475 0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175Vertical Section at 201.00° (950 usft/in)SU 32-16 T17-5/8" x 9-7/8"3-1/2" x 6-3/4"50010001500200025003000350040004500500055006000650070007500800085008585SU 32-16 wp02aStart Dir 3º/100' : 500' MD, 500'TVDEnd Dir : 2166.67' MD, 1963.04' TVDStart Dir 3º/100' : 5266.67' MD, 3955.68'TVDEnd Dir : 6600' MD, 5087.07' TVDTotal Depth : 8585' MD, 7041.92' TVDSterling A2Sterling B4Upper Beluga_UB 4Upper Beluga_UB 5Hilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: SU 32-16223.70+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.002390035.49314622.39 60° 32' 16.9593 N 151° 1' 46.0333 WSURVEY PROGRAMDate: 2025-08-21T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool18.00 2765.00 SU 32-16 wp02a (SU 32-16) 3_MWD+AX+Sag2765.00 8585.00 SU 32-16 wp02a (SU 32-16) 3_MWD+AX+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation3571.70 3330.00 4669.30 Sterling A25192.70 4951.00 6707.26 Sterling B45633.70 5392.00 7155.06 Upper Beluga_UB 45767.70 5526.00 7291.13 Upper Beluga_UB 5REFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: SU 32-16, True NorthVertical (TVD) Reference:Plan RKB @ 241.70usft (169)Measured Depth Reference:Plan RKB @ 241.70usft (169)Calculation Method:Minimum CurvatureProject:Sterling UnitSite:Sterling Unit PadWell:Plan: SU 32-16Wellbore:SU 32-16Design:SU 32-16 wp02aCASING DETAILSTVD TVDSS MD SizeName2347.64 2105.94 2765.00 7-5/8 7-5/8" x 9-7/8"7041.92 6800.22 8585.00 3-1/2 3-1/2" x 6-3/4"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation118.000.000.0018.000.000.000.000.000.002 500.00 0.00 0.00 500.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 500' MD, 500'TVD3 2166.67 50.00 201.00 1963.04 -636.91 -244.49 3.00 201.00 682.23 End Dir : 2166.67' MD, 1963.04' TVD4 5266.67 50.00 201.00 3955.68 -2853.92 -1095.52 0.00 0.00 3056.96 Start Dir 3º/100' : 5266.67' MD, 3955.68'TVD5 6600.00 10.00 201.00 5087.07 -3463.75 -1329.61 3.00 180.00 3710.17 End Dir : 6600' MD, 5087.07' TVD6 8585.00 10.00 201.00 7041.92 -3785.54 -1453.13 0.00 0.00 4054.87 Total Depth : 8585' MD, 7041.92' TVD -3800 -3600 -3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 -200 0 South(-)/North(+) (400 usft/in)-2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 -200 0 200 400 600 West(-)/East(+) (400 usft/in) SU 32-16 T1 7-5/8" x 9-7/8" 3-1/2" x 6-3/4" 500 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5500 6000 6500 7042 SU 32-16 wp02a End Dir : 6600' MD, 5087.07' TVD Total Depth : 8585' MD, 7041.92' TVD CASING DETAILS TVD TVDSS MD Size Name 2347.64 2105.94 2765.00 7-5/8 7-5/8" x 9-7/8" 7041.92 6800.22 8585.00 3-1/2 3-1/2" x 6-3/4" Project: Sterling Unit Site: Sterling Unit Pad Well: Plan: SU 32-16 Wellbore: SU 32-16 Plan: SU 32-16 wp02a WELL DETAILS: Plan: SU 32-16 223.70 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2390035.49 314622.39 60° 32' 16.9593 N 151° 1' 46.0333 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: SU 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eparation Factor450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100 8550Measured Depth (900 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: SU 32-16 NAD 1927 (NADCON CONUS)Alaska Zone 04223.70+N/-S +E/-W Northing Easting Latittude Longitude0.000.002390035.49314622.3960° 32' 16.9593 N151° 1' 46.0333 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: SU 32-16, True NorthVertical (TVD) Reference:Plan RKB @ 241.70usft (169)Measured Depth Reference:Plan RKB @ 241.70usft (169)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-08-21T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.00 2765.00 SU 32-16 wp02a (SU 32-16) 3_MWD+AX+Sag2765.00 8585.00 SU 32-16 wp02a (SU 32-16) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100 8550Measured Depth (900 usft/in)SU 32-09SU 43-09XSU 43-09GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.00 To 8585.00Project: Sterling UnitSite: Sterling Unit PadWell: Plan: SU 32-16Wellbore: SU 32-16Plan: SU 32-16 wp02aCASING DETAILSTVD TVDSS MD Size Name2347.64 2105.94 2765.00 7-5/8 7-5/8" x 9-7/8"7041.92 6800.22 8585.00 3-1/2 3-1/2" x 6-3/4" Gate Sterling Pad 61: 6HF 6HF 68%+/ 6WHUOLQJ3DG 686WHUOLQJ3DG $QFKRUDJH +RPHU 1LNLVNL 6HZDUG 6WHUOLQJ3DG /HJHQG 68BIW%XIIHU 68B%XIIHU 2WKHU6XUIDFH:HOO/RFDWLRQV 2WKHU%RWWRP+ROH/RFDWLRQV 2WKHU:HOO3DWKV Map Date: 10/2/2025 )HHW 'RFXPHQW3DWK2?$:6?*,6?'URSER[?-XOLHDQQD3RWWHU?3URMHFWB+DQGRII?3URMHFWB+DQGRIIDSU[NAD 1927 StatePlane Alaska 4 FIPS 5004 6WHUOLQJ3DG 68DQG68 IW5DGLXV u CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. You don't often get email from cdinger@hilcorp.com. Learn why this is important From:Starns, Ted C (OGC) To:"Cody Dinger"; Nathan Sperry; Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC) Cc:Luke Suchecki Subject:RE: [EXTERNAL] SU-32-16 (PTD 225-095) - Questions Date:Monday, September 29, 2025 1:57:00 PM Attachments:image001.pngimage002.png Thanks Cody, For our purposes, Box 14 is to identify wells which need a spacing exception, which you have. As such we’re more concerned with the productive interval. To me it looks like ~220’ to the nearest property change (ADL 394293) between TPH& BHL. I’ll just go ahead and update that value on the permit and send it on its way. Have a good day, Ted Ted Starns Petroleum Geologist AOGCC 907-793-1225 (office) From: Cody Dinger <cdinger@hilcorp.com> Sent: Monday, September 29, 2025 1:13 PM To: Nathan Sperry <Nathan.Sperry@hilcorp.com>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Luke Suchecki <Luke.Suchecki@hilcorp.com> Subject: RE: [EXTERNAL] SU-32-16 (PTD 225-095) - Questions Hi Ted, Typically, within a unit we provide a measurement to the nearest unit boundary. Since we are not within a unit, I measured to the nearest property ownership line from surface. This was an unusual circumstance, so I wasn’t certain what data should’ve been provided. From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Monday, September 29, 2025 12:13 PM To: Cody Dinger <cdinger@hilcorp.com> Subject: FW: [EXTERNAL] SU-32-16 (PTD 225-095) - Questions From: Starns, Ted C (OGC) <ted.starns@alaska.gov> Sent: Monday, September 29, 2025 11:18 AM To: Nathan Sperry <nathan.sperry@hilcorp.com>; Luke Suchecki <luke.suchecki@hilcorp.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: [EXTERNAL] SU-32-16 (PTD 225-095) - Questions Hello Nathan and Luke, I’m nearly complete with my review of the SU 32-16 PTD (#225-095), and I see that you have an approved spacing exception, CO 824. However, I’m curious on how you came up with the figure in Box 14 of the 10-401 form which states that the SU 32-16 well is 2175’ from the nearest property owner. Can you please help me understand how you came up with this distance? Thanks for your help, Ted Ted Starns Petroleum Geologist AOGCC 907-793-1225 (office) 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 notifyus 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. Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. For the mud logged interval, a set of cuttings must be submitted to the AOGCC as per 20 AAC 25.071. -TS 9/26/25 SU 32-16 225-095 STERLING STERLING UNDEF GAS WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:STERLING UNIT 32-16Initial Class/TypeDEV / PENDGeoArea820Unit51962On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250950Field & Pool:STERLING, STERLING UNDEF GAS - 768500NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberNo Sterling Undefined Gas4 Well located in a defined poolNo5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedNo9 Operator only affected partyYes10 Operator has appropriate bond in forceNo CO 82411 Permit can be issued without conservation orderNo CO 82412 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)No16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2760 psi, BOP rated to 5000 psi (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not expected35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.11 to 0.491 psi/ft (2.1 to 9.5 ppg EMW). Beluga underpressure expected.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprTCSDate9/29/2025ApprBJMDate9/30/2025ApprTCSDate9/29/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 10/6/2025