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Home My WebLink About225-059Nolan 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 BRU 223-34T 50283202060000 225059 12/31/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 09:10:43 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PBU D-26B 50029215300200 206098 12/20/2025 HALLIBURTON ISAT T41329 PBU D-26B 50029215300200 206098 12/19/2025 BAKER SPN T41329 PBU F-21A 50029219490100 225019 1/18/2026 HALLIBURTON RBT-COILFLAG T41330 PBU J-21A 50029217050100 225106 1/21/2026 HALLIBURTON RBT-COILFLAG T41331 PBU L-291 50029237790000 224002 12/26/2025 HALLIBURTON RBT T41332 PBU L-291 50029237790000 224002 12/9/2025 YELLOWJACKET RCBL T41332 PBU S-107A 50029220440200 225083 12/8/2025 HALLIBURTON RBT-COILFLAG T41333 PBU S-201A 50029229870100 219092 1/21/2026 HALLIBURTON WFL-TMD3D T41335 PBU S-24B 50029220440200 203163 12/22/2025 HALLIBURTON RBT T41334 PBU S-24B 50029230230100 203163 12/23/2025 HALLIBURTON WFL-TMD3D T41334 SRU 223-15 50133207410000 225123 1/29/2026 YELLOWJACKET GPT-PERF T41336 SRU 223-15 50133207410000 225123 1/20/2026 YELLOWJACKET SCBL T41336 SRU 233-10 50133207400000 225113 12/30/2026 AK E-LINE CBL T41337 SRU 233-10 50133207400000 225113 1/10/2026 YELLOWJACKET SCBL T41337 SRU 233-10 50133207400000 225113 1/6/2026 YELLOWJACKET SCBL T41337 SRU 34-28 50133101580000 163007 1/7/2026 YELLOWJACKET Gamma Ray T41338 SU 32-16 50133207380000 225095 1/17/2026 YELLOWJACKET GPT-PLUG-PERF T41339 SU 32-16 50133207380000 225095 11/22/2025 YELLOWJACKET SCBL T41339 SU 43-10 50133207390000 225107 12/10/2025 YELLOWJACKET SCBL T41340 TBU A-12RD 50883200320100 171029 1/2/2026 AK E-LINE StripGun T41341 TBU D-24A 50733202240100 174064 12/4/2025 AK E-LINE TubingPunch T41342 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 09:11:00 -09'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 6,895' 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 AKA029656 / AKA029657 225-059 50-283-20206-00-00 Hilcorp Alaska, LLC Proposed Pools: 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 9.2# / L-80 TVD Burst 3,206' 10,160psi 2,593' 120' 3,383' MD 7-58" See Attached Schematic 2,980psi 6,890psi 120'120' 3,391' December 1, 2025 Tieback 3-1/2" 6,893' Perforation Depth MD (ft): Beluga River Unit (BRU) 223-34TCO 802A Same 5,952'3-1/2" ~2,230psi Beluga River Sterling-Beluga Gas Size See Attached Schematic 3,695' N/A Length Baker LTP, SSSV 3,198' MD/2,457' TVD; 168' MD/TVD 5,953' 6,827' 5,886' 16" m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.11.13 17:31:52 - 09'00' Noel Nocas (4361) 325-699 By Grace Christianson at 8:37 am, Nov 14, 2025 10-404 BJM 11/20/25 SFD 11/17/2025 DSR-11/19/25JLC 11/20/2025 11/20/25 Well Prognosis Well Name: BRU 223-34T API Number: 50-283-20206-00-00 Current Status: Gas Producer Permit to Drill Number: 225-059 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: 2503 psi @ 5442 TVD (Based on 0.46 psi/ft gradient) Max. Potential Surface Pressure: 2230 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.721 psi/ft using 13.87 ppg EMW FIT at the 7-5/8 surface casing Shallowest Potential Perf TVD: MPSP/(0.721-0.05) = 2230 psi / 0.671 = 3323 TVD Top of SBGP (CO 802A): ~3712 MD/~2841 TVD Well Status: Online flowing ~3 mmscfd @ 309 psi. Brief Well Summary BRU 23-34T was drilled in the 2025 Beluga River drilling campaign targeting the Sterling and Beluga sands. The objective of this sundry is to add perforations to the well after closing out the original perf add sundry in September. All sands lie in the Sterling-Beluga Gas Pool (SBGP) per CO 802A and BRU PA. Wellbore Conditions: - Max Inclination 61° at 2,546 MD - T & IA PT to 3000 psi (30 min) 8/14/25 - Min ID- 2.813 in SCSSSV @ 168 (GX Profile) - Wide spot at liner hanger 4.5-5.75 ID from 3194-3231 - Cement top ~3958 (CBL run 8/20/25) - Top of Pool per CO and BLM PA: ~3712 MD/~2841 TVD Procedure: 1. Review all COAs for AOGCC & BLM 2. MIRU E-line and pressure control equipment 3. PT lubricator to 250 psi low / 2,500 psi high 4. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: Sands Top MD Btm MD Top TVD Btm TVD Amt Top of Pool per CO 802A: ~3,712 MD/2,841 TVD Top of PA (BLM) BEL D ±4,528' ±4,533' ±3,608' ±3,613' ±5' BEL D1 ±4,549' ±4,553' ±3,629' ±3,633' ±4' BEL D1 ±4,559' ±4,567' ±3,639' ±3,646' ±8' BEL D3 ±4,596' ±4,619' ±3,675' ±3,698' ±23' BEL D4 ±4,634' ±4,644' ±3,713' ±3,723' ±10' BEL D5 ±4,665' ±4,673' ±3,743' ±3,751' ±8' BEL D6 ±4,689' ±4,693' ±3,767' ±3,771' ±4' BEL D6 ±4,701' ±4,716' ±3,779' ±3,794' ±15' BEL D7 ±4,736' ±4,744' ±3,814' ±3,821' ±8' BEL E1 ±4,779' ±4,791' ±3,856' ±3,868' ±12' BEL E1 ±4,816' ±4,820' ±3,893' ±3,897' ±4' BEL E2 ±4,845' ±4,857' ±3,922' ±3,933' ±12' BEL E3 ±4,892' ±4,896' ±3,968' ±3,972' ±4' Well Prognosis 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 Attachments: 1. Current Schematic 2. Proposed Schematic Sands Top MD Btm MD Top TVD Btm TVD Amt BEL E3 ±4,918' ±4,930' ±3,994' ±4,006' ±12' BEL E4 ±4,947' ±4,950' ±4,023' ±4,026' ±3' BEL E5 ±4,976' ±4,979' ±4,052' ±4,055' ±3' BEL E5 ±5,006' ±5,011' ±4,081' ±4,086' ±5' BEL E5 ±5,036' ±5,048' ±4,111' ±4,123' ±12' BEL E6 ±5,088' ±5,108' ±4,163' ±4,183' ±20' Updated by CJD 09-5-25 SCHEMATIC Beluga River Unit BRU 223-34T PTD: 225-059 API: 50-283-20206-00-00 PBTD = 6,827 MD / TVD = 5,886 TD = 6,895 MD / TVD = 5,953 RKB to GL = 19.9 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875Surf 3,391 3-1/2" Prod Lnr 9.2 L-80 Wedge 563 2.992 3,1986,893 3-1/2Production Tieback 9.2 L-80 EUE 2.992Surf 3,206 3/4 16 7-5/8 9-7/8 hole 3-1/2 JEWELRY DETAIL No. Depth Item 1 20Cactus CTF-ONE-CTL 11 x 4-1/2 Hanger w/ 4 Type H BPV profile 2 168Giant 5K TRSSSV w/ 2.813 GX Profile, SN 10193A 3 3,1985-1/2 x 7-5/8 Baker ZXP Flexlock with HRD-E Liner top packer w/ 3.5x 5.5 XO at 3230. Wide spot (4.5-5.75) in tubing 37ft (3194-3231) 4 3,206 Bullet Seal assembly 2.07 off no-go at 3196 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 206 bbl (503 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 150 bbls (calculated 152 bbls), spacer & 93 bbls of lead cement to surface, 0 bbls of losses during job & reciprocated pipe. 3-1/2 142 bbls (334 sx) 12 ppg Lead followed with 24 bbls (109 sx) of 15.3 ppg tail, bumped plug. Lost returns 28bbls into displacement, circulated out 7bbls of spacer. 95 bbls of losses during cement job. TOC based on CBL @ 3958 dated 8/19/25) 6-3/4 hole 1 Notes: 10 Short jt w/ RA tags 6285, 5200, 4115 10 Short joints 5742, 4659, 3575 Deviation 61 deg @ 2546, Max dogleg 6.76deg @ 2233 Well went on losses between 4794-4800 in this hole section @4866 in open hole well was sidetracked off a loss zone cement plug. 2 RA 4115 RA 5200 RA 6285 PB1 @ 4,866 MD PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~3,712 MD/2,841 TVD Top of PA (BLM) BEL F1 5,176'5,182'4,250'4,256'6'9/1/25 Open BEL F4 5,207'5,212'4,281'4,286'5'9/1/25 Open BEL F5 5,314'5,320'4,387'4,393'6'9/1/25 Open BEL F7 5,493'5,499'4,565'4,571'6'8/31/25 Open BEL F7 5,506' 5,516' 4,577' 4,587' 10' 8/31/25 Open BEL F10 5,640' 5,660' 4,710' 4,730' 20' 8/30/25 Open BEL G3 5,781' 5,801' 4,850' 4,869' 20' 8/30/25 Open BEL G6 5,896' 5,910' 4,963' 4,978' 14' 8/30/25 Open BEL G9 6,010' 6,024' 5,075' 5,089' 14' 8/29/25 Open BEL G10 6,045' 6,059' 5,111' 5,124' 14' 8/29/25 Open BEL H1 6,161' 6,171' 5,225' 5,235' 10' 8/29/25 Open BEL H3 6,232' 6,242' 5,296' 5,305' 10' 8/29/25 Open Updated by CAH 11-12-25 PROPOSED Beluga River Unit BRU 223-34T PTD: 225-059 API: 50-283-20206-00-00 PBTD = 6,827 MD / TVD = 5,886 TD = 6,895 MD / TVD = 5,953 RKB to GL = 19.9 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875Surf 3,391 3-1/2" Prod Lnr 9.2 L-80 Wedge 563 2.992 3,1986,893 3-1/2Production Tieback 9.2 L-80 EUE 2.992Surf 3,206 3/4 16 7-5/8 9-7/8 hole 3-1/2 JEWELRY DETAIL No. Depth Item 1 20Cactus CTF-ONE-CTL 11 x 4-1/2 Hanger w/ 4 Type H BPV profile 2 168Giant 5K TRSSSV w/ 2.813 GX Profile, SN 10193A 3 3,1985-1/2 x 7-5/8 Baker ZXP Flexlock with HRD-E Liner top packer w/ 3.5x 5.5 XO at 3230. Wide spot (4.5-5.75) in tubing 37ft (3194-3231) 4 3,206 Bullet Seal assembly 2.07 off no-go at 3196 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 206 bbl (503 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 150 bbls (calculated 152 bbls), spacer & 93 bbls of lead cement to surface, 0 bbls of losses during job & reciprocated pipe. 3-1/2 142 bbls (334 sx) 12 ppg Lead followed with 24 bbls (109 sx) of 15.3 ppg tail, bumped plug. Lost returns 28bbls into displacement, circulated out 7bbls of spacer. 95 bbls of losses during cement job. TOC based on CBL @ 3958 dated 8/19/25) 6-3/4 hole 1 Notes: 10 Short jt w/ RA tags 6285, 5200, 4115 10 Short joints 5742, 4659, 3575 Deviation 61 deg @ 2546, Max dogleg 6.76deg @ 2233 Well went on losses between 4794-4800 in this hole section @4866 in open hole well was sidetracked off a loss zone cement plug. 2 RA 4115 RA 5200 RA 6285 PB1 @ 4,866 MD PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~3,712 MD/2,841 TVD Top of PA (BLM) BEL D ±4,528'±4,533'±3,608'±3,613'±5'TBD Proposed BEL D1 ±4,549'±4,553'±3,629'±3,633'±4'TBD Proposed BEL D1 ±4,559'±4,567'±3,639'±3,646'±8'TBD Proposed BEL D3 ±4,596'±4,619'±3,675'±3,698'±23'TBD Proposed BEL D4 ±4,634'±4,644'±3,713'±3,723'±10'TBD Proposed BEL D5 ±4,665'±4,673'±3,743'±3,751'±8'TBD Proposed BEL D6 ±4,689'±4,693'±3,767'±3,771'±4'TBD Proposed BEL D6 ±4,701' ±4,716' ±3,779' ±3,794' ±15' TBD Proposed BEL D7 ±4,736' ±4,744' ±3,814' ±3,821' ±8' TBD Proposed BEL E1 ±4,779' ±4,791' ±3,856' ±3,868' ±12' TBD Proposed BEL E1 ±4,816' ±4,820' ±3,893' ±3,897' ±4' TBD Proposed BEL E2 ±4,845' ±4,857' ±3,922' ±3,933' ±12' TBD Proposed BEL E3 ±4,892' ±4,896' ±3,968' ±3,972' ±4' TBD Proposed BEL E3 ±4,918' ±4,930' ±3,994' ±4,006' ±12' TBD Proposed BEL E4 ±4,947' ±4,950' ±4,023' ±4,026' ±3' TBD Proposed BEL E5 ±4,976' ±4,979' ±4,052' ±4,055' ±3' TBD Proposed BEL E5 ±5,006' ±5,011' ±4,081' ±4,086' ±5' TBD Proposed BEL E5 ±5,036' ±5,048' ±4,111' ±4,123' ±12' TBD Proposed BEL E6 ±5,088' ±5,108' ±4,163' ±4,183' ±20' TBD Proposed BEL F1 ±5,145' ±5,151' ±4,219' ±4,225' ±6' TBD Proposed BEL F1 ±5,167' ±5,173' ±4,241' ±4,247' ±6' TBD Proposed Perforation details continued on Page 2 Updated by DMA 11-12-25 SCHEMATIC Beluga River Unit BRU 223-34T PTD: 225-059 API: 50-283-20206-00-00 Perfs Continued from Page 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status BEL F1 5,176' 5,182' 4,250' 4,256' 6' 9/1/25 Open BEL F4 5,207' 5,212' 4,281' 4,286' 5' 9/1/25 Open BEL F5 5,314' 5,320' 4,387' 4,393' 6' 9/1/25 Open BEL F7 5,493' 5,499' 4,565' 4,571' 6' 8/31/25 Open BEL F7 5,506' 5,516' 4,577' 4,587' 10' 8/31/25 Open BEL F10 5,640' 5,660' 4,710' 4,730' 20' 8/30/25 Open BEL G3 5,781' 5,801' 4,850' 4,869' 20' 8/30/25 Open BEL G6 5,896' 5,910' 4,963' 4,978' 14' 8/30/25 Open BEL G9 6,010' 6,024' 5,075' 5,089' 14' 8/29/25 Open BEL G10 6,045' 6,059' 5,111' 5,124' 14' 8/29/25 Open BEL H1 6,161' 6,171' 5,225' 5,235' 10' 8/29/25 Open BEL H3 6,232' 6,242' 5,296' 5,305' 10' 8/29/25 Open 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: 09/19/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250919 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 212-35T 50283200970000 198161 8/10/2025 AK E-LINE PPROF T40899 BRU 223-34T 50283202060000 225059 8/17/2025 AK E-LINE CBL T40900 BRU 234-27 50283202070000 225065 9/12/2025 AK E-LINE CBL T40901 BRU 242-04 50283201640000 212041 6/9/2025 AK E-LINE Perf T40902 KBU 11-08Z 50133206290000 214044 9/8/2025 AK E-LINE Perf T40903 MPU H-03 50029220630000 190088 9/9/2025 AK E-LINE SetPacker T40904 MPU H-11 50029228020000 197163 2/9/2025 AK E-LINE Caliper T40905 MPU M-62 50029237440000 223006 8/31/2025 AK E-LINE LDL T40906 NCIU A-06 50883200260000 169050 8/25/2025 AK E-LINE TubingCut T40907 NCIU A-21A 50883201990100 225075 8/26/2025 AK E-LINE Perf T40908 ODSK-33 50703205620000 207183 9/10/2025 READ Caliper Survey T40909 ODSN-01a 50703206480100 216008 9/8/2025 READ Caliper Survey T40910 ODSN-06 50703207150000 215098 9/9/2025 READ Jewelry Log T40911 PBU C-34C 50029217850300 225068 8/25/2025 BAKER MRPM T40912 PBU Q-06A 50029203460100 198090 8/21/2025 BAKER SPN T40913 TBU M-25 50733203910000 187086 8/31/2025 AK E-LINE Drift T40914 Please include current contact information if different from above. BRU 223-34T 50283202060000 225059 8/17/2025 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.22 13:22:50 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/12/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250912 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 223-34T 50283202060000 225059 8/28/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/19/2025 AK E-LINE CIBP BRU 224-34T 50283202050000 225044 8/17/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/22/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/27/2025 AK E-LINE Perf BRU 241-23 50283201910000 223061 8/20/2025 AK E-LINE Plug/Perf GP 11-13RD 50733200260100 191133 8/29/2025 AK E-LINE Perf KALOTSA 6 50133206850000 219114 8/14/2025 AK E-LINE PPROF MGS ST 17595 06 50733100730000 166003 8/19/2025 AK E-LINE Drift MGS ST 17595 06 50733100730000 166003 8/26/2025 AK E-LINE Drift MGS ST 17595 11 50733200130000 167017 8/17/2025 AK E-LINE CBL MGS ST 17595 20 50733203770000 185135 8/21/2025 AK E-LINE CBL MPI 1-61 50029225200000 194142 8/19/2025 AK E-LINE Patch NCIU A-21A 50883201990100 225075 8/23/2025 AK E-LINE Perf END 1-23 50029225100000 194128 7/14/2025 HALLIBURTON MFC40 END 2-74 50029237850000 224024 7/12/2025 HALLIBURTON MFC40 END 3-07A 50029219110100 198147 7/13/2005 HALLIBURTON COILFLAG END 3-15 50029217510000 187094 7/15/2025 HALLIBURTON MFC24 NS-20 50029231180000 202188 9/2/2025 HALLIBURTON COILFLAG PBU 01-13A 50029202700100 225052 8/18/2025 HALLIBURTON RBT-COILFLAG PBU 07-24A 50029209450100 225045 8/3/2025 HALLIBURTON RBT-COILFLAG PBU C-34C 50029217850300 225068 8/25/2025 HALLIBURTON RBT SD-07 50133205940000 211050 8/14/2025 HALLIBURTON TMD3D ODSK-14 50703206100000 209155 9/8/2025 READ CaliperSurvey Please include current contact information if different from above. T40874 T40875 T40875 T40875 T40875 T40876 T40877 T40878 T40879 T40879 T40880 T40881 T40882 T40883 T40884 T40885 T40886 T40887 T40888 T40889 T40890 T40891 T40892 T40893 BRU 223-34T 50283202060000 225059 8/28/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.12 14:33:03 -08'00' David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/12/2025 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Well: BRU 223-34T + PB1 PTD: 225-059 API: 50-283-20206-00-00 (BRU 223-34T) API: 50-283-20206-70-00 (BRU 223-34TPB1) FINAL LWD FORMATION EVALUATION LOGS (07/27/2025 to 08/10/2025) EWR-P4, DGR and BaseStar Gamma Ray, ADR and StrataStar Resistivity, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey Main Folder Contents: Sub-Folder Contents: Please include current contact information if different from above. T40894 T40895 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.12 15:31:13 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 6,895'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 See Attached Schematic 3,695' N/A Length Baker LTP, SSSV 3,198' MD/2,457' TVD; 168' MD/TVD 5,953'6,828'5,887' 16" Beluga River Unit (BRU) 223-34TCO 802A Same 5,952'3-1/2" ~2,230psi Beluga River Sterling-Beluga Gas Size August 28, 2025 Tieback 3-1/2" 6,893' Perforation Depth MD (ft): See Attached Schematic 2,980psi 6,890psi 120'120' 3,391' 120' 3,383' MD 7-58" 9.2# / L-80 TVD Burst 3,206' 10,160psi 2,593' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AKA029656 / AKA029657 225-059 50-283-20206-00-00 Hilcorp Alaska, LLC Proposed Pools: 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: 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 m n P s 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov DOA - Noel Nocas Out of Office By Grace Christianson at 2:56 pm, Aug 25, 2025 Digitally signed by Ryan Lemay (14113) DN: cn=Ryan Lemay (14113) Date: 2025.08.25 14:47:02 - 08'00' Ryan Lemay (14113) 325-513 DSR-8/26/25A.Dewhurst 26AUG25 10-407 BJM 8/27/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.08.28 08:16:53 -08'00'08/28/25 RBDMS JSB 082825 Well Prognosis Well Name: BRU 223-34T API Number: 50-283-20206-00-00 Current Status: New Drill Well Permit to Drill Number: 225-059 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: 2503 psi @ 5442’ TVD (Based on 0.46 psi/ft gradient) Max. Potential Surface Pressure: 2230 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.721 psi/ft using 13.87 ppg EMW FIT at the 7-5/8” surface casing Shallowest Potential Perf TVD: MPSP/(0.721-0.05) = 2230 psi / 0.671 = 3323’ TVD Top of SBGP (CO 802A): ~3712’ MD/~2841’ TVD Well Status: New Drill Well Initial Completion Brief Well Summary BRU 213-26T is the fourth of five grass roots well to be drilled in the 2025 Beluga River drilling campaign targeting the Sterling and Beluga sands. During the drilling of the well the well went on losses and while remediating the losses with cement, the open hole was sidetracked off the cement plug placed to mitigate losses. The objective of this sundry is to perforate the well and flow the new drill well. All sands lie in the Sterling-Beluga Gas Pool (SBGP) per CO 802A and BRU PA. Wellbore Conditions: - Max Inclination – 61° at 2,546’ MD - T & IA PT to 3000 psi (30 min) 8/14/25 - Min ID- 2.813” in SCSSSV @ 168’ (GX Profile) - Wide spot at liner hanger 4.5-5.75” from 3194-3231’ - Cement top ~3958’ (CBL run 8/20/25) - Liner filled with 9.0 ppg drilling mud, tubing is filled with CI 8.4 ppg water - Top Of Pool per CO : ~3712’ MD/~2841’ TVD Work completed on PTD# 225-059 Step 20: - Eline ran CBL (8/19/25) – submitted under separate cover to BLM & AOGCC - CT Cleaned out well and blewdown well with N2, Current pressure 2500 psi. Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 2,500 psi high 3. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 4. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: Below are proposed targeted sands in order of testing (bottom/up), but additional 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 BEL D ±4,528' ±4,533' ±3,608' ±3,613' ±5' BEL D1 ±4,549' ±4,553' ±3,629' ±3,633' ±4' BEL D1 ±4,559' ±4,567' ±3,639' ±3,646' ±8' BEL D3 ±4,596' ±4,619' ±3,675' ±3,698' ±23' CBL received on 8/20/25. Cement covers all proposed perf intervals with TOC approximately 3958' MD. -bjm Well Prognosis 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 BEL D4 ±4,634' ±4,644' ±3,713' ±3,723' ±10' BEL D5 ±4,665' ±4,673' ±3,743' ±3,751' ±8' BEL D6 ±4,689' ±4,693' ±3,767' ±3,771' ±4' BEL D6 ±4,701' ±4,716' ±3,779' ±3,794' ±15' BEL D7 ±4,736' ±4,744' ±3,814' ±3,821' ±8' BEL E1 ±4,779' ±4,791' ±3,856' ±3,868' ±12' BEL E1 ±4,816' ±4,820' ±3,893' ±3,897' ±4' BEL E2 ±4,845' ±4,857' ±3,922' ±3,933' ±12' BEL E3 ±4,892' ±4,896' ±3,968' ±3,972' ±4' BEL E3 ±4,918' ±4,930' ±3,994' ±4,006' ±12' BEL E4 ±4,947' ±4,950' ±4,023' ±4,026' ±3' BEL E5 ±4,976' ±4,979' ±4,052' ±4,055' ±3' BEL E5 ±5,006' ±5,011' ±4,081' ±4,086' ±5' BEL E5 ±5,036' ±5,048' ±4,111' ±4,123' ±12' BEL E6 ±5,088' ±5,108' ±4,163' ±4,183' ±20' BEL F1 ±5,145' ±5,151' ±4,219' ±4,225' ±6' BEL F1 ±5,167' ±5,173' ±4,241' ±4,247' ±6' BEL F1 ±5,176' ±5,182' ±4,250' ±4,256' ±6' BEL F5 ±5,207' ±5,212' ±4,281' ±4,286' ±5' BEL F5 ±5,242' ±5,248' ±4,316' ±4,322' ±6' BEL F5 ±5,259' ±5,269' ±4,332' ±4,342' ±10' BEL F5 ±5,314' ±5,320' ±4,387' ±4,393' ±6' BEL F6 ±5,336' ±5,372' ±4,409' ±4,445' ±36' BEL F6 ±5,429' ±5,434' ±4,501' ±4,506' ±5' BEL F6 ±5,454' ±5,474' ±4,526' ±4,546' ±20' BEL F7 ±5,479' ±5,484' ±4,551' ±4,556' ±5' BEL F7 ±5,493' ±5,499' ±4,565' ±4,571' ±6' BEL F7 ±5,506' ±5,516' ±4,577' ±4,587' ±10' BEL F7 ±5,557' ±5,562' ±4,628' ±4,633' ±5' BEL F10 ±5,640' ±5,660' ±4,710' ±4,730' ±20' BEL F10 ±5,665' ±5,682' ±4,735' ±4,752' ±17' BEL G1 ±5,731' ±5,736' ±4,800' ±4,805' ±5' BEL G3 ±5,781' ±5,801' ±4,850' ±4,869' ±20' BEL G4 ±5,821' ±5,826' ±4,889' ±4,894' ±5' BEL G5 ±5,851' ±5,857' ±4,919' ±4,925' ±6' BEL G5 ±5,872' ±5,878' ±4,940' ±4,946' ±6' BEL G6 ±5,896' ±5,911' ±4,963' ±4,978' ±15' BEL G8 ±5,978' ±5,984' ±5,044' ±5,050' ±6' BEL G9 ±6,008' ±6,024' ±5,074' ±5,090' ±16' BEL G10 ±6,043' ±6,059' ±5,109' ±5,124' ±16' BEL H ±6,101' ±6,124' ±5,166' ±5,189' ±23' BEL H1 ±6,161' ±6,171' ±5,225' ±5,235' ±10' BEL H3 ±6,232' ±6,242' ±5,296' ±5,305' ±10' BEL H6 ±6,374' ±6,380' ±5,436' ±5,442' ±6' Well Prognosis ii. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations b. Complete coil cleanouts as necessary for sand or water production per coil test procedure and equipment listed in PTD# 225-059 Step 20. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Standard Nitrogen Operations Updated by DMA 08-25-25 SCHEMATIC Beluga River Unit BRU 223-34T PTD: 225-059 API: 50-283-20206-00-00 PBTD = 6,828’ MD / TVD = 5,887’ TD = 6,895’ MD / TVD = 5,953’ RKB to GL = 19.9’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875”Surf 3,391’ 3-1/2"Prod Lnr 9.2 L-80 Wedge 563 2.992” 3,198’6,893’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 3,206’ 3/4 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth Item 1 20’Cactus CTF-ONE-CTL 11” x 4-1/2” Hanger w/ 4” Type H BPV profile 2 168’Giant 5K TRSSSV w/ 2.813” GX Profile, SN 10193A 3 3,198’5-1/2” x 7-5/8” Baker ZXP Flexlock with HRD-E Liner top packer w/ 3.5”x 5.5” XO at 3230. Wide spot (4.5”-5.75”) in tubing 37ft (3194’-3231’) 4 3,206 Bullet Seal assembly 2.07’ off no-go at 3196’ OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 206 bbl (503 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 150 bbls (calculated 152 bbls), spacer & 93 bbls of lead cement to surface, 0 bbls of losses during job & reciprocated pipe. 3-1/2” 142 bbls (334 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, bumped plug. Lost returns 28bbls into displacement, circulated out 7bbls of spacer. 95 bbls of losses during cement job. TOC based on CBL @ 3958’ dated 8/18/25) 6-3/4” hole 1 Notes: 10’ Short jt w/ RA tags 6285, 5200, 4115 10’ Short joints 5742, 4659, 3575 Deviation 61 deg @ 2546’, Max dogleg 6.76deg @ 2233’ Well went on losses between 4794-4800 in this hole section @4866’ in open hole well was sidetracked off a loss zone cement plug. 2 RA 4115’ RA 5200’ RA 6285’ Updated by DMA 08-25-25 SCHEMATIC Beluga River Unit BRU 223-34T PTD: 225-059 API: 50-283-20206-00-00 Updated by DMA 08-25-25 PROPOSED Beluga River Unit BRU 223-34T PTD: 225-059 API: 50-283-20206-00-00 PBTD = 6,828’ MD / TVD = 5,887’ TD = 6,895’ MD / TVD = 5,953’ RKB to GL = 19.9’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875”Surf 3,391’ 3-1/2"Prod Lnr 9.2 L-80 Wedge 563 2.992” 3,198’6,893’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 3,206’ 3/4 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth Item 1 20’Cactus CTF-ONE-CTL 11” x 4-1/2” Hanger w/ 4” Type H BPV profile 2 168’Giant 5K TRSSSV w/ 2.813” GX Profile, SN 10193A 3 3,198’5-1/2” x 7-5/8” Baker ZXP Flexlock with HRD-E Liner top packer w/ 3.5”x 5.5” XO at 3230. Wide spot (4.5”-5.75”) in tubing 37ft (3194’-3231’) 4 3,206 Bullet Seal assembly 2.07’ off no-go at 3196’ OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 206 bbl (503 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 150 bbls (calculated 152 bbls), spacer & 93 bbls of lead cement to surface, 0 bbls of losses during job & reciprocated pipe. 3-1/2” 142 bbls (334 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, bumped plug. Lost returns 28bbls into displacement, circulated out 7bbls of spacer. 95 bbls of losses during cement job. TOC based on CBL @ 3958’ dated 8/18/25) 6-3/4” hole 1 Notes: 10’ Short jt w/ RA tags 6285, 5200, 4115 10’ Short joints 5742, 4659, 3575 Deviation 61 deg @ 2546’, Max dogleg 6.76deg @ 2233’ Well went on losses between 4794-4800 in this hole section @4866’ in open hole well was sidetracked off a loss zone cement plug. PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~3,712’ MD/2,841’ TVD Top of PA (BLM) BEL D ±4,528'±4,533'±3,608'±3,613'±5'TBD Proposed BEL D1 ±4,549'±4,553'±3,629'±3,633'±4'TBD Proposed BEL D1 ±4,559'±4,567'±3,639'±3,646'±8'TBD Proposed BEL D3 ±4,596'±4,619'±3,675'±3,698'±23'TBD Proposed BEL D4 ±4,634'±4,644'±3,713'±3,723'±10'TBD Proposed BEL D5 ±4,665'±4,673'±3,743'±3,751'±8'TBD Proposed BEL D6 ±4,689'±4,693'±3,767'±3,771'±4'TBD Proposed BEL D6 ±4,701'±4,716'±3,779'±3,794'±15'TBD Proposed BEL D7 ±4,736'±4,744'±3,814'±3,821'±8'TBD Proposed BEL E1 ±4,779'±4,791'±3,856'±3,868'±12'TBD Proposed BEL E1 ±4,816'±4,820'±3,893'±3,897'±4'TBD Proposed BEL E2 ±4,845'±4,857'±3,922'±3,933'±12'TBD Proposed BEL E3 ±4,892'±4,896'±3,968'±3,972'±4'TBD Proposed BEL E3 ±4,918'±4,930'±3,994'±4,006'±12'TBD Proposed BEL E4 ±4,947'±4,950'±4,023'±4,026'±3'TBD Proposed BEL E5 ±4,976'±4,979'±4,052'±4,055'±3'TBD Proposed BEL E5 ±5,006'±5,011'±4,081'±4,086'±5'TBD Proposed BEL E5 ±5,036'±5,048'±4,111'±4,123'±12'TBD Proposed PERFORATION DETAIL - Continued on Following Page 2 Bel D to Bel H6 RA 4115’ RA 5200’ RA 6285’ Updated by DMA 08-25-25 PROPOSED Beluga River Unit BRU 223-34T PTD: 225-059 API: 50-283-20206-00-00 PERFORATION DETAIL – Continued from Previous Page Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status BEL E6 ±5,088' ±5,108' ±4,163' ±4,183' ±20' TBD Proposed BEL F1 ±5,145' ±5,151' ±4,219' ±4,225' ±6' TBD Proposed BEL F1 ±5,167' ±5,173' ±4,241' ±4,247' ±6' TBD Proposed BEL F1 ±5,176' ±5,182' ±4,250' ±4,256' ±6' TBD Proposed BEL F5 ±5,207' ±5,212' ±4,281' ±4,286' ±5' TBD Proposed BEL F5 ±5,242' ±5,248' ±4,316' ±4,322' ±6' TBD Proposed BEL F5 ±5,259' ±5,269' ±4,332' ±4,342' ±10' TBD Proposed BEL F5 ±5,314' ±5,320' ±4,387' ±4,393' ±6' TBD Proposed BEL F6 ±5,336' ±5,372' ±4,409' ±4,445' ±36' TBD Proposed BEL F6 ±5,429' ±5,434' ±4,501' ±4,506' ±5' TBD Proposed BEL F6 ±5,454' ±5,474' ±4,526' ±4,546' ±20' TBD Proposed BEL F7 ±5,479' ±5,484' ±4,551' ±4,556' ±5' TBD Proposed BEL F7 ±5,493' ±5,499' ±4,565' ±4,571' ±6' TBD Proposed BEL F7 ±5,506' ±5,516' ±4,577' ±4,587' ±10' TBD Proposed BEL F7 ±5,557' ±5,562' ±4,628' ±4,633' ±5' TBD Proposed BEL F10 ±5,640' ±5,660' ±4,710' ±4,730' ±20' TBD Proposed BEL F10 ±5,665' ±5,682' ±4,735' ±4,752' ±17' TBD Proposed BEL G1 ±5,731' ±5,736' ±4,800' ±4,805' ±5' TBD Proposed BEL G3 ±5,781' ±5,801' ±4,850' ±4,869' ±20' TBD Proposed BEL G4 ±5,821' ±5,826' ±4,889' ±4,894' ±5' TBD Proposed BEL G5 ±5,851' ±5,857' ±4,919' ±4,925' ±6' TBD Proposed BEL G5 ±5,872' ±5,878' ±4,940' ±4,946' ±6' TBD Proposed BEL G6 ±5,896' ±5,911' ±4,963' ±4,978' ±15' TBD Proposed BEL G8 ±5,978' ±5,984' ±5,044' ±5,050' ±6' TBD Proposed BEL G9 ±6,008' ±6,024' ±5,074' ±5,090' ±16' TBD Proposed BEL G10 ±6,043' ±6,059' ±5,109' ±5,124' ±16' TBD Proposed BEL H ±6,101' ±6,124' ±5,166' ±5,189' ±23' TBD Proposed BEL H1 ±6,161' ±6,171' ±5,225' ±5,235' ±10' TBD Proposed BEL H3 ±6,232' ±6,242' ±5,296' ±5,305' ±10' TBD Proposed BEL H6 ±6,374' ±6,380' ±5,436' ±5,442' ±6' TBD Proposed STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1 Dewhurst, Andrew D (OGC) From:Cody Dinger <cdinger@hilcorp.com> Sent:Tuesday, 26 August, 2025 14:44 To:Dewhurst, Andrew D (OGC); Chad Helgeson Cc:Guhl, Meredith D (OGC); McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] RE: BRU 223-34T Perf Sundry (325-513): Request for Data Attachments:BRU 223-34T LWD Final.las; BRU 223-34T PB1 LWD Final.las Hi Andy, Attached are the LWD .las Ʊles for BRU 223-34T + PB1. Thank you! Cody Dinger Hilcorp Alaska, LLC Drilling Tech 907-777-8389 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Tuesday, August 26, 2025 2:38 PM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Cody Dinger <cdinger@hilcorp.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] RE: BRU 223-34T Perf Sundry (325-513): Request for Data Chad, I see we already have a copy of the survey. My apologies. Just the .las logs then please. Andy From: Dewhurst, Andrew D (OGC) Sent: Tuesday, 26 August, 2025 14:36 To: chelgeson@hilcorp.com Cc: Cody Dinger <cdinger@hilcorp.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: BRU 223-34T Perf Sundry (325-513): Request for Data Chad, CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 To assist us with the review of this sundry, would you please provide Ʊeld copies of the following: x Directional survey (.txt or other digital format) x LWD logs (in .las format) Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________BELUGA RIV UNIT 223-34T JBR 09/26/2025 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:0 3-1/2" & 4-1/2" joints. Test Results TEST DATA Rig Rep:Ken PorterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley Rig Owner/Rig No.:Hilcorp 147 PTD#:2250590 DATE:8/13/2025 Type Operation:DRILL Annular: 250/3000Type Test:BIWKLY Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopSAM250819190855 Inspector Austin McLeod Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 4.5 MASP: 2079 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 13 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 2-7/8"x5"P #2 Rams 1 Blinds P #3 Rams 1 2-7/8"x5"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 2-1/16"&3-1/P Kill Line Valves 3 2-1/16"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3100 Pressure After Closure P1700 200 PSI Attained P24 Full Pressure Attained P91 Blind Switch Covers:PAll stations Bottle precharge P Nitgn Btls# &psi (avg)P4@2612 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P15 #1 Rams P4 #2 Rams P4 #3 Rams P4 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1       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: Beluga River Unit Field, Sterling-Beluga Gas Pool, BRU 223-34T Hilcorp Alaska, LLC Permit to Drill Number: 225-059 Surface Location: 226' FNL, 215' FEL, Sec 4, T12N, R10W, SM, AK Bottomhole Location: 2365' FSL, 2133' FWL, Sec 34, T13N, 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 17th day of July 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.17 09:02:15 -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: 6,882' TVD: 5,939' 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): 102.9' 15. Distance to Nearest Well Open Surface: x-315440 y-2619699 Zone-4 84.4' to Same Pool:1063' to BRU 223-34 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 8 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# P-110 GBCD 3,383' Surface Surface 3,383' 2,585' 6-3/4" 3-1/2" 9.2# L-80 Wedge 563 3,699' 3,183' 2,439' 6,882' 5,939' Tieback 3-1/2" 9.2# L-80 EUE 3,183' Surface Surface 3,183' 2,439' 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 7/22/2025 3452' to nearest unit boundary Nathan Sperry nathan.sperry@hilcorp.com 907-777-8450 Tieback Assy. 2667 Cement Volume MD Drilling Manager Sean Mclaughlin 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate LengthCasing Size Plugs (measured): (including stage data) Driven L - 1148 ft3 / T - 128 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 2673 GL / BF Elevation above MSL (ft): Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 801 ft3 / T - 131 ft3 2079 1896' FSL, 2267' FWL, Sec 34, T13N, R10W, SM, AK 2365' FSL, 2133' FWL, Sec 34, T13N, R10W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 226' FNL, 215' FEL, Sec 4, T12N, R10W, SM, AK AKA029656 / AKA029657 BRU 223-34T Beluga River Unit Sterling-Beluga Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.06.02 10:19:19 - 08'00' Sean McLaughlin (4311) By Grace Christianson at 10:37 am, Jun 02, 2025 BJM 6/26/25 BOP test to 3000 psi. Annular test to 2500 psi. 50-283-20206-00-00 Submit FIT/LOT results within 48 hrs of obtaining data. 225-059 DSR-6/3/25 CT BOP test to 3500 psi 58 A.Dewhurst 17JUL25 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.17 09:02:27 -08'00' 07/17/25 07/17/25 RBDMS JSB 072225 BRU 223-34T (C-pad) Drilling Program Beluga River Unit May 16, 2025 BRU 223-34T Drilling Procedure Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Planned Wellbore Schematic........................................................................................................6 7.0 Drilling / Completion Summary...................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications....................................................................8 9.0 R/U and Preparatory Work........................................................................................................11 10.0 N/U 21-1/4” 2M Diverter.............................................................................................................12 11.0 Drill 9-7/8” Hole Section..............................................................................................................14 12.0 Run 7-5/8” Surface Casing..........................................................................................................16 13.0 Cement 7-5/8” Surface Casing....................................................................................................18 14.0 BOP N/U and Test........................................................................................................................22 15.0 Drill 6-3/4” Hole Section..............................................................................................................23 16.0 Run 3-1/2” Production Liner......................................................................................................25 17.0 Cement 3-1/2” Production Liner................................................................................................28 18.0 3-1/2” Liner Tieback Polish Run................................................................................................33 19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................34 20.0 CBL and Nitrogen Operation (Post Rig Work)........................................................................35 21.0 Diverter Schematic ......................................................................................................................38 22.0 BOP Schematic.............................................................................................................................39 23.0 Wellhead Schematic.....................................................................................................................40 24.0 Anticipated Drilling Hazards......................................................................................................41 25.0 Hilcorp Rig 147 Layout...............................................................................................................43 26.0 FIT/LOT Procedure ....................................................................................................................44 27.0 Choke Manifold Schematic.........................................................................................................45 28.0 Casing Design Information.........................................................................................................46 29.0 6-3/4” Hole Section MASP..........................................................................................................47 30.0 Spider Plot w/ 660’ Radius for SSSV.........................................................................................48 31.0 Surface Plat (As-Staked NAD27 & NAD83)..............................................................................49 Page 2 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 1.0 Well Summary Well BRU 223-34T Pad & Old Well Designation BRU C Pad – Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Sterling/Beluga Planned Well TD, MD / TVD 6882’ MD / 5939’ TVD PBTD, MD / TVD 6800’ MD / 5858’ TVD AFE Drilling Days 16 AFE Completion Days 3 Maximum Anticipated Pressure (Surface)2079 psi Maximum Anticipated Pressure (Downhole/Reservoir)2673 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 102.9’ Ground Elevation 84.4’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 2.0 Management of Change Information Page 4 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16”15.01”14.822”-84 X-56 Weld 2980 1410 - Surface 9-7/8”7-5/8”6.875”6.750”8.500”29.7 L-80 GBCD 6890 4790 683 Prod 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD563 10160 10540 207 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 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 multiple 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 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 7.0 Drilling / Completion Summary BRU 223-34T is an S-shaped directional grassroots development well to be drilled from BRU C Pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Sterling and Beluga sands. The base plan is an S-shaped directional wellbore with a kickoff point at ~300’ MD. Maximum hole angle will be ~60 deg. and TD of the well will be 6882’ TMD/ 5939’ TVD, ending with 10 deg inclination left in the hole. Vertical separation will be 775 ft. Drilling operations are expected to commence approximately July 15 th, 2025. The Hilcorp Rig #147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 3,383’ MD / 2,585’ 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 BLM and AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Beluga Waste Cells.The contingency plan will be tohaul cuttingsto theKenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 147 to wellsite 2. N/U diverter and test. 3. Drill 9-7/8” hole to surface TD. Run and cmt 7-5/8” surface casing. 4. ND diverter, N/U & test 11” x 5M BOP. 5. Test casing to 3500 psi. Perform 13.7# FIT (13.2# minimum to drill ahead). 6. Drill 6-3/4” hole section to production TD. Perform Wiper trip. 7. Run and cmt 3-1/2” production liner. 8. Displace well to 6% KCL completion fluid. 9. POOH and LDDP. 10. RIH and land 3-1/2” tieback string in liner top. 11. Test IA to 3000; Test tubing to 3000 psi 12. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: Surface hole: GR + Res MWD Production Hole: Triple Combo Page 8 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with all relevant AOGCC regulations and all BLM regulations pertaining to Onshore Order No.1. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of BRU 223-34T. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. And BLM 48 hrs notice prior to testing. 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 and BLM approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the BLM APD and the AOGCC PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. BLM Regulation Variance Requests: x Onshore Oil and Gas Order No. 1, Section III. D. 3. C. o Hilcorp requests approval to install a 2-1/16” 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. Page 9 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 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 48 hours’ notice prior to testing BOPs. x Any other notifications required in APD. Required BLM Notifications: x 48 hours before spud. Follow up with actual spud date and time within 24 hours. x 72 hours before casing running and cmt operations x 72 hours before BOPE tests x 72 hours before logging, coring, & testing x Any other notifications required in APD Additional requirements may be stipulated on APD and Sundry. Page 10 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email:bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) BLM Allie Schoessler / BLM Petroleum Engineer / (O): 907-271-3127 Email:aschoessler@blm.gov Use the below email address for BOP notifications to the BLM: BLM_AK_AKSO_EnergySection_Notifications@blm.gov Page 11 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install landing ring on conductor. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 147, 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 12 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 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. 10.5 Estimated Diverter line orientation on BRU C Pad (orientation is subject to change on location): Page 13 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure Page 14 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 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 3,383’ MD/ 2,585’ 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 a wiper trip halfway through the surface hole interval. Make additional wiper trips if hole conditions dictate. 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 – 9.4 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 15 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH Surface Interval 8.8 – 9.4 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.6 At TD, pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.7 TOH with the drilling assy, handle BHA as appropriate. Page 16 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker TRS 7-5/8” casing running equipment. x Ensure 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 17 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 18 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 13.0 Cement 7-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume is 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 open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 19 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry Tail Slurry 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 Verified cement calcs. -bjm Page 20 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 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 3.7 bbls. 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. x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require running steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 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 wellez: 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 Page 21 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 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 22 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 14.0 BOP N/U and Test 14.1 ND diverter line and diverter 14.2 N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test packoff to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: 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. Page 23 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 15.0 Drill 6-3/4” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH and conduct shallow hole test of MWD to confirm all LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 15.7 Workstring will be 4.5” 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 Hole 9.0–9.4 40-53 15-25 15-25 8.5-9.5 11.0 Page 24 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst.7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 13.7ppg EMW. A 13.2# ppg FIT will result in a 20 bbl KTV assuming an 8.65ppg PP and a 9.4ppg MW (swabbed kick). 15.14 Drill 6-3/4” hole section to 6882’ MD / 5939’ TVD 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 1000’ to 1200’ 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 Lost circulation potential when drilling through Sterling A1 through Beluga F (3952’ to 5680’ MD). 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, laying down drill pipe. LD density and porosity tools. Page 25 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 16.0 Run 3-1/2” Production Liner 16.1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” Hydril 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 Baker landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 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 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure Page 27 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 16.6. Run in hole w/ 3-1/2” liner to the 7-5/8” casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. PU 3-1/2” X 7-5/8” liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 16.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.15. Stage pump rates up slowly to circulating rate.Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 28 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 17.0 Cement 3-1/2” Production Liner 17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. 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. Page 29 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure Estimated Total Cement Volume: Verified cement calcs. -bjm Page 30 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure Cement 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 17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 17.9. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to up as required by service company procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).Hold pressure for 3-5 minutes. 17.11. Slack off total liner weight plus 30k to confirm hanger is set. 17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls. 17.13. Continue 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 (HRD-E) from the liner. Page 31 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 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 packoff bushing from the nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 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. Backup release from liner hanger (verify with service company rep): 17.21. If the tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 17.22. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 17.23. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. 17.24. WOC until the compressive strength hits at least 500 psi before testing casing to 3000 psi and chart for 30 minutes. Page 32 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure Ensure to report the following on wellez: 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 33 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 18.0 3-1/2” Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per service company procedure. 18.3. POOH, and LDDP and polish mill. 18.4. If not completed, test 3-1/2” casing to 3000 psi and chart for 30 minutes Page 34 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 19.0 3-1/2” Tieback Run, ND/NU, RDMO 19.1 PU 3-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 EUE. Ensure any jewelry is picked up per tally. x Install chemical injection mandrel at ~1,500’ MD. 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 #147 Page 35 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 20.0 CBL and Nitrogen Operation (Post Rig Work) Pre-Sundry work: 1. Review all approved COAs 2. MIRU E-line and pressure control equipment 3. Log well with CBL 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 36 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure Page 37 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure Page 38 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 21.0 Diverter Schematic Page 39 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 22.0 BOP Schematic Page 40 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 23.0 Wellhead Schematic Page 41 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 24.0 Anticipated Drilling Hazards 9-7/8” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 – 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help ensure good cement to surface after running the casing, condition the mud to a YP of 25 – 30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 42 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. 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 43 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 25.0 Hilcorp Rig 147 Layout Page 44 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 26.0 FIT/LOT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 45 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 27.0 Choke Manifold Schematic Page 46 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 28.0 Casing Design Information Page 47 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 29.0 6-3/4” Hole Section MASP Page 48 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 30.0 Spider Plot w/ 660’ Radius for SSSV Page 49 Version 0.0 May 16, 2025 BRU 223-34T Drilling Procedure 31.0 Surface Plat (As-Staked NAD27 & NAD83) !"##$ %& ' $ 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000True Vertical Depth (800 usft/in)-800 -400 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 Vertical Section at 344.00° (800 usft/in) 7-5/8" x 9-7/8" 3-1/2" x 6-3/4" 5 0 0 1 0 0 0 1 5 0 0 2000250030003 5 0 0 4 0 0 0 4 5 0 0 50 00 5 5 0 0 6000 6 5 0 0 6882 BRU 223-34T wp02 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 2300' MD, 1953.99' TVD Start Dir 3º/100' : 2730' MD, 2168.99'TVD End Dir : 4396.67' MD, 3491.33' TVD Total Depth : 6882' MD, 5938.91' TVD Sterling A1 Sterling B Sterling C Beluga D Beluga E Beluga F Beluga G Beluga H Beluga I Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: BRU 223-34T 84.40 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2619698.76 315440.06 61° 9' 58.5197 N 151° 2' 42.8360 W SURVEY PROGRAM Date: 2025-05-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.50 3383.13 BRU 223-34T wp02 (BRU 223-34T) 3_MWD+AX+Sag 3383.13 6882.00 BRU 223-34T wp02 (BRU 223-34T) 3_MWD+AX+Sag REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well BRU 223-34T, True North Vertical (TVD) Reference:RKB As-Built @ 102.90usft (HEC 147) Measured Depth Reference:RKB As-Built @ 102.90usft (HEC 147) Calculation Method: Minimum Curvature Project:Beluga River Site:BRU C-Pad Well:BRU 223-34T Wellbore:BRU 223-34T Design:BRU 223-34T wp02 CASING DETAILS TVD TVDSS MD Size Name 2585.00 2482.10 3383.13 7-5/8 7-5/8" x 9-7/8" 5938.91 5836.01 6882.00 3-1/2 3-1/2" x 6-3/4" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.50 0.00 0.00 18.50 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 3 2300.00 60.00 344.00 1953.99 917.94 -263.21 3.00 344.00 954.93 End Dir : 2300' MD, 1953.99' TVD 4 2730.00 60.00 344.00 2168.99 1275.90 -365.86 0.00 0.00 1327.32 Start Dir 3º/100' : 2730' MD, 2168.99'TVD 5 4396.67 10.00 344.00 3491.33 2165.95 -621.08 3.00 180.00 2253.24 End Dir : 4396.67' MD, 3491.33' TVD 6 6882.00 10.00 344.00 5938.91 2580.80 -740.03 0.00 0.00 2684.81 Total Depth : 6882' MD, 5938.91' TVD -150 0 150 300 450 600 750 900 1050 1200 1350 1500 1650 1800 1950 2100 2250 2400 2550 2700 South(-)/North(+) (300 usft/in)-900 -750 -600 -450 -300 -150 0 150 300 450 600 750 900 1050 West(-)/East(+) (300 usft/in) 7-5/8" x 9-7/8" 3-1/2" x 6-3/4" 250500 7 5 0 1 0 0 0 1 2 5 0 1 5 0 0 1 7 5 0 2 0 0 0 2 2 5 0 2 5 0 0 2 7 5 0 3 0 0 0 3 2 5 0 3 5 0 0 3 7 5 0 4 0 0 0 4 2 5 0 4 5 0 0 4 7 5 0 5 0 0 0 5 2 5 0 5 5 0 0 5 7 5 05939 BRU 223-34T wp02 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 2300' MD, 1953.99' TVD Start Dir 3º/100' : 2730' MD, 2168.99'TVD End Dir : 4396.67' MD, 3491.33' TVD Total Depth : 6882' MD, 5938.91' TVD CASING DETAILS TVD TVDSS MD Size Name 2585.00 2482.10 3383.13 7-5/8 7-5/8" x 9-7/8" 5938.91 5836.01 6882.00 3-1/2 3-1/2" x 6-3/4" Project: Beluga River Site: BRU C-Pad Well: BRU 223-34T Wellbore: BRU 223-34T Plan: BRU 223-34T wp02 WELL DETAILS: BRU 223-34T 84.40 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2619698.76 315440.06 61° 9' 58.5197 N 151° 2' 42.8360 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well BRU 223-34T, True North Vertical (TVD) Reference:RKB As-Built @ 102.90usft (HEC 147) Measured Depth Reference:RKB As-Built @ 102.90usft (HEC 147) Calculation Method:Minimum Curvature ( $ ) # $ * +, * - -. %'$ % / !"" # $%&'(&)*+%,- ,& .& ,. , * # $%&'(&)*+%,- 0 / * / ) 1 ,%) ( 2 ),%) %(,*+0 - 1 2%(,*1 23131- 4& ! 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( ( $!$%&! $!$%&' =- (.&- (. ?" &"-&% )0)-)&") ')()+ )123!4! 5)0)-)&") *0--& ')()+ )123!4! 5 6 7 89(& 7 :&. 7 7 $ &. ; $#< $( =& 5 :: & 7 752676.7 8 7 6& 0.001.002.003.004.00Separation Factor0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600Measured Depth (800 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:BRU 223-34T NAD 1927 (NADCON CONUS)Alaska Zone 0484.40+N/-S +E/-W Northing EastingLatittudeLongitude0.000.002619698.76 315440.06 61° 9' 58.5197 N 151° 2' 42.8360 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well BRU 223-34T, True NorthVertical (TVD) Reference: RKB As-Built @ 102.90usft (HEC 147)Measured Depth Reference:RKB As-Built @ 102.90usft (HEC 147)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-05-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.50 3383.13 BRU 223-34T wp02 (BRU 223-34T) 3_MWD+AX+Sag3383.13 6882.00 BRU 223-34T wp02 (BRU 223-34T) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600Measured Depth (800 usft/in)BRU 224-34BRU 241-04 wp04aBRU 211-03BRU 242-04BRU 223-34GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.50 To 6882.00Project: Beluga RiverSite: BRU C-PadWell: BRU 223-34TWellbore: BRU 223-34TPlan: BRU 223-34T wp02CASING DETAILSTVD TVDSS MD Size Name2585.00 2482.10 3383.13 7-5/8 7-5/8" x 9-7/8"5938.91 5836.01 6882.00 3-1/2 3-1/2" x 6-3/4" 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. BELUGA RIVER BRU 223-34T STERLING-BELUGA GAS 225-059 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 223-34TInitial Class/TypeDEV / PENDGeoArea820Unit50220On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250590Field & Pool:BELUGA RIVER, STRLG-BELUGA GAS - 92500NA1Permit fee attachedYesAKA029656 and AKA0296572Lease number appropriateYes3Unique well name and numberYesBELUGA RIVER, STRLG-BELUGA GAS - 92500 - governed by CO 8024Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18Conductor string providedYes19Surface casing protects all known USDWsYes20CMT vol adequate to circulate on conductor & surf csgYes21CMT vol adequate to tie-in long string to surf csgYes22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYes26Adequate wellbore separation proposedYes27If diverter required, does it meet regulationsYes28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP = 2079 psi, BOP rated to 5000 psi (BOP test to 3000 psi)30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNo33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)YesH2S not anticipated based on offset wells.35Permit can be issued w/o hydrogen sulfide measuresYes36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate17-Jul-25ApprBJMDate26-Jun-25ApprADDDate16-Jul-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 7/17/2025