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Home My WebLink About225-038Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 1/21/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260121 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 16RD 50133205540100 207125 12/3/2025 AK E-LINE PPROF T41253 BRU 211-35 50283201890000 223050 11/7/2025 AK E-LINE Perf T41254 BRU 213-26 50283201920000 223069 11/23/2025 AK E-LINE Perf T41255 BRU 213-26T 50283202040000 225038 11/4/2025 AK E-LINE Perf T41256 BRU 241-34S 50283201980000 224077 11/9/2025 AK E-LINE Perf T41257 BRU 241-34T 50283201810000 220052 11/6/2025 AK E-LINE Perf T41258 BRU 244-27 50283201850000 222038 12/13/2025 AK E-LINE Perf T41259 BRU 244-27 50283201850000 222038 12/19/2025 AK E-LINE StripGun T41259 GP ST 17586 9 50733204480000 193062 11/13/2025 AK E-LINE Perf T41260 IRU 241-01 50283201840000 221076 12/21/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/30/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/16/2025 AK E-LINE Plug T41261 IRU 241-01 50283201840000 221076 11/26/2025 AK E-LINE Plug/Perf T41261 KALOTSA 01 50133206570000 216132 11/19/2025 AK E-LINE Perf T41262 KBU 31-18 50133206490000 215024 11/8/2025 AK E-LINE Drift/PPROF T41263 KU 12-17 50133205770000 208089 11/14/2025 AK E-LINE StimGun T41264 LRU C-01RD 50283200610100 201168 11/27/2025 AK E-LINE RCT/Perf T41265 MPI 2-32 50029220840000 190119 12/10/2025 AK E-LINE LDL T41266 MPI 2-38 50029220900000 190129 12/5/2025 AK E-LINE LDL T41267 MPU H-16 50029232270000 204190 12/3/2025 AK E-LINE CBL T41268 MPU H-16 50029232270000 204190 11/19/2025 AK E-LINE TubingCut T41268 MPU I-14 50029232140000 204119 11/13/2025 AK E-LINE CBL T41269 NCIU A-06A 50883200260100 225071 11/28/2025 AK E-LINE Perf/Plug T41270 NCIU A-08 50883200280000 169063 12/2/2025 AK E-LINE GPT T41271 NCIU A-19 50883201940000 224026 12/16/2025 AK E-LINE GPT T41272 NCIU A-19 50883201940000 224026 12/12/2025 AK E-LINE GPT/Perf/Plug T41272 NCIU A-19 50883201940000 224026 12/17/2025 AK E-LINE Perf T41272 NCIU A-21A 50883201990100 225075 12/30/2025 AK E-LINE PPROF T41273 OP19-T1N 50029234910000 213068 11/19/2025 AK E-LINE TubingPunch T41274 BRU 213-26T 50283202040000 225038 11/4/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:35 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PCU D-10 50283202080000 225082 12/9/2025 AK E-LINE Perf T41275 SCU 322C-04 50133101040100 215217 12/4/2025 AK E-LINE TubingPunch T41276 SRU 222-33 50133207150000 223100 12/7/2025 AK E-LINE Plug T41277 SU 43-10 50133207390000 225107 11/26/2025 AK E-LINE CBL T41278 TBU A-12RD 50733200760100 171029 11/29/2025 AK E-LINE Perf T41279 TBU D-24A 50733202240100 174064 12/2/2025 AK E-LINE TubingPunch T41280 TBU D-24A 50733202240100 174064 11/21/2025 AK E-LINE TubingPunch T41280 TBU M-10 50733205880000 209154 11/15/2025 AK E-LINE Perf T41281 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:51 -09'00' 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: 11/20/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251120 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 23 50133206350000 214093 10/14/2025 AK E-LINE PPROF T41129 BR 09-86 50733204480000 193062 10/28/2025 AK E-LINE Perf T41130 BRU 213-26T 50283202040000 225038 10/30/2025 AK E-LINE Perf T41131 END 1-57 50029218730000 188114 11/16/2025 READ PressTempSurvey T41132 END 2-28B 50029218470200 203006 11/15/2025 READ PressTempSurvey T41133 END 2-30B 50029222280200 208187 11/18/2025 READ PressTempSurvey T41134 END 2-52 50029217500000 187092 10/28/2025 HALLIBURTON LDL T41135 KALOTSA 10 50133207320000 224147 11/7/2025 AK E-LINE Perf T41136 MPF-92 50029229240000 198193 11/8/2025 READ CaliperSurvey T41137 MPH-01 50029220610000 190086 11/7/2025 READ CaliperSurvey T41138 MPI-14 50029232140000 204119 11/8/2025 READ CaliperSurvey T41139 MPU H-01 50029220610000 190086 11/4/2025 AK E-LINE Drift/CBL/Caliper/Packer T41138 MPU I-14 50029232140000 204119 11/8/2025 AK E-LINE RigAssist T41139 MPU J-02 50029220710000 190096 11/6/2025 AK E-LINE Caliper/Gyro T41140 NCIU A-07A 50883200270100 225094 11/1/2025 AK E-LINE CBL T41141 NCIU A-07A 50883200270100 225094 11/4/2025 AK E-LINE Perf T41141 ODSN-01A 50703206480100 216008 10/24/2025 HALLIBURTON PACKER T41142 ODSN-25 50703206560000 212030 10/23/2025 HALLIBURTON PACKER T41143 ODSN-26 50703206420000 211121 11/4/2025 HALLIBURTON PERF T41144 PBU 02-10B 50029201630200 200064 10/27/2025 HALLIBURTON RBT T41145 PBU A-24B 50029207430200 225067 10/20/2025 BAKER MRPM T41146 PBU B-05E 50029202760500 225093 10/23/2025 HALLIBURTON RBT T41147 PBU B-05E 50029202760500 225093 10/23/2025 BAKER MRPM T41147 PBU B-20A 50029208420100 212026 10/16/2025 BAKER SPN T41148 PBU F-18B 50029206360200 225099 11/5/2025 HALLIBURTON RBT-COILFLAG T41149 PCU D-10 50283202080000 225082 10/31/2025 AK E-LINE Patch T41150 PCU D-10 50283202080000 225082 10/17/2025 AK E-LINE Perf T41150 PCU D-10 50283202080000 225082 10/22/2025 AK E-LINE Perf T41150 PCU D-10 50283202080000 225082 10/29/2025 AK E-LINE Perf T41150 BRU 213-26T 50283202040000 225038 10/30/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.20 13:27:19 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PCU D-11 50283202090000 225088 10/16/2025 AK E-LINE CBL T41151 PCU D-11 50283202090000 225088 10/24/2025 AK E-LINE Perf T41151 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.20 13:27:31 -09'00' 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): 7,179' N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi Production Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Baker ZXP LTP; N/A 2,781' MD / 2,426'TVD; N/A, N/A 6,739' 7,012' 6,576' Beluga River Sterling-Beluga Gas 16" 7-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 213-26TCO 802A Same 6,644'3-1/2" ~2,234 psi 1,694' N/A Length October 14, 2025 Tieback 3-1/2" 7,082' Perforation Depth MD (ft): See Attached Schematic 2,980psi 6,890psi 120'120' 2,939' Size 120' 2,939' MD Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,794' 10,160psi 2,574' 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 FEDA 029657 225-038 50-283-20204-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 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: 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 October 27, 2025 325-638 By Gavin Gluyas at 10:57 am, Oct 16, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.10.15 16:58:46 - 08'00' Noel Nocas (4361) DSR-10/16/25BJM 10/20/25 10-404 SFD 10/22/2025 10/23/25 Well Prognosis Well Name: BRU 213-26T API Number: 50-283-20204-00-00 Current Status: Flowing Gas Well Permit to Drill Number: 225-038 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: 2507 psi @ 5451 TVD (Based on 0.46 psi/ft gradient) Max. Potential Surface Pressure:2234psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.742 psi/ft using 14.27 ppg EMW FIT at the 7-5/8 surface casing shoe Shallowest Potential Perf TVD: MPSP/(0.742-0.05) = 2234 psi / 0.692 = 3229 TVD Top of SBGP (CO 802A): ~3193 MD/~2816 TVD Well Status: Well online flowing @ 2 mmscfd @ 300 psi Brief Well Summary BRU 213-26T was drilled in June of 2025. It was brought online at higher pressure and not all the perfs were completed that were originally planned. The objective of this sundry is to continue perforating the well. All sands lie in the Sterling-Beluga Gas Pool (SBGP) per CO 802A and BRU PA. Wellbore Conditions: - Max Inclination 45° at 2,220 MD - Min ID- 2.992 3-1/2 tubing/liner - Top Of Pool per CO : 3193 MD/2816 TVD Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 2,500 psi high 3. 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 D1 ±4,015' ±4,031' ±3,626' ±3,641' ±16' BEL D2 ±4,043' ±4,047' ±3,653' ±3,657' ±4' BEL D3 ±4,053' ±4,056' ±3,663' ±3,666' ±3' BEL D4 ±4,093' ±4,101' ±3,702' ±3,710' ±8' BEL D5 ±4,121' ±4,124' ±3,730' ±3,733' ±3' BEL D5 ±4,130' ±4,136' ±3,739' ±3,745' ±6' BEL D6 ±4,168' ±4,181' ±3,777' ±3,789' ±13' BEL E ±4,211' ±4,214' ±3,819' ±3,822' ±3' BEL E1 ±4,240' ±4,248' ±3,848' ±3,856' ±8' BEL E1 ±4,273' ±4,281' ±3,880' ±3,888' ±8' BEL E1 ±4,287' ±4,292' ±3,894' ±3,899' ±5' BEL E3 ±4,338' ±4,352' ±3,945' ±3,958' ±14' BEL E3 ±4,361' ±4,364' ±3,967' ±3,970' ±3' brought online at higher pressure (Based on 0.05 psi/ft gas gradient to surface) Well Prognosis BEL E3 ±4,393' ±4,396' ±3,999' ±4,002' ±3' BEL E4 ±4,407' ±4,413' ±4,013' ±4,019' ±6' BEL E5 ±4,436' ±4,453' ±4,042' ±4,058' ±17' BEL E6 ±4,505' ±4,511' ±4,110' ±4,116' ±6' BEL E6 ±4,524' ±4,540' ±4,129' ±4,145' ±16' BEL E6 ±4,568' ±4,571' ±4,173' ±4,176' ±3' a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Pending well production, all perf intervals may not be completed ii. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 4. RDMO Attachments: 1. Current Schematic 2. Proposed Schematic Updated by CJD 07-21-25 CURRENT Beluga River Unit BRU 213-26T PTD: 225-038 API: 50-283-20204-00-00 PBTD = 7,012 MD / TVD = 6,576 TD = 7,179 MD / TVD = 6,739 RKB to GL = 19.7CASING 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 L-80 GBCD 6.875Surf 2,939 3-1/2" Prod Lnr 9.2 L-80 GB ACME / Hyd 563 2.992 2,7817,082 3-1/2Production Tieback 9.2 L-80 EUE 2.992Surf 2,794 2/3 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 Liner Hanger w/ 4 Type H BPV profile 2 2,7815-1/2 Baker ZXP flexlock w/ HRD-E Liner hanger / LTP Assembly 3 2,7944 Bullet seal assembly, 1.53 off no-go OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 172 bbl (402 sx) 12 ppg lead cement followed by 37 bbl (193 sx) 15.8 tail cement. Bumped plug at 129 bbls (calculated 131 bbls), spacer & 74 bbls of contaminated cement to surface, 22 bbls of losses during job 3-1/2 182 bbls (425 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, bumped plug and Lost Circ 37 bbls into displacement (72 bbls of total losses during job. 30 bbls of spacer & 2 bbls cement to surface). TOC based on CBL @ 3106 dated 6/14/25 6-3/4 hole Notes: 10 Short jt w/ RA tags 6493, 5588, 4555, 3572 10 Short joints 6019, 5065, 4079, 3064 Liner details GB Acme liner is Range III pipe (~42ft), Wedge 563 is Range II pipe (~31ft) XO is at 5388 Deviation Kick off ~670 build to 45 deg @ 2200. Drop to 10deg @ 3387 RA 6493 RA 3572 RA 4555 RA 5588 Bel F1 to Bel H9 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~3,193 MD/2,816 TVD Top of PA (BLM) BEL F1 4,606'4,611'4,210'4,215'5'7/6/25 Open BEL F4 4,648'4,652'4,252'4,256'4'7/6/25 Open BEL F4 4,669'4,673'4,273'4,277'4'7/6/25 Open BEL F4 4,681'4,684'4,285'4,288'3'7/6/25 Open BEL F4 4,687'4,695'4,291'4,299'8'7/6/25 Open BEL F4 4,703'4,706'4,307'4,310'3'7/6/25 Open BEL F5 4,717'4,722'4,321'4,326'5'7/6/25 Open BEL F5 4,739'4,747'4,343'4,350'8'7/5/25 Open BEL F6 4,759'4,762'4,362'4,365'3'7/5/25 Open BEL F6 4,800' 4,804' 4,403' 4,407' 4' 7/5/25 Open BEL F6 4,815' 4,821' 4,418' 4,424' 6' 7/5/25 Open BEL F6 4,836' 4,839' 4,439' 4,442' 3' 7/5/25 Open BEL F6 4,849' 4,852' 4,452' 4,455' 3' 7/5/25 Open BEL F7 4,903' 4,909' 4,506' 4,512' 6' 7/5/25 Open BEL F7 4,942' 4,950' 4,544' 4,552' 8' 7/5/25 Open BEL F10 5,030' 5,035' 4,632' 4,637' 5' 7/5/25 Open BEL G1 5,116' 5,122' 4,717' 4,723' 6' 7/4/25 Open BEL G1 5,134' 5,138' 4,735' 4,739' 4' 7/4/25 Open BEL G2 5,163' 5,171' 4,764' 4,772' 8' 7/4/25 Open BEL G2 5,180' 5,192' 4,781' 4,793' 12' 7/4/25 Open BEL G3 5,212' 5,221' 4,812' 4,821' 9' 7/2/25 Open BEL G5 5,284' 5,290' 4,883' 4,889' 6' 7/2/25 Open PERFORATION DETAIL - Continued on Following Page Updated by DMA 07-21-25 Current Beluga River Unit BRU 213-26T PTD: 225-038 API: 50-283-20204-00-00 PERFORATION DETAIL Continued from Previous Page Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status BEL G6 5,313' 5,316' 4,912' 4,915' 3' 7/2/25 Open BEL G9 5,398' 5,404' 4,995' 5,001' 6' 7/2/25 Open BEL H 5,460' 5,465' 5,056' 5,061' 5' 7/2/25 Open BEL H 5,478' 5,487' 5,074' 5,082' 9' 7/1/25 Open BEL H1 5,499' 5,502' 5,094' 5,097' 3' 7/1/25 Open BEL H2 5,541' 5,547' 5,135' 5,141' 6' 7/1/25 Open BEL H3 5,592' 5,596' 5,185' 5,189' 4' 7/1/25 Open BEL H3 5,601' 5,609' 5,194' 5,202' 8' 7/1/25 Open BEL H4 5,657' 5,661' 5,219' 5,253' 4' 7/1/25 Open BEL H5 5,692' 5,701' 5,283' 5,292' 9' 6/30/25 Open BEL H6 5,734' 5,740' 5,324' 5,330' 6' 6/30/25 Open BEL H7 5,746' 5,771' 5,336' 5,360' 25' 6/30/25 Open BEL H8 5,798' 5,804' 5,387' 5,392' 6' 6/30/25 Open BEL H9 5,807' 5,828' 5,395' 5,416' 21' 6/29/25 Open BEL H9 5,864' 5,870' 5,451' 5,457' 6' 6/29/25 Open Updated by CAH 10-04-25 PROPOSED Beluga River Unit BRU 213-26T PTD: 225-038 API: 50-283-20204-00-00 PBTD = 7,012 MD / TVD = 6,576 TD = 7,179 MD / TVD = 6,739 RKB to GL = 19.7CASING 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 L-80 GBCD 6.875Surf 2,939 3-1/2" Prod Lnr 9.2 L-80 GB ACME / Hyd 563 2.992 2,7817,082 3-1/2Production Tieback 9.2 L-80 EUE 2.992Surf 2,794 2/3 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 Liner Hanger w/ 4 Type H BPV profile 2 2,7815-1/2 Baker ZXP flexlock w/ HRD-E Liner hanger / LTP Assembly 3 2,7944 Bullet seal assembly, 1.53 off no-go OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 172 bbl (402 sx) 12 ppg lead cement followed by 37 bbl (193 sx) 15.8 tail cement. Bumped plug at 129 bbls (calculated 131 bbls), spacer & 74 bbls of contaminated cement to surface, 22 bbls of losses during job 3-1/2 182 bbls (425 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, bumped plug and Lost Circ 37 bbls into displacement (72 bbls of total losses during job. 30 bbls of spacer & 2 bbls cement to surface). TOC based on CBL @ 3106 dated 6/14/25 6-3/4 hole Notes: 10 Short jt w/ RA tags 6493, 5588, 4555, 3572 10 Short joints 6019, 5065, 4079, 3064 Liner details GB Acme liner is Range III pipe (~42ft), Wedge 563 is Range II pipe (~31ft) XO is at 5388 Deviation Kick off ~670 build to 45 deg @ 2200. Drop to 10deg @ 3387 RA 6493 RA 3572 RA 4555 RA 5588 Bel F1 to Bel H9 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~3,193 MD/2,816 TVD Top of PA (BLM) BEL D1 ±4,015'±4,031'±3,626'±3,641'±16'Proposed TBD BEL D2 ±4,043'±4,047'±3,653'±3,657'±4'Proposed TBD BEL D3 ±4,053'±4,056'±3,663'±3,666'±3'Proposed TBD BEL D4 ±4,093'±4,101'±3,702'±3,710'±8'Proposed TBD BEL D5 ±4,121'±4,124'±3,730'±3,733'±3'Proposed TBD BEL D5 ±4,130'±4,136'±3,739'±3,745'±6'Proposed TBD BEL D6 ±4,168'±4,181'±3,777'±3,789'±13'Proposed TBD BEL E ±4,211'±4,214'±3,819'±3,822'±3'Proposed TBD BEL E1 ±4,240'±4,248'±3,848'±3,856'±8'Proposed TBD BEL E1 ±4,273' ±4,281' ±3,880' ±3,888' ±8' Proposed TBD BEL E1 ±4,287' ±4,292' ±3,894' ±3,899' ±5' Proposed TBD BEL E3 ±4,338' ±4,352' ±3,945' ±3,958' ±14' Proposed TBD BEL E3 ±4,361' ±4,364' ±3,967' ±3,970' ±3' Proposed TBD BEL E3 ±4,393' ±4,396' ±3,999' ±4,002' ±3' Proposed TBD BEL E4 ±4,407' ±4,413' ±4,013' ±4,019' ±6' Proposed TBD BEL E5 ±4,436' ±4,453' ±4,042' ±4,058' ±17' Proposed TBD BEL E6 ±4,505' ±4,511' ±4,110' ±4,116' ±6' Proposed TBD BEL E6 ±4,524' ±4,540' ±4,129' ±4,145' ±16' Proposed TBD BEL E6 ±4,568' ±4,571' ±4,173' ±4,176' ±3' Proposed TBD BEL F1 4,606' 4,611' 4,210' 4,215' 5' 7/6/25 Open BEL F4 4,648' 4,652' 4,252' 4,256' 4' 7/6/25 Open PERFORATION DETAIL - Continued on Following Page Updated by DMA 07-21-25 Current Beluga River Unit BRU 213-26T PTD: 225-038 API: 50-283-20204-00-00 PERFORATION DETAIL Continued from Previous Page Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status BEL F4 4,669' 4,673' 4,273' 4,277' 4' 7/6/25 Open BEL F4 4,681' 4,684' 4,285' 4,288' 3' 7/6/25 Open BEL F4 4,687' 4,695' 4,291' 4,299' 8' 7/6/25 Open BEL F4 4,703' 4,706' 4,307' 4,310' 3' 7/6/25 Open BEL F5 4,717' 4,722' 4,321' 4,326' 5' 7/6/25 Open BEL F5 4,739' 4,747' 4,343' 4,350' 8' 7/5/25 Open BEL F6 4,759' 4,762' 4,362' 4,365' 3' 7/5/25 Open BEL F6 4,800' 4,804' 4,403' 4,407' 4' 7/5/25 Open BEL F6 4,815' 4,821' 4,418' 4,424' 6' 7/5/25 Open BEL F6 4,836' 4,839' 4,439' 4,442' 3' 7/5/25 Open BEL F6 4,849' 4,852' 4,452' 4,455' 3' 7/5/25 Open BEL F7 4,903' 4,909' 4,506' 4,512' 6' 7/5/25 Open BEL F7 4,942' 4,950' 4,544' 4,552' 8' 7/5/25 Open BEL F10 5,030' 5,035' 4,632' 4,637' 5' 7/5/25 Open BEL G1 5,116' 5,122' 4,717' 4,723' 6' 7/4/25 Open BEL G1 5,134' 5,138' 4,735' 4,739' 4' 7/4/25 Open BEL G2 5,163' 5,171' 4,764' 4,772' 8' 7/4/25 Open BEL G2 5,180' 5,192' 4,781' 4,793' 12' 7/4/25 Open BEL G3 5,212' 5,221' 4,812' 4,821' 9' 7/2/25 Open BEL G5 5,284' 5,290' 4,883' 4,889' 6' 7/2/25 Open BEL G6 5,313' 5,316' 4,912' 4,915' 3' 7/2/25 Open BEL G9 5,398' 5,404' 4,995' 5,001' 6' 7/2/25 Open BEL H 5,460' 5,465' 5,056' 5,061' 5' 7/2/25 Open BEL H 5,478' 5,487' 5,074' 5,082' 9' 7/1/25 Open BEL H1 5,499' 5,502' 5,094' 5,097' 3' 7/1/25 Open BEL H2 5,541' 5,547' 5,135' 5,141' 6' 7/1/25 Open BEL H3 5,592' 5,596' 5,185' 5,189' 4' 7/1/25 Open BEL H3 5,601' 5,609' 5,194' 5,202' 8' 7/1/25 Open BEL H4 5,657' 5,661' 5,219' 5,253' 4' 7/1/25 Open BEL H5 5,692' 5,701' 5,283' 5,292' 9' 6/30/25 Open BEL H6 5,734' 5,740' 5,324' 5,330' 6' 6/30/25 Open BEL H7 5,746' 5,771' 5,336' 5,360' 25' 6/30/25 Open BEL H8 5,798' 5,804' 5,387' 5,392' 6' 6/30/25 Open BEL H9 5,807' 5,828' 5,395' 5,416' 21' 6/29/25 Open BEL H9 5,864' 5,870' 5,451' 5,457' 6' 6/29/25 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: 09/10/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250910 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 213-26T 50283202040000 225038 6/14/2025 AK E-LINE CBL MPU C-21 50029207530000 182081 7/8/2025 AK E-LINE Caliper MPU M-62 50029237440000 223006 6/23/2025 READ Caliper Survey PBU 01-13A 50029202700100 225052 8/17/2025 BAKER MRPM PBU 01-30A 50029216060100 225050 8/7/2025 BAKER MRPM PBU 07-24A 50029209450100 225045 8/3/2025 BAKER MRPM PBU N-12 50029205570000 181014 8/5/2025 BAKER SPN PBU PSI-09 50029230950000 202124 7/17/2025 HALLIBURTON WFL-TMD3D Please include current contact information if different from above. T40860 T40861 T40862 T40863 194-080 T40864 T40865 T40866 T40867 BRU 213-26T 50283202040000 225038 6/14/2025 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.10 11:27:53 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Joshua Riley - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:BRU 213-26T MIT results Date:Wednesday, June 11, 2025 4:52:34 PM Attachments:BRU 213-26T MIT 6-11-25.xlsx Here you go. Josh Riley Hilcorp DSM (907)776-6776 Cell (907)252-1211 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. %HOXJD5LYHU8QLW7 37' Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2250380 Type Inj N Tubing 3075 3065 3050 3050 Type Test P Packer TVD 2426 BBL Pump 0.7 IA 175 175 170 170 Interval O Test psi 1500 BBL Return 0.7 OA 0 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2250380 Type Inj N Tubing 150 150 150 Type Test P Packer TVD 2426 BBL Pump 1.3 IA 3125 3125 3125 Interval O Test psi 1500 BBL Return 1.3 OA 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:Post completion testing Notes: Notes: Hilcorp Alaska LLC Beluga River H pad Waived Josh Riley 06/11/25 Notes:Post Completion testing Notes: Notes: Notes: BRU 213-26T BRU 213-26T Form 10-426 (Revised 01/2017)2025-0611_MIT_BRU_213-26T_2tests 9 9 9 9 999 9 9 9 999 9 *DVSURGXFHU -5HJJ 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: 08/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250807 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 23 50133206350000 214093 6/26/2025 AK E-LINE PPROF T40741 BCU 25 50133206440000 214132 7/16/2025 AK E-LINE Plug/Cement T40742 BRU 211-35 50283201890000 223050 6/11/2025 AK E-LINE Perf T40743 BRU 211-35 50283201890000 223050 6/20/2025 AK E-LINE PPROF T40743 BRU 213-26 50283201920000 223069 7/7/2025 AK E-LINE Perf T40744 BRU 213-26T 50283202040000 225038 7/2/2025 AK E-LINE Perf T40745 BRU 213-26T 50283202040000 225038 7/4/2025 AK E-LINE Perf T40745 BRU 213-26T 50283202040000 225038 6/28/2025 AK E-LINE Perf T40745 BRU 241-23 50283201910000 223061 7/18/2025 AK E-LINE Perf T40746 GP 11-13RD 50733200260100 191133 6/2/2025 AK E-LINE PPFROF T40747 KBU 32-06 50133206580000 216137 7/1/2025 AK E-LINE PPROF T40748 MPU E-28 50029232590000 202055 5/8/2025 AK E-LINE Caliper T40749 MPU F-21 50029226940000 196135 7/10/2025 AK E-LINE Caliper T40750 MPU G-02 50029219260000 189028 7/6/2025 AK E-LINE Puncher T40751 MPU I-01 50029220650000 190090 7/7/2025 AK E-LINE TubingPunch T40752 NS-19 50029231220000 202207 6/27/2025 AK E-LINE Perf T40753 PBU J-07C 50029202410300 225026 5/29/2025 BAKER MRPM T40754 PBU N-07B 50029201370200 223122 6/7/2025 BAKER MRPM T40755 PCU-05 50283202030000 225037 7/10/2024 AK E-LINE Perf T40756 TBU D-07RD2 50733201170200 192155 7/19/2025 AK E-LINE Perf T40757 TBU M-09 50733204760000 196127 7/18/2025 AK E-LINE Perf T40758 Please include current contact information if different from above. T40745BRU 213-26T 50283202040000 225038 7/2/2025 AK E-LINE Perf T40745BRU 213-26T 50283202040000 225038 7/4/2025 AK E-LINE Perf T40745BRU 213-26T 50283202040000 225038 6/28/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.08 11:16:55 -08'00' David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 7/01/2025 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Well: BRU 213-26T PTD: 225-038 API: 50-283-20204-00-00 FINAL LWD FORMATION EVALUATION LOGS (05/28/2025 to 06/08/2025) DGR, PCG, EWR-M4, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey Folder Contents: Please include current contact information if different from above. 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,179'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi Production 10,540psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Baker ZXP LTP; N/A 2,781' MD / 2,426'TVD; N/A, N/A 6,739'7,012'6,576' Beluga River Sterling-Beluga Gas 16" 7-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 213-26TCO 802A Same 6,644'3-1/2" ~2,360psi 1,694' N/A Length June 20, 2025 5,388'2,607' Tieback 3-1/2" 4,985' 7,082' Perforation Depth MD (ft): 3-1/2" See Attached Schematic 2,980psi 6,890psi 124'124' 2,939' Size 124' 2,939' MD Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,794' 10,160psi 2,574' 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 FEDA 029657 225-038 50-283-20204-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY 10,160psi Tubing Grade: chelgeson@hilcorp.com 907-777-8405 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: m n P s 66 t n N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 11:57 am, Jun 13, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.06.13 10:23:43 - 08'00' Noel Nocas (4361) 325-361 BJM 6/24/25 DSR-6/17/25 10-404 A.Dewhurst 16JUN25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.24 05:58:34 -08'00'06/24/25 RBDMS JSB 062425 Well Prognosis Well Name: BRU 213-26T API Number: 50-283-20204-00-00 Current Status: New Drill Well Permit to Drill Number: 225-038 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: 2714 psi @ 5901’ TVD (Based on 0.46 psi/ft gradient) Max. Potential Surface Pressure: 2360 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.742 psi/ft using 14.27 ppg EMW FIT at the 7-5/8” surface casing shoe Shallowest Potential Perf TVD: MPSP/(0.742-0.05) = 2360 psi / 0.692 = 3410’ TVD Top of SBGP (CO 802A): ~3193’ MD/~2816’ TVD Well Status: New Drill Well Initial Completion Brief Well Summary BRU 213-26T is the second of five grass roots well to be drilled in the 2025 Beluga River drilling campaign targeting the Sterling and Beluga sands. 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 – 45° at 2,220’ MD - T & IA PT to 3000 psi (30 min) – BLM Witnessed - Min ID- 2.992” 3-1/2” tubing/liner - Top Of Pool per CO : 3193’ MD/2816’ TVD Work to be completed on PTD# 225-0238 Step 19: - Eline run CBL (Send log to state prior to perforating on this sundry) - CT cleanout well with water and displace with N2 Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 2,500 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 D1 ±4,015' ±4,031' ±3,626' ±3,641' ±16' BEL D2 ±4,043' ±4,047' ±3,653' ±3,657' ±4' BEL D3 ±4,053' ±4,056' ±3,663' ±3,666' ±3' BEL D4 ±4,093' ±4,101' ±3,702' ±3,710' ±8' BEL D5 ±4,121' ±4,124' ±3,730' ±3,733' ±3' BEL D5 ±4,130' ±4,136' ±3,739' ±3,745' ±6' Well Prognosis BEL D6 ±4,168' ±4,181' ±3,777' ±3,789' ±13' BEL E ±4,211' ±4,214' ±3,819' ±3,822' ±3' BEL E1 ±4,240' ±4,248' ±3,848' ±3,856' ±8' BEL E1 ±4,273' ±4,281' ±3,880' ±3,888' ±8' BEL E1 ±4,287' ±4,292' ±3,894' ±3,899' ±5' BEL E3 ±4,338' ±4,352' ±3,945' ±3,958' ±14' BEL E3 ±4,361' ±4,364' ±3,967' ±3,970' ±3' BEL E3 ±4,393' ±4,396' ±3,999' ±4,002' ±3' BEL E4 ±4,407' ±4,413' ±4,013' ±4,019' ±6' BEL E5 ±4,436' ±4,453' ±4,042' ±4,058' ±17' BEL E6 ±4,505' ±4,511' ±4,110' ±4,116' ±6' BEL E6 ±4,524' ±4,540' ±4,129' ±4,145' ±16' BEL E6 ±4,568' ±4,571' ±4,173' ±4,176' ±3' BEL F1 ±4,606' ±4,611' ±4,210' ±4,215' ±5' BEL F4 ±4,648' ±4,652' ±4,252' ±4,256' ±4' BEL F4 ±4,669' ±4,673' ±4,273' ±4,277' ±4' BEL F4 ±4,681' ±4,684' ±4,285' ±4,288' ±3' BEL F4 ±4,687' ±4,695' ±4,291' ±4,299' ±8' BEL F4 ±4,703' ±4,706' ±4,307' ±4,310' ±3' BEL F5 ±4,717' ±4,722' ±4,321' ±4,326' ±5' BEL F5 ±4,739' ±4,747' ±4,343' ±4,350' ±8' BEL F6 ±4,759' ±4,762' ±4,362' ±4,365' ±3' BEL F6 ±4,800' ±4,804' ±4,403' ±4,407' ±4' BEL F6 ±4,815' ±4,821' ±4,418' ±4,424' ±6' BEL F6 ±4,836' ±4,839' ±4,439' ±4,442' ±3' BEL F6 ±4,849' ±4,852' ±4,452' ±4,455' ±3' BEL F7 ±4,903' ±4,909' ±4,506' ±4,512' ±6' BEL F7 ±4,942' ±4,950' ±4,544' ±4,552' ±8' BEL F7 ±4,987' ±4,990' ±4,589' ±4,592' ±3' BEL F10 ±5,030' ±5,035' ±4,632' ±4,637' ±5' BEL G1 ±5,116' ±5,122' ±4,717' ±4,723' ±6' BEL G1 ±5,134' ±5,138' ±4,735' ±4,739' ±4' BEL G2 ±5,163' ±5,171' ±4,764' ±4,772' ±8' BEL G2 ±5,180' ±5,192' ±4,781' ±4,793' ±12' BEL G3 ±5,212' ±5,221' ±4,812' ±4,821' ±9' BEL G5 ±5,284' ±5,290' ±4,883' ±4,889' ±6' BEL G6 ±5,313' ±5,316' ±4,912' ±4,915' ±3' BEL G9 ±5,398' ±5,404' ±4,995' ±5,001' ±6' BEL H ±5,460' ±5,465' ±5,056' ±5,061' ±5' BEL H ±5,478' ±5,487' ±5,074' ±5,082' ±9' BEL H1 ±5,499' ±5,502' ±5,094' ±5,097' ±3' BEL H2 ±5,541' ±5,547' ±5,135' ±5,141' ±6' BEL H3 ±5,592' ±5,596' ±5,185' ±5,189' ±4' Well Prognosis BEL H3 ±5,601' ±5,609' ±5,194' ±5,202' ±8' BEL H4 ±5,657' ±5,661' ±5,219' ±5,253' ±4' BEL H5 ±5,692' ±5,701' ±5,283' ±5,292' ±9' BEL H6 ±5,734' ±5,740' ±5,324' ±5,330' ±6' BEL H7 ±5,746' ±5,771' ±5,336' ±5,360' ±25' BEL H8 ±5,783' ±5,789' ±5,372' ±5,378' ±6' BEL H8 ±5,798' ±5,804' ±5,387' ±5,392' ±6' BEL H9 ±5,807' ±5,828' ±5,395' ±5,416' ±21' BEL H9 ±5,864' ±5,870' ±5,451' ±5,457' ±6' BEL H12 ±5,974' ±5,982' ±5,559' ±5,567' ±8' BEL H13 ±5,993' ±6,003' ±5,578' ±5,587' ±10' BEL I ±6,218' ±6,221' ±5,798' ±5,801' ±3' BEL I2 ±6,320' ±6,324' ±5,898' ±5,901' ±4' a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Pending well production, all perf intervals may not be completed ii. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 5. RDMO 6. Turn well over to production & flow test well 7. Test SVS as necessary once well has reached stable flow rates a. Notify state 24 hrs prior to testing within 5 days of stable production Attachments: 1. Current Schematic 2. Proposed Schematic Updated by CAH 06-13-25 SCHEMATIC Beluga River Unit BRU 213-26T PTD: 225-038 API: 50-283-20204-00-00 PBTD = 7,012’ MD / TVD = 6,576’ TD = 7,179’ MD / TVD = 6,739’ RKB to GL = 19.7’CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 124' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 2,939’ 3-1/2"Prod Lnr 9.2 L-80 GB ACME 2.992”5,388’7,082’ 3-1/2”Prod Lnr 9.2 L-80 Wedge 563 2.992”2,781’5,388’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 2,794’ 2/3 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” Liner Hanger w/ 4” Type H BPV profile 2 2,781’5-1/2” Baker ZXP flexlock w/ HRD-E Liner hanger / LTP Assembly 3 2,794’4” Bullet seal assembly, 1.53’ off no-go OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 172 bbl (402 sx) 12 ppg lead cement followed by 37 bbl (193 sx) 15.8 tail cement. Bumped plug at 129 bbls (calculated 131 bbls), spacer & 74 bbls of contaminated cement to surface, 22 bbls of losses during job 3-1/2” 182 bbls (425 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, bumped plug and Lost Circ 37 bbls into displacement (72 bbls of total losses during job. 30 bbls of spacer & 2 bbls cement to surface). TOC based on CBL @ xxxx’ To be completed before perforating. 6-3/4” hole Notes: 10’ Short jt w/ RA tags 6493, 5588, 4555, 3572 10’ Short joints 6019, 5065, 4079, 3064 Liner details GB Acme liner is Range III pipe (~42ft), Wedge 563 is Range II pipe (~31ft) XO is at 5388’ Deviation Kick off ~670’ build to 45 deg @ 2200’. Drop to 10deg @ 3387’ RA 6493’ RA 3572’ RA 4555’ RA 5588’ 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~3,193’ MD/2,816’ TVD Top of PA (BLM) Updated by DMA 06-12-25 PROPOSED Beluga River Unit BRU 213-26T PTD: 225-038 API: 50-283-20204-00-00 PBTD = 7,012’ MD / TVD = 6,576’ TD = 7,179’ MD / TVD = 6,739’ RKB to GL = 19.7’CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 124' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 2,939’ 3-1/2"Prod Lnr 9.2 L-80 GB ACME 2.992”5,388’7,082’ 3-1/2”Prod Lnr 9.2 L-80 Wedge 563 2.992”2,781’5,388’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 2,794’ 2/3 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” Liner Hanger w/ 4” Type H BPV profile 2 2,781’5-1/2” Baker ZXP flexlock w/ HRD-E Liner hanger / LTP Assembly 3 2,794’4” Bullet seal assembly, 1.53’ off no-go OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 172 bbl (402 sx) 12 ppg lead cement followed by 37 bbl (193 sx) 15.8 tail cement. Bumped plug at 129 bbls (calculated 131 bbls), spacer & 74 bbls of contaminated cement to surface, 22 bbls of losses during job 3-1/2” 182 bbls (425 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, bumped plug and Lost Circ 37 bbls into displacement (72 bbls of total losses during job. 30 bbls of spacer & 2 bbls cement to surface). TOC based on CBL @ xxxx’ To be completed before perforating. 6-3/4” hole Notes: 10’ Short jt w/ RA tags 6493, 5588, 4555, 3572 10’ Short joints 6019, 5065, 4079, 3064 Liner details GB Acme liner is Range III pipe (~42ft), Wedge 563 is Range II pipe (~31ft) XO is at 5388’ Deviation Kick off ~670’ build to 45 deg @ 2200’. Drop to 10deg @ 3387’ RA 6493’ RA 3572’ RA 4555’ RA 5588’Bel D1 to Bel I2 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~3,193’ MD/2,816’ TVD Top of PA (BLM) BEL D1 ±4,015'±4,031'±3,626'±3,641'±16'Proposed TBD BEL D2 ±4,043'±4,047'±3,653'±3,657'±4'Proposed TBD BEL D3 ±4,053'±4,056'±3,663'±3,666'±3'Proposed TBD BEL D4 ±4,093'±4,101'±3,702'±3,710'±8'Proposed TBD BEL D5 ±4,121'±4,124'±3,730'±3,733'±3'Proposed TBD BEL D5 ±4,130'±4,136'±3,739'±3,745'±6'Proposed TBD BEL D6 ±4,168'±4,181'±3,777'±3,789'±13'Proposed TBD BEL E ±4,211'±4,214'±3,819'±3,822'±3'Proposed TBD BEL E1 ±4,240'±4,248'±3,848'±3,856'±8'Proposed TBD BEL E1 ±4,273'±4,281'±3,880'±3,888'±8'Proposed TBD BEL E1 ±4,287'±4,292'±3,894'±3,899'±5'Proposed TBD BEL E3 ±4,338'±4,352'±3,945'±3,958'±14'Proposed TBD BEL E3 ±4,361'±4,364'±3,967'±3,970'±3'Proposed TBD BEL E3 ±4,393'±4,396'±3,999'±4,002'±3'Proposed TBD BEL E4 ±4,407'±4,413'±4,013'±4,019'±6'Proposed TBD BEL E5 ±4,436'±4,453'±4,042'±4,058'±17'Proposed TBD BEL E6 ±4,505'±4,511'±4,110'±4,116'±6'Proposed TBD BEL E6 ±4,524'±4,540'±4,129'±4,145'±16'Proposed TBD BEL E6 ±4,568'±4,571'±4,173'±4,176'±3'Proposed TBD BEL F1 ±4,606'±4,611'±4,210'±4,215'±5'Proposed TBD BEL F4 ±4,648'±4,652'±4,252'±4,256'±4'Proposed TBD BEL F4 ±4,669'±4,673'±4,273'±4,277'±4'Proposed TBD BEL F4 ±4,681'±4,684'±4,285'±4,288'±3'Proposed TBD BEL F4 ±4,687'±4,695'±4,291'±4,299'±8'Proposed TBD BEL F4 ±4,703'±4,706'±4,307'±4,310'±3'Proposed TBD PERFORATION DETAIL - Continued on Following Page Lost Circ 37 bbls into displacement (72 bbls of total losses during job. 30 bbls of spacer & 2 bbls cement to surface). Updated by DMA 06-12-25 PROPOSED Beluga River Unit BRU 213-26T PTD: 225-038 API: 50-283-20204-00-00 PERFORATION DETAIL – Continued from Previous Page Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status BEL F5 ±4,717' ±4,722' ±4,321' ±4,326' ±5' Proposed TBD BEL F5 ±4,739' ±4,747' ±4,343' ±4,350' ±8' Proposed TBD BEL F6 ±4,759' ±4,762' ±4,362' ±4,365' ±3' Proposed TBD BEL F6 ±4,800' ±4,804' ±4,403' ±4,407' ±4' Proposed TBD BEL F6 ±4,815' ±4,821' ±4,418' ±4,424' ±6' Proposed TBD BEL F6 ±4,836' ±4,839' ±4,439' ±4,442' ±3' Proposed TBD BEL F6 ±4,849' ±4,852' ±4,452' ±4,455' ±3' Proposed TBD BEL F7 ±4,903' ±4,909' ±4,506' ±4,512' ±6' Proposed TBD BEL F7 ±4,942' ±4,950' ±4,544' ±4,552' ±8' Proposed TBD BEL F7 ±4,987' ±4,990' ±4,589' ±4,592' ±3' Proposed TBD BEL F10 ±5,030' ±5,035' ±4,632' ±4,637' ±5' Proposed TBD BEL G1 ±5,116' ±5,122' ±4,717' ±4,723' ±6' Proposed TBD BEL G1 ±5,134' ±5,138' ±4,735' ±4,739' ±4' Proposed TBD BEL G2 ±5,163' ±5,171' ±4,764' ±4,772' ±8' Proposed TBD BEL G2 ±5,180' ±5,192' ±4,781' ±4,793' ±12' Proposed TBD BEL G3 ±5,212' ±5,221' ±4,812' ±4,821' ±9' Proposed TBD BEL G5 ±5,284' ±5,290' ±4,883' ±4,889' ±6' Proposed TBD BEL G6 ±5,313' ±5,316' ±4,912' ±4,915' ±3' Proposed TBD BEL G9 ±5,398' ±5,404' ±4,995' ±5,001' ±6' Proposed TBD BEL H ±5,460' ±5,465' ±5,056' ±5,061' ±5' Proposed TBD BEL H ±5,478' ±5,487' ±5,074' ±5,082' ±9' Proposed TBD BEL H1 ±5,499' ±5,502' ±5,094' ±5,097' ±3' Proposed TBD BEL H2 ±5,541' ±5,547' ±5,135' ±5,141' ±6' Proposed TBD BEL H3 ±5,592' ±5,596' ±5,185' ±5,189' ±4' Proposed TBD BEL H3 ±5,601' ±5,609' ±5,194' ±5,202' ±8' Proposed TBD BEL H4 ±5,657' ±5,661' ±5,219' ±5,253' ±4' Proposed TBD BEL H5 ±5,692' ±5,701' ±5,283' ±5,292' ±9' Proposed TBD BEL H6 ±5,734' ±5,740' ±5,324' ±5,330' ±6' Proposed TBD BEL H7 ±5,746' ±5,771' ±5,336' ±5,360' ±25' Proposed TBD BEL H8 ±5,783' ±5,789' ±5,372' ±5,378' ±6' Proposed TBD BEL H8 ±5,798' ±5,804' ±5,387' ±5,392' ±6' Proposed TBD BEL H9 ±5,807' ±5,828' ±5,395' ±5,416' ±21' Proposed TBD BEL H9 ±5,864' ±5,870' ±5,451' ±5,457' ±6' Proposed TBD BEL H12 ±5,974' ±5,982' ±5,559' ±5,567' ±8' Proposed TBD BEL H13 ±5,993' ±6,003' ±5,578' ±5,587' ±10' Proposed TBD BEL I ±6,218' ±6,221' ±5,798' ±5,801' ±3' Proposed TBD BEL I2 ±6,320' ±6,324' ±5,898' ±5,901' ±4' Proposed TBD 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, Sterling -Beluga Gas Pool, BRU 213-26T Hilcorp Alaska, LLC Permit to Drill Number: 225-038 Surface Location: 809' FSL, 549' FWL, Sec 26, T13N, R10W, SM, AK Bottomhole Location: 2512' FNL, 444' FWL, Sec 26, 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 2VW day of May 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.21 04:26:37 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 7,179' TVD: 6,748' 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): 98' 15. Distance to Nearest Well Open Surface: x-318488 y-2625962 Zone-4 79.5' to Same Pool:1074' to BRU 214-26 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 45 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# L-80 GBCD 2,898' Surface Surface 2,898' 2,538' 6-3/4" 3-1/2" 9.2# L-80 GB ACME 4,481' 2,698' 2,353' 7,179' 6,748' Tieback 3-1/2" 9.2# L-80 EUE 2,698' Surface Surface 2,698' 2,353' 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 6/10/2025 4565' to nearest unit boundary Nathan Sperry nathan.sperry@hilcorp.com 907-777-8450 Tieback Assy. 1474 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 - 966 ft3 / T - 128 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 3037 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 - 1000 ft3 / T - 131 ft3 2362 2116' FSL, 478' FWL, Sec 26, T13N, R10W, SM, AK 2512' FNL, 444' FWL, Sec 26, T13N, R10W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 809' FSL, 549' FWL, Sec 26, T13N, R10W, SM, AK AKA029657 BRU 213-26T 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) By Gavin Gluyas at 3:47 pm, Apr 14, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.04.14 15:37:09 - 08'00' Sean McLaughlin (4311) 225-038 A.Dewhurst 20MAY25 CT BOP test to 3500 psi. Submit FIT/LOT data within 48 hrs of performing test. DSR-4/17/25 BOP test to 3000 psi. Annular test to 2500 psi. 50-283-20204-00-00 BJM 5/20/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.21 04:26:52 -08'00' 05/21/25 05/21/25 RBDMS JSB 052225 BRU 213-26T Drilling Program Beluga River Unit April 2, 2025 BRU 213-26T 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 April 2, 2025 BRU 213-26T Drilling Procedure 1.0 Well Summary Well BRU 213-26T Pad & Old Well Designation BRU H Pad – Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Sterling/Beluga Planned Well TD, MD / TVD 7179 MD / 6748’ TVD PBTD, MD / TVD 7079’ MD / 6648’ TVD AFE Drilling Days 21 AFE Completion Days 4 Maximum Anticipated Pressure (Surface)2362 psi Maximum Anticipated Pressure (Downhole/Reservoir)3037 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 98.0’ Ground Elevation 79.5’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 2.0 Management of Change Information Page 4 Version 0.0 April 2, 2025 BRU 213-26T 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 GB ACME 10160 10540 168 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 April 2, 2025 BRU 213-26T 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 (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 2. Spills: x Notify Drlg Manager 1. Sean Mclaughlin: C: 907-223-6784 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com,andcdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com,and cdinger@hilcorp.com Page 6 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 6.0 Planned Wellbore Schematic Superseded Page 6 Version 0.0 April 2, 2025 6.0 Planned Wellbore Schematic Page 7 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 7.0 Drilling / Completion Summary BRU 213-26T is an S-shaped directional grassroots development well to be drilled from BRU H 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 ~45 deg. and TD of the well will be 7179’ TMD/ 6748’ TVD, ending with 10 deg inclination left in the hole. Vertical separation will be 1955 ft. Drilling operations are expected to commence approximately June 10 th, 2025. The Hilcorp Rig #147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 2,898’ MD / 2,538’ 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 14.0# FIT (13.5# 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 April 2, 2025 BRU 213-26T Drilling Procedure 7.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below 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 213-26T. 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 250/5000 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 April 2, 2025 BRU 213-26T 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: 250/5000 (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 April 2, 2025 BRU 213-26T 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 April 2, 2025 BRU 213-26T Drilling Procedure 8.0 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 April 2, 2025 BRU 213-26T Drilling Procedure 9.0 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 H Pad (orientation is subject to change on location): Page 13 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure Page 13 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure See satellite image showing diverter layout attached. -bjm Page 14 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 10.0 Drill 9-7/8” Hole Section 11.1 P/U 9-7/8” directional drilling assy: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 4-1/2” Workstring & HWDP will come from Hilcorp. 11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 9-7/8” hole section to 2,898’ MD/ 2,538’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale x Take MWD surveys every stand drilled (60’ intervals). 11.5 9-7/8” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 15 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH Surface Interval 8.8 – 9.8 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 April 2, 2025 BRU 213-26T Drilling Procedure 11.0 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 April 2, 2025 BRU 213-26T 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 April 2, 2025 BRU 213-26T Drilling Procedure 12.0 Cement 7-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls spacer. Test surface cmt lines. 13.5 Pump remaining spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 75% lead open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 19 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (2398’ MD to surface)Tail Slurry (2898’ to 2398’ MD) 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 Superseded Page 19 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (2398’ MD to surface) Tail Slurry (2898’ to 2398’ MD) 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 9HULILHGFHPHQWFDOFVEMP Page 20 Version 0.0 April 2, 2025 BRU 213-26T 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 3.6 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 April 2, 2025 BRU 213-26T 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 April 2, 2025 BRU 213-26T Drilling Procedure 13.0 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 250/5000 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. Test BOP to 3000 psi per Nathan Sperry 4/16/25. -bjm Page 23 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 14.0 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 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0 Page 24 Version 0.0 April 2, 2025 BRU 213-26T 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 14.0 ppg EMW. A 13.5# ppg FIT will result in a 25 bbl KTV assuming an 8.6ppg PP and a 9.1ppg MW (swabbed kick). 15.14 Drill 6-3/4” hole section to 7179’ MD / 6748’ 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’ 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, B, C, Beluga D, E, and F (3420’ to 5081’ 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 April 2, 2025 BRU 213-26T Drilling Procedure 15.0 Run 3-1/2” Production Liner 16.1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” GB ACME 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 April 2, 2025 BRU 213-26T Drilling Procedure Page 27 Version 0.0 April 2, 2025 BRU 213-26T 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 April 2, 2025 BRU 213-26T Drilling Procedure 16.0 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 April 2, 2025 BRU 213-26T Drilling Procedure Estimated Total Cement Volume: Superseded Page 29 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure Estimated Total Cement Volume: 9HULILHGFHPHQWFDOFVEMP Page 30 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure Cement Slurry Design: Lead Slurry (6679’ MD to 2698’ MD)Tail Slurry (7179’ to 6679’ MD) 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. 17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. Page 31 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 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 minimum of 12 hours, test casing to 3000 psi and chart for 30 minutes. Page 32 Version 0.0 April 2, 2025 BRU 213-26T 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 sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 33 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 17.0 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 April 2, 2025 BRU 213-26T Drilling Procedure 18.0 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.48 hr notice required. 19.7 Test 7-5/8” x 3-1/2” annulus to 3000 psi and chart for 30 minutes.48 hr notice required. 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 April 2, 2025 BRU 213-26T Drilling Procedure 19.0 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 April 2, 2025 BRU 213-26T Drilling Procedure Page 37 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure Page 38 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 20.0 Diverter Schematic Page 39 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 21.0 BOP Schematic Page 40 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 22.0 Wellhead Schematic Page 41 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 23.0 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 April 2, 2025 BRU 213-26T 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 April 2, 2025 BRU 213-26T Drilling Procedure 24.0 Hilcorp Rig 147 Layout Page 44 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 25.0 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 April 2, 2025 BRU 213-26T Drilling Procedure 26.0 Choke Manifold Schematic Page 46 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 27.0 Casing Design Information Page 47 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 28.0 6-3/4” Hole Section MASP Page 48 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 29.0 Spider Plot w/ 660’ Radius for SSSV Page 49 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure 30.0 Surface Plat (As-Staked NAD27 & NAD83) Page 50 Version 0.0 April 2, 2025 BRU 213-26T Drilling Procedure Standard Proposal Report 02 April, 2025 Plan: BRU 213-26T wp02 Hilcorp Alaska, LLC Beluga River BRU H-Pad Plan: 213-26T BRU 213-26T 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800True Vertical Depth (800 usft/in)-400 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 Vertical Section at 357.00° (800 usft/in) 213-26T T1 7-5/8" x 9 7/8" 3-1/2" x 6 3/4" 5 0 0 1 00 0 1500200025 0 0 30 0 0 350 0 40 00 45 00 5000 550 0 6000 6 500 7000 717 9 BRU 213-26T wp02 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 1800' MD, 1650.47' TVD Start Dir 3º/100' : 2050' MD, 1827.25'TVD End Dir : 3216.67' MD, 2846.08' TVD Total Depth : 7179' MD, 6748.22' 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: Plan: 213-26T 79.50 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2625962.21 318488.32 61° 11' 0.6671 N 151° 1' 42.7077 W SURVEY PROGRAM Date: 2025-03-13T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.50 2750.00 BRU 213-26T wp02 (BRU 213-26T) 3_MWD+AX+Sag 2750.00 7179.00 BRU 213-26T wp02 (BRU 213-26T) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3046.00 2948.00 3419.67 STERLING_A1 3241.00 3143.00 3617.68 STERLING_B 3387.00 3289.00 3765.93 STERLING_C 3585.00 3487.00 3966.98 BELUGA_D 3806.00 3708.00 4191.39 BELUGA_E 4172.00 4074.00 4563.04 BELUGA_F 4682.00 4584.00 5080.91 BELUGA_G 5051.00 4953.00 5455.60 BELUGA H 5809.00 5711.00 6225.29 BELUGA_I REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: 213-26T, True North Vertical (TVD) Reference:RKB Prelim @ 98.00usft (147) Measured Depth Reference:RKB Prelim @ 98.00usft (147) Calculation Method: Minimum Curvature Project:Beluga RiverSite:BRU H-Pad Well:Plan: 213-26T Wellbore:BRU 213-26TDesign:BRU 213-26T wp02 CASING DETAILS TVDSS 2538.32 2440.32 2898.00 7-5/8" x 9 7/8" 6748.22 6650.22 7179.00 3-1/2 3-1/2" x 6 3/4" TVD MD NameSize 7-5/8 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 1800.00 45.00 357.00 1650.47 558.62 -29.28 3.00 357.00 559.38 End Dir : 1800' MD, 1650.47' TVD 4 2050.00 45.00 357.00 1827.25 735.15 -38.53 0.00 0.00 736.16 Start Dir 3º/100' : 2050' MD, 1827.25'TVD 5 3216.67 10.00 357.00 2846.08 1264.80 -66.29 3.00 180.001266.53 End Dir : 3216.67' MD, 2846.08' TVD 6 6244.00 10.00 357.00 5827.42 1789.77 -93.80 0.00 0.001792.22 7 7179.00 10.00 357.00 6748.22 1951.90 -102.29 0.00 0.001954.58 Total Depth : 7179' MD, 6748.22' TVD 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 South(-)/North(+) (200 usft/in)-400 -300 -200 -100 0 100 200 300 400 500 600 700 800 West(-)/East(+) (200 usft/in) 7-5/8" x 9 7/8" 3-1/2" x 6 3/4" 500 750 100 0 1250 150 0 17 50 2000 2250 2500 2750 3000 3250 350 0 3750 400 0 4250 4500 475 0 5000 525 0 550 0 57 5 0 600 0 6250 6500 674 8BRU 213-26T wp02 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 1800' MD, 1650.47' TVD Start Dir 3º/100' : 2050' MD, 1827.25'TVD End Dir : 3216.67' MD, 2846.08' TVD Total Depth : 7179' MD, 6748.22' TVD CASING DETAILS TVD TVDSS MD Size Name 2538.32 2440.32 2898.00 7-5/8 7-5/8" x 9 7/8" 6748.22 6650.22 7179.00 3-1/2 3-1/2" x 6 3/4" Project: Beluga River Site: BRU H-Pad Well: Plan: 213-26T Wellbore: BRU 213-26T Plan: BRU 213-26T wp02 WELL DETAILS: Plan: 213-26T 79.50 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2625962.21 318488.32 61° 11' 0.6671 N 151° 1' 42.7077 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: 213-26T, True NorthVertical (TVD) Reference: RKB Prelim @ 98.00usft (147) Measured Depth Reference:RKB Prelim @ 98.00usft (147) Calculation Method:Minimum Curvature 213-26T T1 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Beluga River BRU H-Pad Standard Proposal Report Well: Wellbore: Plan: 213-26T BRU 213-26T Survey Calculation Method:Minimum Curvature RKB Prelim @ 98.00usft (147) Design:BRU 213-26T wp02 Database:Alaska MD Reference:RKB Prelim @ 98.00usft (147) North Reference: Well Plan: 213-26T True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Beluga River, Alaska, USA Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: Grid Convergence: BRU H-Pad usft Map usft usft °-0.90Slot Radius:"13-3/16 2,625,971.33 318,339.63 5.00 61° 11' 0.7339 N 151° 1' 45.7432 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Plan: 213-26T usft usft 0.00 0.00 2,625,962.21 318,488.32 79.50Wellhead Elevation:usft0.50 61° 11' 0.6671 N 151° 1' 42.7077 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) BRU 213-26T Model NameMagnetics BGGM2024 3/13/2025 14.43 73.91 55,097.36224500 Phase:Version: Audit Notes: Design BRU 213-26T wp02 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:18.50 357.000.000.0018.50 Inclination (°) Azimuth (°) +E/-W (usft) Tool Face (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections TVD System usft 0.000.000.000.000.000.0018.500.000.0018.50 -79.50 0.000.000.000.000.000.00300.000.000.00300.00 202.00 357.000.003.003.00-29.28558.621,650.47357.0045.001,800.00 1,552.47 0.000.000.000.00-38.53735.151,827.25357.0045.002,050.00 1,729.25 180.000.00-3.003.00-66.291,264.802,846.08357.0010.003,216.67 2,748.08 0.000.000.000.00-93.801,789.775,827.42357.0010.006,244.00 5,729.42 0.000.000.000.00-102.291,951.906,748.22357.0010.007,179.00 6,650.22 4/2/2025 4:55:44PM COMPASS 5000.17 Build 04 Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Beluga River BRU H-Pad Standard Proposal Report Well: Wellbore: Plan: 213-26T BRU 213-26T Survey Calculation Method:Minimum Curvature RKB Prelim @ 98.00usft (147) Design:BRU 213-26T wp02 Database:Alaska MD Reference:RKB Prelim @ 98.00usft (147) North Reference: Well Plan: 213-26T True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 79.50 Vert Section 18.50 0.00 18.50 0.00 0.000.00 318,488.322,625,962.2179.50 0.00 0.00 100.00 0.00 100.00 0.00 0.000.00 318,488.322,625,962.21-2.00 0.00 0.00 200.00 0.00 200.00 0.00 0.000.00 318,488.322,625,962.21-102.00 0.00 0.00 300.00 0.00 300.00 0.00 0.000.00 318,488.322,625,962.21-202.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 400.00 3.00 399.95 2.61 -0.14357.00 318,488.222,625,964.83-301.95 3.00 2.62 500.00 6.00 499.63 10.45 -0.55357.00 318,487.942,625,972.66-401.63 3.00 10.46 600.00 9.00 598.77 23.48 -1.23357.00 318,487.462,625,985.71-500.77 3.00 23.51 700.00 12.00 697.08 41.68 -2.18357.00 318,486.792,626,003.91-599.08 3.00 41.74 800.00 15.00 794.31 64.99 -3.41357.00 318,485.942,626,027.24-696.31 3.00 65.08 900.00 18.00 890.18 93.35 -4.89357.00 318,484.902,626,055.62-792.18 3.00 93.48 1,000.00 21.00 984.43 126.68 -6.64357.00 318,483.672,626,088.97-886.43 3.00 126.85 1,100.00 24.00 1,076.81 164.89 -8.64357.00 318,482.272,626,127.20-978.81 3.00 165.12 1,200.00 27.00 1,167.06 207.88 -10.89357.00 318,480.702,626,170.22-1,069.06 3.00 208.16 1,300.00 30.00 1,254.93 255.52 -13.39357.00 318,478.952,626,217.90-1,156.93 3.00 255.87 1,400.00 33.00 1,340.18 307.69 -16.13357.00 318,477.042,626,270.10-1,242.18 3.00 308.12 1,500.00 36.00 1,422.59 364.25 -19.09357.00 318,474.962,626,326.69-1,324.59 3.00 364.75 1,600.00 39.00 1,501.91 425.04 -22.28357.00 318,472.732,626,387.52-1,403.91 3.00 425.62 1,700.00 42.00 1,577.95 489.88 -25.67357.00 318,470.362,626,452.41-1,479.95 3.00 490.56 1,800.00 45.00 1,650.47 558.62 -29.28357.00 318,467.842,626,521.18-1,552.47 3.00 559.38 End Dir : 1800' MD, 1650.47' TVD 1,900.00 45.00 1,721.19 629.23 -32.98357.00 318,465.252,626,591.84-1,623.19 0.00 630.10 2,000.00 45.00 1,791.90 699.85 -36.68357.00 318,462.662,626,662.50-1,693.90 0.00 700.81 2,050.00 45.00 1,827.25 735.15 -38.53357.00 318,461.362,626,697.83-1,729.25 0.00 736.16 Start Dir 3º/100' : 2050' MD, 1827.25'TVD 2,100.00 43.50 1,863.07 769.99 -40.35357.00 318,460.082,626,732.69-1,765.07 3.00 771.05 2,200.00 40.50 1,937.37 836.81 -43.86357.00 318,457.632,626,799.55-1,839.37 3.00 837.96 2,300.00 37.50 2,015.08 899.65 -47.15357.00 318,455.332,626,862.43-1,917.08 3.00 900.88 2,400.00 34.50 2,095.97 958.34 -50.22357.00 318,453.182,626,921.16-1,997.97 3.00 959.65 2,500.00 31.50 2,179.83 1,012.72 -53.07357.00 318,451.182,626,975.58-2,081.83 3.00 1,014.11 2,600.00 28.50 2,266.42 1,062.65 -55.69357.00 318,449.352,627,025.53-2,168.42 3.00 1,064.10 2,700.00 25.50 2,355.51 1,107.98 -58.07357.00 318,447.692,627,070.89-2,257.51 3.00 1,109.50 2,800.00 22.50 2,446.85 1,148.59 -60.20357.00 318,446.202,627,111.53-2,348.85 3.00 1,150.17 2,898.00 19.56 2,538.32 1,183.71 -62.04357.00 318,444.912,627,146.67-2,440.32 3.00 1,185.33 7-5/8" x 9 7/8" 2,900.00 19.50 2,540.20 1,184.37 -62.07357.00 318,444.892,627,147.34-2,442.20 3.00 1,186.00 3,000.00 16.50 2,635.30 1,215.23 -63.69357.00 318,443.762,627,178.22-2,537.30 3.00 1,216.90 3,100.00 13.50 2,731.88 1,241.07 -65.04357.00 318,442.812,627,204.08-2,633.88 3.00 1,242.78 3,200.00 10.50 2,829.68 1,261.83 -66.13357.00 318,442.052,627,224.85-2,731.68 3.00 1,263.57 3,216.67 10.00 2,846.09 1,264.80 -66.29357.00 318,441.942,627,227.81-2,748.09 3.00 1,266.53 End Dir : 3216.67' MD, 2846.08' TVD 3,300.00 10.00 2,928.15 1,279.25 -67.04357.00 318,441.412,627,242.27-2,830.15 0.00 1,281.00 3,400.00 10.00 3,026.63 1,296.59 -67.95357.00 318,440.772,627,259.62-2,928.63 0.00 1,298.37 3,419.67 10.00 3,046.00 1,300.00 -68.13357.00 318,440.652,627,263.04-2,948.00 0.00 1,301.78 STERLING_A1 4/2/2025 4:55:44PM COMPASS 5000.17 Build 04 Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Beluga River BRU H-Pad Standard Proposal Report Well: Wellbore: Plan: 213-26T BRU 213-26T Survey Calculation Method:Minimum Curvature RKB Prelim @ 98.00usft (147) Design:BRU 213-26T wp02 Database:Alaska MD Reference:RKB Prelim @ 98.00usft (147) North Reference: Well Plan: 213-26T True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS -3,027.11 Vert Section 3,500.00 10.00 3,125.11 1,313.93 -68.86357.00 318,440.142,627,276.98-3,027.11 0.00 1,315.73 3,600.00 10.00 3,223.59 1,331.27 -69.77357.00 318,439.502,627,294.33-3,125.59 0.00 1,333.10 3,617.68 10.00 3,241.00 1,334.33 -69.93357.00 318,439.392,627,297.40-3,143.00 0.00 1,336.17 STERLING_B 3,700.00 10.00 3,322.07 1,348.61 -70.68357.00 318,438.872,627,311.68-3,224.07 0.00 1,350.46 3,765.93 10.00 3,387.00 1,360.04 -71.28357.00 318,438.452,627,323.12-3,289.00 0.00 1,361.91 STERLING_C 3,800.00 10.00 3,420.55 1,365.95 -71.59357.00 318,438.232,627,329.03-3,322.55 0.00 1,367.83 3,900.00 10.00 3,519.03 1,383.29 -72.50357.00 318,437.592,627,346.39-3,421.03 0.00 1,385.19 3,966.98 10.00 3,585.00 1,394.91 -73.10357.00 318,437.172,627,358.01-3,487.00 0.00 1,396.82 BELUGA_D 4,000.00 10.00 3,617.51 1,400.63 -73.40357.00 318,436.962,627,363.74-3,519.51 0.00 1,402.56 4,100.00 10.00 3,716.00 1,417.97 -74.31357.00 318,436.322,627,381.09-3,618.00 0.00 1,419.92 4,191.39 10.00 3,806.00 1,433.82 -75.14357.00 318,435.742,627,396.95-3,708.00 0.00 1,435.79 BELUGA_E 4,200.00 10.00 3,814.48 1,435.32 -75.22357.00 318,435.692,627,398.44-3,716.48 0.00 1,437.29 4,300.00 10.00 3,912.96 1,452.66 -76.13357.00 318,435.052,627,415.79-3,814.96 0.00 1,454.65 4,400.00 10.00 4,011.44 1,470.00 -77.04357.00 318,434.412,627,433.15-3,913.44 0.00 1,472.01 4,500.00 10.00 4,109.92 1,487.34 -77.95357.00 318,433.782,627,450.50-4,011.92 0.00 1,489.38 4,563.04 10.00 4,172.00 1,498.27 -78.52357.00 318,433.382,627,461.44-4,074.00 0.00 1,500.33 BELUGA_F 4,600.00 10.00 4,208.40 1,504.68 -78.86357.00 318,433.142,627,467.85-4,110.40 0.00 1,506.74 4,700.00 10.00 4,306.88 1,522.02 -79.77357.00 318,432.512,627,485.20-4,208.88 0.00 1,524.11 4,800.00 10.00 4,405.36 1,539.36 -80.67357.00 318,431.872,627,502.55-4,307.36 0.00 1,541.47 4,900.00 10.00 4,503.84 1,556.70 -81.58357.00 318,431.232,627,519.91-4,405.84 0.00 1,558.84 5,000.00 10.00 4,602.32 1,574.04 -82.49357.00 318,430.602,627,537.26-4,504.32 0.00 1,576.20 5,080.91 10.00 4,682.00 1,588.07 -83.23357.00 318,430.082,627,551.30-4,584.00 0.00 1,590.25 BELUGA_G 5,100.00 10.00 4,700.80 1,591.38 -83.40357.00 318,429.962,627,554.61-4,602.80 0.00 1,593.57 5,200.00 10.00 4,799.28 1,608.73 -84.31357.00 318,429.332,627,571.96-4,701.28 0.00 1,610.93 5,300.00 10.00 4,897.76 1,626.07 -85.22357.00 318,428.692,627,589.31-4,799.76 0.00 1,628.30 5,400.00 10.00 4,996.25 1,643.41 -86.13357.00 318,428.062,627,606.67-4,898.25 0.00 1,645.66 5,455.60 10.00 5,051.00 1,653.05 -86.63357.00 318,427.702,627,616.31-4,953.00 0.00 1,655.32 BELUGA H 5,500.00 10.00 5,094.73 1,660.75 -87.04357.00 318,427.422,627,624.02-4,996.73 0.00 1,663.03 5,600.00 10.00 5,193.21 1,678.09 -87.94357.00 318,426.782,627,641.37-5,095.21 0.00 1,680.39 5,700.00 10.00 5,291.69 1,695.43 -88.85357.00 318,426.152,627,658.72-5,193.69 0.00 1,697.76 5,800.00 10.00 5,390.17 1,712.77 -89.76357.00 318,425.512,627,676.07-5,292.17 0.00 1,715.12 5,900.00 10.00 5,488.65 1,730.11 -90.67357.00 318,424.882,627,693.43-5,390.65 0.00 1,732.49 6,000.00 10.00 5,587.13 1,747.45 -91.58357.00 318,424.242,627,710.78-5,489.13 0.00 1,749.85 6,100.00 10.00 5,685.61 1,764.79 -92.49357.00 318,423.602,627,728.13-5,587.61 0.00 1,767.22 6,200.00 10.00 5,784.09 1,782.14 -93.40357.00 318,422.972,627,745.48-5,686.09 0.00 1,784.58 6,225.29 10.00 5,809.00 1,786.52 -93.63357.00 318,422.812,627,749.87-5,711.00 0.00 1,788.97 BELUGA_I 6,244.00 10.00 5,827.42 1,789.77 -93.80357.00 318,422.692,627,753.12-5,729.42 0.00 1,792.22 4/2/2025 4:55:44PM COMPASS 5000.17 Build 04 Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Beluga River BRU H-Pad Standard Proposal Report Well: Wellbore: Plan: 213-26T BRU 213-26T Survey Calculation Method:Minimum Curvature RKB Prelim @ 98.00usft (147) Design:BRU 213-26T wp02 Database:Alaska MD Reference:RKB Prelim @ 98.00usft (147) North Reference: Well Plan: 213-26T True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS -5,784.57 Vert Section 6,300.00 10.00 5,882.57 1,799.48 -94.31357.00 318,422.332,627,762.84-5,784.57 0.00 1,801.95 6,400.00 10.00 5,981.05 1,816.82 -95.22357.00 318,421.702,627,780.19-5,883.05 0.00 1,819.31 6,500.00 10.00 6,079.53 1,834.16 -96.12357.00 318,421.062,627,797.54-5,981.53 0.00 1,836.68 6,600.00 10.00 6,178.01 1,851.50 -97.03357.00 318,420.422,627,814.89-6,080.01 0.00 1,854.04 6,700.00 10.00 6,276.50 1,868.84 -97.94357.00 318,419.792,627,832.24-6,178.50 0.00 1,871.41 6,800.00 10.00 6,374.98 1,886.18 -98.85357.00 318,419.152,627,849.60-6,276.98 0.00 1,888.77 6,900.00 10.00 6,473.46 1,903.52 -99.76357.00 318,418.522,627,866.95-6,375.46 0.00 1,906.14 7,000.00 10.00 6,571.94 1,920.86 -100.67357.00 318,417.882,627,884.30-6,473.94 0.00 1,923.50 7,100.00 10.00 6,670.42 1,938.21 -101.58357.00 318,417.242,627,901.65-6,572.42 0.00 1,940.87 7,179.00 10.00 6,748.22 1,951.90 -102.29357.00 318,416.742,627,915.36-6,650.22 0.00 1,954.58 Total Depth : 7179' MD, 6748.22' TVD - 3-1/2" x 6 3/4" Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Targets Dip Angle (°) Dip Dir. (°) 213-26T T1 5,827.00 2,627,747.50 318,420.301,784.11 -96.100.00 0.00 - plan misses target center by 5.96usft at 6242.62usft MD (5826.07 TVD, 1789.53 N, -93.79 E) - Circle (radius 100.00) Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 3-1/2" x 6 3/4"6,748.227,179.00 3-1/2 6-3/4 7-5/8" x 9 7/8"2,538.322,898.00 7-5/8 9-7/8 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations Vertical Depth SS 3,966.98 3,585.00 BELUGA_D 6,225.29 5,809.00 BELUGA_I 5,080.91 4,682.00 BELUGA_G 5,455.60 5,051.00 BELUGA H 4,563.04 4,172.00 BELUGA_F 3,617.68 3,241.00 STERLING_B 4,191.39 3,806.00 BELUGA_E 3,419.67 3,046.00 STERLING_A1 3,765.93 3,387.00 STERLING_C 4/2/2025 4:55:44PM COMPASS 5000.17 Build 04 Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Beluga River BRU H-Pad Standard Proposal Report Well: Wellbore: Plan: 213-26T BRU 213-26T Survey Calculation Method:Minimum Curvature RKB Prelim @ 98.00usft (147) Design:BRU 213-26T wp02 Database:Alaska MD Reference:RKB Prelim @ 98.00usft (147) North Reference: Well Plan: 213-26T True Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 300.00 300.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 1,800.00 1,650.47 558.62 -29.28 End Dir : 1800' MD, 1650.47' TVD 2,050.00 1,827.25 735.15 -38.53 Start Dir 3º/100' : 2050' MD, 1827.25'TVD 3,216.67 2,846.09 1,264.80 -66.29 End Dir : 3216.67' MD, 2846.08' TVD 7,179.00 6,748.22 1,951.90 -102.29 Total Depth : 7179' MD, 6748.22' TVD 4/2/2025 4:55:44PM COMPASS 5000.17 Build 04 Page 6 Clearance SummaryAnticollision Report02 April, 2025Hilcorp Alaska, LLCBeluga RiverBRU H-PadPlan: 213-26TBRU 213-26TBRU 213-26T wp02Reference Design: BRU H-Pad - Plan: 213-26T - BRU 213-26T - BRU 213-26T wp02Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 2,625,962.21 N, 318,488.32 E (61° 11' 00.67" N, 151° 01' 42.71" W)Datum Height: RKB Prelim @ 98.00usft (147)Scan Range: 0.00 to 7,179.00 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.17 Build: 04Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00 Beluga RiverHilcorp Alaska, LLCAnticollision Report for Plan: 213-26T - BRU 213-26T wp02Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 0.00 to 7,179.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: BRU H-Pad - Plan: 213-26T - BRU 213-26T - BRU 213-26T wp02MeasuredDepth(usft)Summary Based on MinimumSeparation WarningBRU H-PadBRU 212-26 - BRU 212-26 - BRU 212-26 99.04 1,182.60 87.85 1,174.29 8.8531,182.60Clearance Factor Pass - BRU 213-26 - BRU 213-26 - BRU 213-26 49.20 976.12 40.04 1,007.52 5.367976.12Ellipse Separation Pass - BRU 213-26 - BRU 213-26 - BRU 213-26 50.99 1,000.00 41.19 1,027.92 5.2031,000.00Clearance Factor Pass - BRU 214-26 - BRU 214-26 - BRU 214-26 152.97 1,292.53 143.72 1,304.74 16.5341,292.53Ellipse Separation Pass - BRU 214-26 - BRU 214-26 - BRU 214-26 1,487.04 6,725.00 1,395.46 6,448.00 16.2386,725.00Clearance Factor Pass - BRU 214-26 - BRU 214-26PB1 - BRU 214-26PB1 152.97 1,292.53 143.72 1,304.74 16.5341,292.53Ellipse Separation Pass - BRU 214-26 - BRU 214-26PB1 - BRU 214-26PB1 153.93 1,325.00 144.54 1,333.22 16.3931,325.00Clearance Factor Pass - BRU 221-35 - BRU 221-35 - BRU 221-35 102.12 209.12 99.55 208.93 39.672209.12Centre Distance Pass - BRU 221-35 - BRU 221-35 - BRU 221-35 102.24 250.00 99.44 249.15 36.587250.00Ellipse Separation Pass - BRU 221-35 - BRU 221-35 - BRU 221-35 125.01 625.00 119.63 611.00 23.227625.00Clearance Factor Pass - BRU 222-26 - BRU 222-26 - BRU 222-26 215.66 191.80 213.18 191.70 87.011191.80Centre Distance Pass - BRU 222-26 - BRU 222-26 - BRU 222-26 215.79 225.00 213.15 223.22 81.686225.00Ellipse Separation Pass - BRU 222-26 - BRU 222-26 - BRU 222-26 986.28 2,575.00 945.63 2,295.24 24.2602,575.00Clearance Factor Pass - BRU 241-34S - BRU 241-34S - BRU 241-34S 120.94 490.03 116.66 496.67 28.248490.03Centre Distance Pass - BRU 241-34S - BRU 241-34S - BRU 241-34S 120.96 500.00 116.61 506.53 27.794500.00Ellipse Separation Pass - BRU 241-34S - BRU 241-34S - BRU 241-34S 143.08 750.00 136.77 751.59 22.702750.00Clearance Factor Pass - UnMarked well BRU 212-26 Offset - Wellbore #1 - Unm151.41 489.60 148.42 500.00 50.553489.60Ellipse Separation Pass - UnMarked well BRU 212-26 Offset - Wellbore #1 - Unm155.46 525.00 152.33 500.00 49.562525.00Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool18.50 2,750.00 BRU 213-26T wp02 3_MWD+AX+Sag2,750.00 7,179.00 BRU 213-26T wp02 3_MWD+AX+Sag02 April, 2025 - 17:01COMPASSPage 2 of 5 Beluga RiverHilcorp Alaska, LLCAnticollision Report for Plan: 213-26T - BRU 213-26T wp02Ellipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.02 April, 2025 - 17:01COMPASSPage 3 of 5 0.001.503.004.50Separation Factor0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200Measured DepthNo-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: 213-26T NAD 1927 (NADCON CONUS)Alaska Zone 0479.50+N/-S +E/-W Northing Easting Latittude Longitude0.000.002625962.21318488.3261° 11' 0.6671 N151° 1' 42.7077 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: 213-26T, True NorthVertical (TVD) Reference:RKB Prelim @ 98.00usft (147)Measured Depth Reference:RKB Prelim @ 98.00usft (147)Calculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2025-03-13T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.50 2750.00 BRU 213-26T wp02 (BRU 213-26T) 3_MWD+AX+Sag2750.00 7179.00 BRU 213-26T wp02 (BRU 213-26T) 3_MWD+AX+Sag0.0035.0070.00105.00140.00175.00Centre to Centre Separation (60.00 usft/in)0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200Measured DepthNO GLOBAL FILTER: Using user defined selection & filtering criteria18.50 To 7179.00Project: Beluga RiverSite: BRU H-PadWell: Plan: 213-26TWellbore: BRU 213-26TPlan: BRU 213-26T wp02Ladder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name2538.32 2440.32 2898.00 7-5/8 7-5/8" x 9 7/8"6748.22 6650.22 7179.00 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 nogreater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. STERLING-BELUGA GAS 225-038 BRU 213-26T BELUGA RIVER WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 213-26TInitial Class/TypeDEV / PENDGeoArea820Unit50220On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250380Field & Pool:BELUGA RIVER, STRLG-BELUGA GAS - 92500NA1 Permit fee attachedYes AKA0296572 Lease number appropriateYes3 Unique well name and numberYes BELUGA RIVER, STRLG-BELUGA GAS - 92500 - governed by CO 8024 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP=2362 psi, BOP rated to 5k psi (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes No H2S anticipated35 Permit can be issued w/o hydrogen sulfide measuresYes Max reservoir pressure 7.7 ppg EMW. Several sands severely under-pressured (2.25 ppg)36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate5/20/2025ApprBJMDate5/19/2025ApprADDDate5/20/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 5/21/2025