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Home My WebLink About225-0651. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 6,266' N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: 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 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: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA 029657 225-065 50-283-20207-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,738' 10,160psi 2,576' Size 120' 2,839' MD See Attached Schematic 2,980psi 6,890psi 120'120' 2,862' February 5, 2026 Tieback 3-1/2" 6,266' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 234-27CO 802A Same 5,910'3-1/2" ~1974psi 3,563' See Schematic Length LTP; N/A 2,704' MD/2,426' TVD; N/A, N/A 5,910' 6,172' 5,819' Beluga River Sterling-Beluga Gas 16" 7-5/8" See Attached Schematic m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2026.01.23 13:39:42 - 09'00' Noel Nocas (4361) 326-048 By Grace Christianson at 2:15 pm, Jan 23, 2026 Perforate 10-404 BJM 1/29/26 Dump bail 25' of cement on existing plug at 5600' before adding additional perforations. DSR-1/27/26SFD 1/26/2026JLC 1/29/2026 01/29/26 Well Prognosis Well Name: BRU 234-27 API Number: 50-283-20207-00-00 Current Status: Gas Producer Permit to Drill Number: 225-065 Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) First Call Engineer: Ryan LeMay (661) 487-0871 (C) Maximum Expected BHP: 2214 psi @ 4815 TVD (Based on 0.46 psi/ft gradient) Max. Potential Surface Pressure:1974 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.74 psi/ft using 14.23 ppg EMW FIT at the 7-5/8 surface casing Shallowest Potential Perf TVD: MPSP/(0.74-0.05) = 1974 psi / 0.69 = 2861 TVD Top of SBGP (CO 802A): 3190 MD / 2894 TVD Well Status: Currently online at 1200 mcfd / 0 bwpd water / 150 psi FTP (As of 1/22/26) Brief Well Summary BRU 234-27 was drilled in the 2025 Beluga River drilling campaign targeting the Sterling and Beluga sands. The objective of this sundry is to add perforations to the well. All sands lie in the Sterling-Beluga Gas Pool (SBGP) per CO 802A and BRU PA. Wellbore Conditions: - Max Inclination 42° at 1,984 MD Procedure: 1. Review all COAs for AOGCC & BLM 2. MIRU E-line and pressure control equipment 3. PT lubricator to 250 psi low / 2,500 psi high 4. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: Sands Top MD Btm MD Top TVD Btm TVD Amt Top of Pool per CO 802A: ~3,190 MD/2,894 TVD Top of PA (BLM) BEL D1 +3,933 +3,939 +3,624 +3,630 +6 BEL D4 +4,007 +4,012 +3,697 +3,701 +4 BEL D5 +4,034 +4,039 +3,723 +3,728 +5 BEL D6 +4,075 +4,094 +3,763 +3,782 +19 BEL E1 +4,152 +4,155 +3,839 +3,842 +3 BEL E2 +4,217 +4,221 +3,903 +3,907 +4 BEL E3 +4,252 +4,257 +3,938 +3,942 +4 BEL E5 +4,354 +4,359 +4,038 +4,043 +5 BEL E5 +4,374 +4,378 +4,058 +4,061 +3 BEL E6 +4,437 +4,443 +4,120 +4,126 +6 BEL E6 +4,458 +4,461 +4,140 +4,143 +3 BEL F6 +4,735 +4,739 +4,414 +4,418 +4 BEL F6 +4,751 +4,754 +4,430 +4,432 +3 BEL F7 +4,941 +4,947 +4,616 +4,622 +6 BEL G3 +5,127 +5,134 +4,799 +4,805 +6 BEL G3 +5,144 +5,148 +4,815 +4,819 +4 0.05 psi/ft gas gradient Well Prognosis a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Pending well production, all perf intervals may not be completed Attachments: 1. Current Schematic 2. Proposed Schematic Updated by CJD 10-29-25 Schematic +PB1/PB2 Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 PBTD 6,172 MD / TVD 5,819 TD 6,266 MD / TVD 5,910 RKB to GL = 19.8 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875Surf 2,862 3-1/2"Prod Lnr 9.2 L-80 Wedge 563 2.9922,7036,266 3-1/2Production Tieback 9.2 L-80 EUE 2.992Surf 2,738 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 2,704YJ Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 3 2,7384 Bullet seal assembly, 2.06 off no-go 4 5,600CIBP 5 5,960CIBP 6 6,050CIBP 7 6,155CIBP 8 6,195CIBP OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 168 bbl (424 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 127 bbls (calculated 127 bbls), spacer & 63 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2 140 bbls (329 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, Lost return flow 70 bbls into lead. Did not bump plug, dart was in drill pipe. Overdisplaced 5 bbls. Lost 262 bbls during cement job and liner setting attempt. Pumped top down squeeze #1 with 93 bbls of 15.3 ppg at liner top (still on losses) Pumped top down squeeze #2 with 51 bbls of 15.8 ppg at liner top, set liner top packer, circed 20 bbls to surface. TOC @ 2824based on CBL @ 10/2/25 6-3/4 hole 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: 3,190 MD / 2,894 TVD Top of PA (BLM) BEL F6 4,835'4,839'4,512'4,516'410/9/25 Open BEL F10 4,985'5,000'4,660'4,674'1510/9/25 Open BEL G 5,056'5,061'4,729'4,734'510/9/25 Open BEL G1 5,079'5,083'4,752'4,756'410/9/25 Open BEL G8 5,346'5,358'5,013'5,024'1210/8/25 Open BEL G10 5,396'5,400'5,061'5,065'410/8/25 Open BEL H1 5,486'5,489'5,149'5,152'310/8/25 Open BEL H1 5,517'5,521'5,179'5,183'410/8/25 Open BEL H2 5,525'5,535'5,187'5,197'1010/8/25 Open BEL H4 5,611'5,631'5,271'5,291'2010/7/25 Closed BEL H4 5,656'5,659'5,315'5,318'310/7/25 Closed BEL H5 5,694'5,697'5,352'5,355'310/7/25 Closed BEL H5 5,702'5,705'5,360'5,363'310/7/25 Closed BEL H9 5,842'5,848'5,497'5,503'610/6/25 Closed BEL H9 5,863'5,867'5,517'5,521'410/6/25 Closed BEL H12 5,976'5,996'5,628'5,647'2010/5/25 Closed BEL H14 6,058'6,068'5,708'5,717'1010/5/25 Closed BEL H14 6,104'6,111'5,752'5,759'710/5/25 Closed BEL H15 6,160'6,189'5,807'5,835'2910/4/25 Closed Notes: 10 Short jt w/ RA tags 5,692, 4,673, 3,654 10 Short joints 5,181, 4,160, 3,145 Deviation Kick off ~500 build to 42 deg @ 1985. Drop to 10-13deg @ 3200 RA 4673 RA 5692 RA 3654 8 PB1 ST @ 3234 PB2 ST @ 4170 7 6 5 4 Updated by CJD 10-29-25 Schematic +PB1/PB2 Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 TOC/Sidetrack Point @ 4,170 MD TD 4,749 MD / TVD 4,227 Sidetrack point @ 3234 TOF @ 3,840 MD BOF @ 4,426 MD TD 4,574 MD / TVD 4,255 PB2 Schematic PB1 Schematic OPEN HOLE / CEMENT DETAIL 6-3/4 OH Pumped 50 bbls LCM Cement 15.8 ppg @ 4,749 MD. Cleaned out cement from 3,996 and unintentionally sidetracked at 4,170 MD. 6-3/4 hole PB1 w/ BHA Lost in Hole DETAIL (8/29/25) No. Depth Item 1 3,840Top of Fish (HWDP) 4,426Bottom of Fish (drilling BHA w/ LWD Sources Am241 @ 4331 & Cs-137 @ 4345) OPEN HOLE / CEMENT DETAIL 6-3/4 OH Pump 700 of cement on top of fish (31 bbls of 15.8 ppg red dye) 6-3/4 hole Updated by CAH 1-22-26 Proposed Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 PBTD 6,172 MD / TVD 5,819 TD 6,266 MD / TVD 5,910 RKB to GL = 19.8 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875Surf 2,862 3-1/2"Prod Lnr 9.2 L-80 Wedge 563 2.9922,7036,266 3-1/2Production Tieback 9.2 L-80 EUE 2.992Surf 2,738 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 2,704YJ Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 3 2,7384 Bullet seal assembly, 2.06 off no-go 4 5,600CIBP 5 5,960CIBP 6 6,050CIBP 7 6,155CIBP 8 6,195CIBP OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 168 bbl (424 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 127 bbls (calculated 127 bbls), spacer & 63 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2 140 bbls (329 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, Lost return flow 70 bbls into lead. Did not bump plug, dart was in drill pipe. Overdisplaced 5 bbls. Lost 262 bbls during cement job and liner setting attempt. Pumped top down squeeze #1 with 93 bbls of 15.3 ppg at liner top (still on losses) Pumped top down squeeze #2 with 51 bbls of 15.8 ppg at liner top, set liner top packer, circed 20 bbls to surface. TOC @ 2824based on CBL @ 10/2/25 6-3/4 hole 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: 3,190 MD / 2,894 TVD Top of PA (BLM) BEL D1 +3,933+3,939+3,624+3,630+6TBD Proposed BEL D4 +4,007+4,012+3,697+3,701+4TBD Proposed BEL D5 +4,034+4,039+3,723+3,728+5TBD Proposed BEL D6 +4,075+4,094+3,763+3,782+19TBD Proposed BEL E1 +4,152+4,155+3,839+3,842+3TBD Proposed BEL E2 +4,217+4,221+3,903+3,907+4TBD Proposed BEL E3 +4,252+4,257+3,938+3,942+4TBD Proposed BEL E5 +4,354+4,359+4,038+4,043+5TBD Proposed BEL E5 +4,374+4,378+4,058+4,061+3TBD Proposed BEL E6 +4,437+4,443+4,120+4,126+6TBD Proposed BEL E6 +4,458+4,461+4,140+4,143+3TBD Proposed BEL F6 +4,735+4,739+4,414+4,418+4TBD Proposed BEL F6 +4,751+4,754+4,430+4,432+3TBD Proposed BEL F6 4,835'4,839'4,512'4,516'410/9/25 Open BEL F7 +4,941+4,947+4,616+4,622+6TBD Proposed BEL F10 4,985'5,000'4,660'4,674'1510/9/25 Open BEL G 5,056'5,061'4,729'4,734'510/9/25 Open BEL G1 5,079'5,083'4,752'4,756'410/9/25 Open BEL G3 +5,127+5,134+4,799+4,805+6TBD Proposed BEL G3 +5,144+5,148+4,815+4,819+4TBD Proposed BEL G8 5,346'5,358'5,013'5,024'1210/8/25 Open BEL G10 5,396'5,400'5,061'5,065'410/8/25 Open BEL H1 5,486'5,489'5,149'5,152'310/8/25 Open BEL H1 5,517'5,521'5,179'5,183'410/8/25 Open BEL H2 5,525'5,535'5,187'5,197'1010/8/25 Open Perfs continued on Page 2 Notes: 10 Short jt w/ RA tags 5,692, 4,673, 3,654 10 Short joints 5,181, 4,160, 3,145 Deviation Kick off ~500 build to 42 deg @ 1985. Drop to 10-13deg @ 3200 RA 4673 RA 5692 RA 3654 8 PB1 ST @ 3234 PB2 ST @ 4170 7 6 5 4 Updated by CAH 1-22-26 Proposed Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 PERFORATION DETAIL (Continued from Page 1) Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status BEL H2 5,525' 5,535' 5,187' 5,197' 10 10/8/25 Open BEL H4 5,611' 5,631' 5,271' 5,291' 20 10/7/25 Closed BEL H4 5,656' 5,659' 5,315' 5,318' 3 10/7/25 Closed BEL H5 5,694' 5,697' 5,352' 5,355' 3 10/7/25 Closed BEL H5 5,702' 5,705' 5,360' 5,363' 3 10/7/25 Closed BEL H9 5,842' 5,848' 5,497' 5,503' 6 10/6/25 Closed BEL H9 5,863' 5,867' 5,517' 5,521' 4 10/6/25 Closed BEL H12 5,976' 5,996' 5,628' 5,647' 20 10/5/25 Closed BEL H14 6,058' 6,068' 5,708' 5,717' 10 10/5/25 Closed BEL H14 6,104' 6,111' 5,752' 5,759' 7 10/5/25 Closed BEL H15 6,160' 6,189' 5,807' 5,835' 29 10/4/25 Closed Proposed Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 TOC/Sidetrack Point @ 4,170 MD TD 4,749 MD / TVD 4,227 Sidetrack point @ 3234 TOF @ 3,840 MD BOF @ 4,426 MD TD 4,574 MD / TVD 4,255 PB2 Schematic PB1 Schematic OPEN HOLE / CEMENT DETAIL 6-3/4 OH Pumped 50 bbls LCM Cement 15.8 ppg @ 4,749 MD. Cleaned out cement from 3,996 and unintentionally sidetracked at 4,170 MD. 6-3/4 hole PB1 w/ BHA Lost in Hole DETAIL (8/29/25) No. Depth Item 1 3,840Top of Fish (HWDP) See BHA details (attached) recovered 92.66 of HWDP 4,426Bottom of Fish (drilling BHA w/ LWD Sources Am241 @ 4331 & Cs-137 @ 4345) OPEN HOLE / CEMENT DETAIL 6-3/4 OH Pump 700 of cement on top of fish (31 bbls of 15.8 ppg red dye) 6-3/4 hole 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: CTCO, N2 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 6,266' N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: 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 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: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA 029657 225-065 50-283-20207-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,738' 10,160psi 2,576' Size 120' 2,839' MD See Attached Schematic 2,980psi 6,890psi 120'120' 2,862' October 29, 2025 Tieback 3-1/2" 6,266' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 234-27CO 802A Same 5,910'3-1/2" ~1576psi 3,563' See Schematic Length LTP; N/A 2,704' MD/2,426' TVD; N/A, N/A 5,910' 5,600' 5,260' Beluga River Sterling-Beluga Gas 16" 7-5/8" See Attached Schematic m n P s 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 9:50 am, Oct 20, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.10.17 15:39:45 - 08'00' Noel Nocas (4361) 325-647 BJM 10/20/25 Dump bail 25' of cement on top of plug at 5600' MD before adding perfs. 10-404 DSR-10/22/25A.Dewhurst 23OCT25 10/23/25 Well Prognosis Well Name: BRU 234-27 API Number: 50-283-20207-00-00 Current Status: New Drill Well Permit to Drill Number: 225-065 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Ryan LeMay (661) 487-0871 (C) Maximum Expected BHP: 1768 psi @ 3842 TVD (Based on 0.46 psi/ft gradient) Max. Potential Surface Pressure: 1576 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.74 psi/ft using 14.23 ppg EMW FIT at the 7-5/8 surface casing Shallowest Potential Perf TVD: MPSP/(0.74-0.05) = 1576 psi / 0.69 = 2285 TVD Top of SBGP (CO 802A): 3190 MD / 2894 TVD Well Status: New Drill Well Initial Completion Currently online at 1028 mcfd / 0 bwpd water / 300 psi FTP (As of 10/14/2025) Hilcorp has completed perforations through currently approved Sundry # 325-578 Brief Well Summary Hilcorp has initiated well completion operations and perforated through the originally submitted and approved intervals per active Sundry # 325-578. This procedure is a program change for Sundry # 325-578 to add additional perforations within the Sterling Beluga Gas Pool / PA. Procedure: 1. MIRU E-line unit. 2. PT lubricator 250 psi low / 2500 psi high 3. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: MD Top MD Base TVD Top TVD Base Footage Top of SBGP 3,190 2,894 Sterling A1 +3,349 +3,373 +3,051 +3,075 +24 Sterling A2 +3,380 +3,384 +3,081 +3,085 +4 Sterling A3 +3,410 +3,438 +3,111 +3,139 +28 Sterling A3 +3,443 +3,454 +3,143 +3,154 +11 Sterling A4B +3,487 +3,507 +3,187 +3,206 +19 Sterling B1 +3,574 +3,578 +3,272 +3,276 +4 Sterling B2 +3,590 +3,610 +3,288 +3,307 +19 Sterling B2 +3,611 +3,632 +3,308 +3,329 +21 Sterling B3 +3,657 +3,664 +3,353 +3,360 +7 Sterling B4 +3,681 +3,689 +3,377 +3,385 +8 Sterling C1 +3,719 +3,727 +3,414 +3,422 +8 Sterling C1 +3,732 +3,741 +3,427 +3,436 +9 Sterling C2 +3,755 +3,769 +3,449 +3,463 +14 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 Well Prognosis Sterling C3 +3,793 +3,807 +3,487 +3,500 +13 Sterling C4 +3,830 +3,857 +3,523 +3,549 +26 Sterling C5 +3,885 +3,892 +3,577 +3,583 +6 Beluga D1 +3,926 +3,928 +3,617 +3,619 +2 Beluga D1 +3,932 +3,939 +3,623 +3,630 +7 Beluga D3 +3,981 +3,988 +3,671 +3,678 +7 Beluga D4 +4,007 +4,012 +3,697 +3,701 +4 Beluga D5 +4,028 +4,030 +3,717 +3,719 +2 Beluga D5 +4,034 +4,039 +3,723 +3,728 +5 Beluga D6 +4,075 +4,094 +3,763 +3,782 +19 Beluga E1 +4,153 +4,155 +3,840 +3,842 +2 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 Contingency Procedure: Coiled Tubing Cleanout 1. If throughout the job any current or proposed zones produce sand and / or water that cannot be depressed and pushed away with nitrogen or pad gas, a coil tubing unit may be rigged up to clean out fill or fluid blown down as necessary. a. MIRU Fox CTU, PT BOPE to 250 psi low / 2500 psi high i. Provide AOGCC 24hrs notice of BOP test. b. Cleanout wellbore fill and / or blowdown well with nitrogen if necessary. Attachments: 1. Current Schematic 2. Proposed Schematic 3. CT Unit BOP Schematic 4. Standard Nitrogen Operations Updated by RPL 10-09-25 Schematic Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 PBTD 6,172 MD / TVD 5,819 TD 6,266 MD / TVD 5,910 RKB to GL = 19.8 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875Surf 2,862 3-1/2"Prod Lnr 9.2 L-80 Wedge 563 2.9922,7036,266 3-1/2Production Tieback 9.2 L-80 EUE 2.992Surf 2,738 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 2,704YJ Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 3 2,7384 Bullet seal assembly, 2.06 off no-go 4 5,600CIBP 5 5,960CIBP 6 6,050CIBP 7 6,155CIBP 8 6,195CIBP OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 168 bbl (424 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 127 bbls (calculated 127 bbls), spacer & 63 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2 140 bbls (329 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, Lost return flow 70 bbls into lead. Did not bump plug, dart was in drill pipe. Overdisplaced 5 bbls. Lost 262 bbls during cement job and liner setting attempt. Pumped top down squeeze #1 with 93 bbls of 15.3 ppg at liner top (still on losses) Pumped top down squeeze #2 with 51 bbls of 15.8 ppg at liner top, set liner top packer, circed 20 bbls to surface. TOC @ 2824based on CBL @ 10/2/25 6-3/4 hole 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: 3,190 MD / 2,894 TVD Top of PA (BLM) BEL F6 4,835'4,839'4,512'4,516'410/9/25 Open BEL F10 4,985'5,000'4,660'4,674'1510/9/25 Open BEL G 5,056'5,061'4,729'4,734'510/9/25 Open BEL G1 5,079'5,083'4,752'4,756'410/9/25 Open BEL G8 5,346'5,358'5,013'5,024'1210/8/25 Open BEL G10 5,396'5,400'5,061'5,065'410/8/25 Open BEL H1 5,486'5,489'5,149'5,152'310/8/25 Open BEL H1 5,517'5,521'5,179'5,183'410/8/25 Open BEL H2 5,525'5,535'5,187'5,197'1010/8/25 Open BEL H4 5,611'5,631'5,271'5,291'2010/7/25 Closed BEL H4 5,656'5,659'5,315'5,318'310/7/25 Closed BEL H5 5,694'5,697'5,352'5,355'310/7/25 Closed BEL H5 5,702'5,705'5,360'5,363'310/7/25 Closed BEL H9 5,842'5,848'5,497'5,503'610/6/25 Closed BEL H9 5,863'5,867'5,517'5,521'410/6/25 Closed BEL H12 5,976'5,996'5,628'5,647'2010/5/25 Closed BEL H14 6,058'6,068'5,708'5,717'1010/5/25 Closed BEL H14 6,104'6,111'5,752'5,759'710/5/25 Closed BEL H15 6,160'6,189'5,807'5,835'2910/4/25 Closed Notes: 10 Short jt w/ RA tags 5,692, 4,673, 3,654 10 Short joints 5,181, 4,160, 3,145 Deviation Kick off ~500 build to 42 deg @ 1985. Drop to 10-13deg @ 3200 RA 4673 RA 5692 RA 3654 8 PB1 ST @ 3234 PB2 ST @ 4170 7 6 5 4 Updated by RPL 10-09-25 Schematic Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 TOC/Sidetrack Point @ 4,170 MD TD 4,749 MD / TVD 4,227 Sidetrack point @ 3234 TOF @ 3,840 MD BOF @ 4,426 MD TD 4,574 MD / TVD 4,255 PB2 Schematic PB1 Schematic OPEN HOLE / CEMENT DETAIL 6-3/4 OH Pumped 50 bbls LCM Cement 15.8 ppg @ 4,749 MD. Cleaned out cement from 3,996 and unintentionally sidetracked at 4,170 MD. 6-3/4 hole PB1 w/ BHA Lost in Hole DETAIL (8/29/25) No. Depth Item 1 3,840Top of Fish (HWDP) See BHA details (attached) recovered 92.66 of HWDP 4,426Bottom of Fish (drilling BHA w/ LWD Sources Am241 @ 4331 & Cs-137 @ 4345) OPEN HOLE / CEMENT DETAIL 6-3/4 OH Pump 700 of cement on top of fish (31 bbls of 15.8 ppg red dye) 6-3/4 hole Updated by RPL 10-14-25 Schematic Proposed Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 PBTD 6,172 MD / TVD 5,819 TD 6,266 MD / TVD 5,910 RKB to GL = 19.8 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875Surf 2,862 3-1/2"Prod Lnr 9.2 L-80 Wedge 563 2.9922,7036,266 3-1/2Production Tieback 9.2 L-80 EUE 2.992Surf 2,738 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 2,704YJ Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 3 2,7384 Bullet seal assembly, 2.06 off no-go 4 5,600CIBP 5 5,960CIBP 6 6,050CIBP 7 6,155CIBP 8 6,195CIBP 6-3/4 hole 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: 3,190 MD / 2,894 TVD Top of PA (BLM) Sterling A1 +3,349+3,373+3,051+3,075+24TBD Proposed Sterling A2 +3,380+3,384+3,081+3,085+4TBD Proposed Sterling A3 +3,410+3,438+3,111+3,139+28TBD Proposed Sterling A3 +3,443+3,454+3,143+3,154+11TBD Proposed Sterling A4B +3,487+3,507+3,187+3,206+19TBD Proposed Sterling B1 +3,574+3,578+3,272+3,276+4TBD Proposed Sterling B2 +3,590+3,610+3,288+3,307+19TBD Proposed Sterling B2 +3,611+3,632+3,308+3,329+21TBD Proposed Sterling B3 +3,657+3,664+3,353+3,360+7TBD Proposed Sterling B4 +3,681+3,689+3,377+3,385+8TBD Proposed Sterling C1 +3,719+3,727+3,414+3,422+8TBD Proposed Sterling C1 +3,732+3,741+3,427+3,436+9TBD Proposed Sterling C2 +3,755+3,769+3,449+3,463+14TBD Proposed Sterling C3 +3,793+3,807+3,487+3,500+13TBD Proposed Sterling C4 +3,830+3,857+3,523+3,549+26TBD Proposed Sterling C5 +3,885+3,892+3,577+3,583+6TBD Proposed Beluga D1 +3,926+3,928+3,617+3,619+2TBD Proposed Beluga D1 +3,932+3,939+3,623+3,630+7TBD Proposed Beluga D3 +3,981+3,988+3,671+3,678+7TBD Proposed Beluga D4 +4,007+4,012+3,697+3,701+4TBD Proposed Beluga D5 +4,028+4,030+3,717+3,719+2TBD Proposed Beluga D5 +4,034+4,039+3,723+3,728+5TBD Proposed Beluga D6 +4,075+4,094+3,763+3,782+19TBD Proposed Beluga E1 +4,153+4,155+3,840+3,842+2TBD Proposed BEL F6 4,835'4,839'4,512'4,516'410/9/25 Open BEL F10 4,985'5,000'4,660'4,674'1510/9/25 Open BEL G 5,056'5,061'4,729'4,734'510/9/25 Open BEL G1 5,079'5,083'4,752'4,756'410/9/25 Open BEL G8 5,346'5,358'5,013'5,024'1210/8/25 Open BEL G10 5,396'5,400'5,061'5,065'410/8/25 Open BEL H1 5,486'5,489'5,149'5,152'310/8/25 Open BEL H1 5,517'5,521'5,179'5,183'410/8/25 Open BEL H2 5,525'5,535'5,187'5,197'1010/8/25 Open BEL H4 5,611'5,631'5,271'5,291'2010/7/25 Closed BEL H4 5,656'5,659'5,315'5,318'310/7/25 Closed BEL H5 5,694'5,697'5,352'5,355'310/7/25 Closed BEL H5 5,702'5,705'5,360'5,363'310/7/25 Closed BEL H9 5,842'5,848'5,497'5,503'610/6/25 Closed BEL H9 5,863'5,867'5,517'5,521'410/6/25 Closed BEL H12 5,976'5,996'5,628'5,647'2010/5/25 Closed BEL H14 6,058'6,068'5,708'5,717'1010/5/25 Closed BEL H14 6,104'6,111'5,752'5,759'710/5/25 Closed RA 4673 RA 5692 RA 3654 8 PB1 ST @ 3234 PB2 ST @ 4170 7 6 5 4 Updated by RPL 10-14-25 Schematic Proposed Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 168 bbl (424 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 127 bbls (calculated 127 bbls), spacer & 63 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2 140 bbls (329 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, Lost return flow 70 bbls into lead. Did not bump plug, dart was in drill pipe. Overdisplaced 5 bbls. Lost 262 bbls during cement job and liner setting attempt. Pumped top down squeeze #1 with 93 bbls of 15.3 ppg at liner top (still on losses) Pumped top down squeeze #2 with 51 bbls of 15.8 ppg at liner top, set liner top packer, circed 20 bbls to surface. TOC @ 2824 based on CBL @ 10/2/25 Notes: 10 Short jt w/ RA tags 5,692, 4,673, 3,654 10 Short joints 5,181, 4,160, 3,145 Deviation Kick off ~500 build to 42 deg @ 1985. Drop to 10-13deg @ 3200 TOC/Sidetrack Point @ 4,170 MD TD 4,749 MD / TVD 4,227 Sidetrack point @ 3234 TOF @ 3,840 MD BOF @ 4,426 MD TD 4,574 MD / TVD 4,255 PB2 Schematic PB1 Schematic OPEN HOLE / CEMENT DETAIL 6-3/4 OH Pumped 50 bbls LCM Cement 15.8 ppg @ 4,749 MD. Cleaned out cement from 3,996 and unintentionally sidetracked at 4,170 MD. 6-3/4 hole PB1 w/ BHA Lost in Hole DETAIL (8/29/25) No. Depth Item 1 3,840Top of Fish (HWDP) See BHA details (attached) recovered 92.66 of HWDP 4,426Bottom of Fish (drilling BHA w/ LWD Sources Am241 @ 4331 & Cs-137 @ 4345) OPEN HOLE / CEMENT DETAIL 6-3/4 OH Pump 700 of cement on top of fish (31 bbls of 15.8 ppg red dye) 6-3/4 hole STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 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:AOGCC Permitting (CED sponsored) To:Brooks, James S (OGC) Subject:RE: [EXTERNAL] Completed Sundry 325-647 BRU 234-27 Change Program - WITHDRAWAL/CANCEL Date:Friday, January 23, 2026 9:27:50 AM Attachments:Sundry_325-647_102325_withdrawn_012326.pdf Hi James, This approved Sundry has been withdrawn as per operator’s request. I have added this to the Wells folder. Thanks, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 From: Donna Ambruz <dambruz@hilcorp.com> Sent: Thursday, January 22, 2026 2:27 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Chad Helgeson <chelgeson@hilcorp.com> Subject: FW: [EXTERNAL] Completed Sundry 325-647 BRU 234-27 Change Program - WITHDRAWAL/CANCEL Please withdraw/cancel the above-referenced sundry. Thank you. Donna Ambruz Operations/Regulatory Tech KEN Asset Team Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 907.777.8305 - Direct dambruz@hilcorp.com From: Christianson, Grace K (OGC) <grace.christianson@alaska.gov> Sent: Thursday, October 23, 2025 1:19 PM To: Abbie Barker <Abbie.Barker@hilcorp.com>; Carrie Janowski <Carrie.Janowski@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com>; Daniel Taylor <dtaylor@hilcorp.com>; Darci Horner CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. <dhorner@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Gordon Piltz - (C) <Gordon.Piltz@hilcorp.com>; Abhijeet Tambe - (C) <abhijeet.tambe@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Josh Allely - (C) <josh.allely@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Tom Fouts <tfouts@hilcorp.com> Subject: [EXTERNAL] Completed Sundry 325-647 BRU 234-27 Change Program Hello, Attached is the completed Sundry for BRU 234-27. Thank you, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska, and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use, or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it without first saving or forwarding it, and so that the AOGCC is aware of the mistake in sending it to you, contact Grace Christianson at (907-793-1230) or (grace.christianson@alaska.gov). 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. 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: 11/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251107 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 212-26 50283201820000 220058 9/20/2025 AK E-LINE Perf BRU 212-35 50283100270000 162018 10/12/2025 AK E-LINE TubingPuncher BRU 234-27 50283202070000 225065 7/17/1905 AK E-LINE CBL-02-October BRU 234-27 50283202070000 225065 10/6/2025 AK E-LINE CIBP/Perf GP 42-23RD 50733201140100 195145 10/26/2025 AK E-LINE TubingPunch GP ST 42-23RD 50733201140100 195145 10/9/2025 AK E-LINE JetCut MPL-54 50029236070000 218066 10/16/2025 READ CaliperSurvey MPL-57 50029236090000 218072 10/27/2025 READ CaliperSurvey MPU B-21 50029215350000 186023 10/25/2025 AK E-LINE RBP NCIU A-07 50883200270000 169058 10/10/2025 AK E-LINE JetCut NCIU A-17A 50883201880100 225089 10/10/2025 AK E-LINE Perf NCIU A-17A 50883201880100 225089 10/14/2025 AK E-LINE Perf PBU 01-10A 50029201690200 225055 8/29/2025 HALLIBURTON RBT PBU 05-11A 50029202520100 196097 10/11/2025 BAKER RPM PBU 05-31B 50029221590200 210085 10/14/2025 BAKER SPN PBU F-06B 50029200970200 225054 9/27/2025 BAKER MRPM PBU F-42A 50029221080100 207093 10/27/2025 BAKER RPM PBU H-07B 50029202420200 225064 9/29/2025 BAKER MRPM PBU L5-27 50029236270000 219046 10/7/2025 BAKER SPN PBU Q-06A 50029203460100 198090 8/22/2025 YELLOWJACKET SCBL SD-06 50133205820000 208160 7/23/2025 YELLOWJACKET GPT-PERF SRU 222-33 50133207150000 223100 7/15/2025 YELLOWJACKET PERF Please include current contact information if different from above. T41066 T41067 T41068 T41068 T41069 T41069 T41070 T41071 T41072 T41073 T41074 T41074 T41075 T41076 T41077 T41078 T41079 T41080 T41081 T41082 T41083 T41084 BRU 234-27 50283202070000 225065 7/17/1905 AK E-LINE CBL-02-October BRU 234-27 50283202070000 225065 10/6/2025 AK E-LINE CIBP/Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.07 15:03:51 -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: CTCO, N2 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 6,266' N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: 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 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: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA 029657 225-065 50-283-20207-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,738' 10,160psi 2,576' Size 120' 2,839' MD See Attached Schematic 2,980psi 6,890psi 120'120' 2,862' October 29, 2025 Tieback 3-1/2" 6,266' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 234-27CO 802A Same 5,910'3-1/2" ~1576psi 3,563' See Schematic Length LTP; N/A 2,704' MD/2,426' TVD; N/A, N/A 5,910' 5,600' 5,260' Beluga River Sterling-Beluga Gas 16" 7-5/8" See Attached Schematic m n P s 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 9:50 am, Oct 20, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.10.17 15:39:45 - 08'00' Noel Nocas (4361) 325-647 BJM 10/20/25 Dump bail 25' of cement on top of plug at 5600' MD before adding perfs. 10-404 DSR-10/22/25A.Dewhurst 23OCT25 10/23/25 Well Prognosis Well Name: BRU 234-27 API Number: 50-283-20207-00-00 Current Status: New Drill Well Permit to Drill Number: 225-065 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Ryan LeMay (661) 487-0871 (C) Maximum Expected BHP: 1768 psi @ 3842 TVD (Based on 0.46 psi/ft gradient) Max. Potential Surface Pressure: 1576 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.74 psi/ft using 14.23 ppg EMW FIT at the 7-5/8 surface casing Shallowest Potential Perf TVD: MPSP/(0.74-0.05) = 1576 psi / 0.69 = 2285 TVD Top of SBGP (CO 802A): 3190 MD / 2894 TVD Well Status: New Drill Well Initial Completion Currently online at 1028 mcfd / 0 bwpd water / 300 psi FTP (As of 10/14/2025) Hilcorp has completed perforations through currently approved Sundry # 325-578 Brief Well Summary Hilcorp has initiated well completion operations and perforated through the originally submitted and approved intervals per active Sundry # 325-578. This procedure is a program change for Sundry # 325-578 to add additional perforations within the Sterling Beluga Gas Pool / PA. Procedure: 1. MIRU E-line unit. 2. PT lubricator 250 psi low / 2500 psi high 3. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: MD Top MD Base TVD Top TVD Base Footage Top of SBGP 3,190 2,894 Sterling A1 +3,349 +3,373 +3,051 +3,075 +24 Sterling A2 +3,380 +3,384 +3,081 +3,085 +4 Sterling A3 +3,410 +3,438 +3,111 +3,139 +28 Sterling A3 +3,443 +3,454 +3,143 +3,154 +11 Sterling A4B +3,487 +3,507 +3,187 +3,206 +19 Sterling B1 +3,574 +3,578 +3,272 +3,276 +4 Sterling B2 +3,590 +3,610 +3,288 +3,307 +19 Sterling B2 +3,611 +3,632 +3,308 +3,329 +21 Sterling B3 +3,657 +3,664 +3,353 +3,360 +7 Sterling B4 +3,681 +3,689 +3,377 +3,385 +8 Sterling C1 +3,719 +3,727 +3,414 +3,422 +8 Sterling C1 +3,732 +3,741 +3,427 +3,436 +9 Sterling C2 +3,755 +3,769 +3,449 +3,463 +14 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 Well Prognosis Sterling C3 +3,793 +3,807 +3,487 +3,500 +13 Sterling C4 +3,830 +3,857 +3,523 +3,549 +26 Sterling C5 +3,885 +3,892 +3,577 +3,583 +6 Beluga D1 +3,926 +3,928 +3,617 +3,619 +2 Beluga D1 +3,932 +3,939 +3,623 +3,630 +7 Beluga D3 +3,981 +3,988 +3,671 +3,678 +7 Beluga D4 +4,007 +4,012 +3,697 +3,701 +4 Beluga D5 +4,028 +4,030 +3,717 +3,719 +2 Beluga D5 +4,034 +4,039 +3,723 +3,728 +5 Beluga D6 +4,075 +4,094 +3,763 +3,782 +19 Beluga E1 +4,153 +4,155 +3,840 +3,842 +2 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 Contingency Procedure: Coiled Tubing Cleanout 1. If throughout the job any current or proposed zones produce sand and / or water that cannot be depressed and pushed away with nitrogen or pad gas, a coil tubing unit may be rigged up to clean out fill or fluid blown down as necessary. a. MIRU Fox CTU, PT BOPE to 250 psi low / 2500 psi high i. Provide AOGCC 24hrs notice of BOP test. b. Cleanout wellbore fill and / or blowdown well with nitrogen if necessary. Attachments: 1. Current Schematic 2. Proposed Schematic 3. CT Unit BOP Schematic 4. Standard Nitrogen Operations Updated by RPL 10-09-25 Schematic Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 PBTD 6,172 MD / TVD 5,819 TD 6,266 MD / TVD 5,910 RKB to GL = 19.8 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875Surf 2,862 3-1/2"Prod Lnr 9.2 L-80 Wedge 563 2.9922,7036,266 3-1/2Production Tieback 9.2 L-80 EUE 2.992Surf 2,738 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 2,704YJ Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 3 2,7384 Bullet seal assembly, 2.06 off no-go 4 5,600CIBP 5 5,960CIBP 6 6,050CIBP 7 6,155CIBP 8 6,195CIBP OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 168 bbl (424 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 127 bbls (calculated 127 bbls), spacer & 63 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2 140 bbls (329 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, Lost return flow 70 bbls into lead. Did not bump plug, dart was in drill pipe. Overdisplaced 5 bbls. Lost 262 bbls during cement job and liner setting attempt. Pumped top down squeeze #1 with 93 bbls of 15.3 ppg at liner top (still on losses) Pumped top down squeeze #2 with 51 bbls of 15.8 ppg at liner top, set liner top packer, circed 20 bbls to surface. TOC @ 2824based on CBL @ 10/2/25 6-3/4 hole 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: 3,190 MD / 2,894 TVD Top of PA (BLM) BEL F6 4,835'4,839'4,512'4,516'410/9/25 Open BEL F10 4,985'5,000'4,660'4,674'1510/9/25 Open BEL G 5,056'5,061'4,729'4,734'510/9/25 Open BEL G1 5,079'5,083'4,752'4,756'410/9/25 Open BEL G8 5,346'5,358'5,013'5,024'1210/8/25 Open BEL G10 5,396'5,400'5,061'5,065'410/8/25 Open BEL H1 5,486'5,489'5,149'5,152'310/8/25 Open BEL H1 5,517'5,521'5,179'5,183'410/8/25 Open BEL H2 5,525'5,535'5,187'5,197'1010/8/25 Open BEL H4 5,611'5,631'5,271'5,291'2010/7/25 Closed BEL H4 5,656'5,659'5,315'5,318'310/7/25 Closed BEL H5 5,694'5,697'5,352'5,355'310/7/25 Closed BEL H5 5,702'5,705'5,360'5,363'310/7/25 Closed BEL H9 5,842'5,848'5,497'5,503'610/6/25 Closed BEL H9 5,863'5,867'5,517'5,521'410/6/25 Closed BEL H12 5,976'5,996'5,628'5,647'2010/5/25 Closed BEL H14 6,058'6,068'5,708'5,717'1010/5/25 Closed BEL H14 6,104'6,111'5,752'5,759'710/5/25 Closed BEL H15 6,160'6,189'5,807'5,835'2910/4/25 Closed Notes: 10 Short jt w/ RA tags 5,692, 4,673, 3,654 10 Short joints 5,181, 4,160, 3,145 Deviation Kick off ~500 build to 42 deg @ 1985. Drop to 10-13deg @ 3200 RA 4673 RA 5692 RA 3654 8 PB1 ST @ 3234 PB2 ST @ 4170 7 6 5 4 Updated by RPL 10-09-25 Schematic Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 TOC/Sidetrack Point @ 4,170 MD TD 4,749 MD / TVD 4,227 Sidetrack point @ 3234 TOF @ 3,840 MD BOF @ 4,426 MD TD 4,574 MD / TVD 4,255 PB2 Schematic PB1 Schematic OPEN HOLE / CEMENT DETAIL 6-3/4 OH Pumped 50 bbls LCM Cement 15.8 ppg @ 4,749 MD. Cleaned out cement from 3,996 and unintentionally sidetracked at 4,170 MD. 6-3/4 hole PB1 w/ BHA Lost in Hole DETAIL (8/29/25) No. Depth Item 1 3,840Top of Fish (HWDP) See BHA details (attached) recovered 92.66 of HWDP 4,426Bottom of Fish (drilling BHA w/ LWD Sources Am241 @ 4331 & Cs-137 @ 4345) OPEN HOLE / CEMENT DETAIL 6-3/4 OH Pump 700 of cement on top of fish (31 bbls of 15.8 ppg red dye) 6-3/4 hole Updated by RPL 10-14-25 Schematic Proposed Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 PBTD 6,172 MD / TVD 5,819 TD 6,266 MD / TVD 5,910 RKB to GL = 19.8 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875Surf 2,862 3-1/2"Prod Lnr 9.2 L-80 Wedge 563 2.9922,7036,266 3-1/2Production Tieback 9.2 L-80 EUE 2.992Surf 2,738 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 2,704YJ Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 3 2,7384 Bullet seal assembly, 2.06 off no-go 4 5,600CIBP 5 5,960CIBP 6 6,050CIBP 7 6,155CIBP 8 6,195CIBP 6-3/4 hole 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: 3,190 MD / 2,894 TVD Top of PA (BLM) Sterling A1 +3,349+3,373+3,051+3,075+24TBD Proposed Sterling A2 +3,380+3,384+3,081+3,085+4TBD Proposed Sterling A3 +3,410+3,438+3,111+3,139+28TBD Proposed Sterling A3 +3,443+3,454+3,143+3,154+11TBD Proposed Sterling A4B +3,487+3,507+3,187+3,206+19TBD Proposed Sterling B1 +3,574+3,578+3,272+3,276+4TBD Proposed Sterling B2 +3,590+3,610+3,288+3,307+19TBD Proposed Sterling B2 +3,611+3,632+3,308+3,329+21TBD Proposed Sterling B3 +3,657+3,664+3,353+3,360+7TBD Proposed Sterling B4 +3,681+3,689+3,377+3,385+8TBD Proposed Sterling C1 +3,719+3,727+3,414+3,422+8TBD Proposed Sterling C1 +3,732+3,741+3,427+3,436+9TBD Proposed Sterling C2 +3,755+3,769+3,449+3,463+14TBD Proposed Sterling C3 +3,793+3,807+3,487+3,500+13TBD Proposed Sterling C4 +3,830+3,857+3,523+3,549+26TBD Proposed Sterling C5 +3,885+3,892+3,577+3,583+6TBD Proposed Beluga D1 +3,926+3,928+3,617+3,619+2TBD Proposed Beluga D1 +3,932+3,939+3,623+3,630+7TBD Proposed Beluga D3 +3,981+3,988+3,671+3,678+7TBD Proposed Beluga D4 +4,007+4,012+3,697+3,701+4TBD Proposed Beluga D5 +4,028+4,030+3,717+3,719+2TBD Proposed Beluga D5 +4,034+4,039+3,723+3,728+5TBD Proposed Beluga D6 +4,075+4,094+3,763+3,782+19TBD Proposed Beluga E1 +4,153+4,155+3,840+3,842+2TBD Proposed BEL F6 4,835'4,839'4,512'4,516'410/9/25 Open BEL F10 4,985'5,000'4,660'4,674'1510/9/25 Open BEL G 5,056'5,061'4,729'4,734'510/9/25 Open BEL G1 5,079'5,083'4,752'4,756'410/9/25 Open BEL G8 5,346'5,358'5,013'5,024'1210/8/25 Open BEL G10 5,396'5,400'5,061'5,065'410/8/25 Open BEL H1 5,486'5,489'5,149'5,152'310/8/25 Open BEL H1 5,517'5,521'5,179'5,183'410/8/25 Open BEL H2 5,525'5,535'5,187'5,197'1010/8/25 Open BEL H4 5,611'5,631'5,271'5,291'2010/7/25 Closed BEL H4 5,656'5,659'5,315'5,318'310/7/25 Closed BEL H5 5,694'5,697'5,352'5,355'310/7/25 Closed BEL H5 5,702'5,705'5,360'5,363'310/7/25 Closed BEL H9 5,842'5,848'5,497'5,503'610/6/25 Closed BEL H9 5,863'5,867'5,517'5,521'410/6/25 Closed BEL H12 5,976'5,996'5,628'5,647'2010/5/25 Closed BEL H14 6,058'6,068'5,708'5,717'1010/5/25 Closed BEL H14 6,104'6,111'5,752'5,759'710/5/25 Closed RA 4673 RA 5692 RA 3654 8 PB1 ST @ 3234 PB2 ST @ 4170 7 6 5 4 Updated by RPL 10-14-25 Schematic Proposed Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 168 bbl (424 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 127 bbls (calculated 127 bbls), spacer & 63 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2 140 bbls (329 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, Lost return flow 70 bbls into lead. Did not bump plug, dart was in drill pipe. Overdisplaced 5 bbls. Lost 262 bbls during cement job and liner setting attempt. Pumped top down squeeze #1 with 93 bbls of 15.3 ppg at liner top (still on losses) Pumped top down squeeze #2 with 51 bbls of 15.8 ppg at liner top, set liner top packer, circed 20 bbls to surface. TOC @ 2824 based on CBL @ 10/2/25 Notes: 10 Short jt w/ RA tags 5,692, 4,673, 3,654 10 Short joints 5,181, 4,160, 3,145 Deviation Kick off ~500 build to 42 deg @ 1985. Drop to 10-13deg @ 3200 TOC/Sidetrack Point @ 4,170 MD TD 4,749 MD / TVD 4,227 Sidetrack point @ 3234 TOF @ 3,840 MD BOF @ 4,426 MD TD 4,574 MD / TVD 4,255 PB2 Schematic PB1 Schematic OPEN HOLE / CEMENT DETAIL 6-3/4 OH Pumped 50 bbls LCM Cement 15.8 ppg @ 4,749 MD. Cleaned out cement from 3,996 and unintentionally sidetracked at 4,170 MD. 6-3/4 hole PB1 w/ BHA Lost in Hole DETAIL (8/29/25) No. Depth Item 1 3,840Top of Fish (HWDP) See BHA details (attached) recovered 92.66 of HWDP 4,426Bottom of Fish (drilling BHA w/ LWD Sources Am241 @ 4331 & Cs-137 @ 4345) OPEN HOLE / CEMENT DETAIL 6-3/4 OH Pump 700 of cement on top of fish (31 bbls of 15.8 ppg red dye) 6-3/4 hole STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 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:Chad Helgeson To:McLellan, Bryan J (OGC) Cc:James Ostroot - (C); Donna Ambruz; Juanita Lovett Subject:BRU 234-27 (PTD# 225-065) Sundry # 325-578 Cement bond log Date:Thursday, October 2, 2025 5:39:55 PM Attachments:BRU 234-27_CBL_2-OCT-25 (5682) FIELD PRINT.pdf Bryan, Please find attached the Cement bond log for BRU 234-27. The cement top jobs seemed to work well. We have good cement throughout the well and definitely good cement up to the liner lap. We do not think any remedial cement work is necessary to execute proposed perfs. Current perf interval (4217-6189) Please let us know if you approve us to process with perforations on BRU 234-27. Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C 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 herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________BELUGA RIV UNIT 234-27 JBR 11/20/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 Good Test Test Results TEST DATA Rig Rep:Ken PorterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley Rig Owner/Rig No.:Hilcorp 147 PTD#:2250650 DATE:9/4/2025 Type Operation:DRILL Annular: 250/3000Type Test:BIWKLY Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopAGE250915152346 Inspector Adam Earl Inspector Insp Source Related Insp No:BOPOP000012153 INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 4.5 MASP: 2071 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 13 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 2 7/8 x 5"P #2 Rams 1 blind P #3 Rams 1 2 7/8 x 5"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8"P HCR Valves 2 3 1/8" & 2 1/1 P Kill Line Valves 1 2 1/16"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3050 Pressure After Closure P1700 200 PSI Attained P28 Full Pressure Attained P96 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P4 @ 2662 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P15 #1 Rams P4 #2 Rams P4 #3 Rams P4 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2       Gluyas, Gavin R (OGQ From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Thursday, August 28, 2025 7:28 AM To: McLellan, Bryan J (OGQ Subject: RE: [EXTERNAL] Re: PTD 225-065 Hilcorp Well BRU 234-27 We engaged the fish yesterday afternoon and jarred for 13 hours with zero movement. We are working on releasing from the fish this morning. I'd like to set a long abandonment/kickoff plug. Do you have an idea of the minimum length plug the AOGCC will accept for abandonment? We will pump one longer than the minimum but if we tag the top and start time drilling, I want to have a minimum length that we need to leave in place if the time drilling/kickoff takes up more footage than anticipated. I'll also workwith HaRiburton to get the federal approval for abandoningthe sources and w/the BLM as well, as this is a BLM regulated well. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Wednesday, August 27, 2025 10:13 AM To: McLellan, Bryan J (OGQ <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] Re: PTD 225-065 Hilcorp Well BRU 234-27 We are at surface now making up the fishing BHA. It took a little longer than expected to mobilize the support crews and get backed off from the fish. Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, August 27, 2025 9:50 AM To: Nathan Sperry <Nathan.Sperrv@hilcorp.com> Subject: [EXTERNAL] Re: PTD 225-065 Hilcorp Well BRU 234-27 ' CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Did you recover the fish? Sent from my Phone On Aug 26, 2025, at 9:47 AM, Nathan Sperry <Nathan.Snerry(&hilcorn com> wrote: ICAUTION: 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. Bryan, Just following upon our phone call. We are stuck in our 6-3/4" interval with a triple combo BHA. Our bit depth is 4,423' MD and our hole depth is 4574' MD. We were drilling ahead with lost circulation when the torque became erratic. We began backreaming out of the hole to get above the lost circulation zone when we became stuck. We jarred for —6 hrs this morning and made less than V of progress. We mobilized a fisherman and a -line crew to the west side early this morning and we plan to backoff above the BHA, makeup a fishing BHA, RIH, engage the fish, and continue jarring. Nate Sperry Drilling Engineer HilcorpAlaska, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Gluyas, Gavin R (OGQ From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Thursday, August 28, 2025 12:41 PM To: McLellan, Bryan J (OGC) Cc: Sean McLaughlin; Cody Dinger Subject: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish Attachments: BRU 234-27 Surveys.pdf; BRU 243-27 Lost in Hole BHA.pdf, BRU 234-27 Proposed Schematic BHA 8-28-25.pdf ICAUTION: 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. Bryan, While drilling ahead with total losses at 4,574' MD, drilling became very difficult (torque, sticking). We began backreaming out of the hole and made it to 4,426' where the BHA became stuck. We were able to pump but did not have any returns at surface and the well was taking —5 bbls/hr static losses from surface. We jarred on the fish for —6 hrs before backing off and tripping for a fishing assembly. We ran a fishing assembly yesterday, engaged the fish at 1330 hrs, and jarred for —13 hrs with zero movement in either direction. I propose to abandon our fish in the hole by pumping a 31 bbls, 700 ft long 15.8ppg balanced cement plug (with red dye) on top of the fish and sidetracking off the top of it. Our hole depth is 4,574' MD. The bottom of the fish is 4,426' and the top of the fish is 3,840'. The fish is 586' long. We will run in the hole with our kickoff assembly, tag the TOC, orient, and sidetrack off it. We will leave a minimum of 200' MD of cement on top of the fish. If we are not departed from the wellbore by 3,640' MD, we will stop sidetracking and will contact you to discuss a forward plan. Halliburton is working on an updated directional plan and I should have something to share in a couple of hours. The uppermost source is 485' below the top of the fish. If we kickoff 200' above the top of the fish, we would have 60' of separation from the uppermost source as we drill by. If you approve of our plan, we will follow up with a 10-403. FYI I'm cc'ing Sean McLaughlin as I will be out of the office starting Friday afternoon and Sean will be covering through Monday. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC The information contained in this email message is confidential and maybe 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. Gluyas, Gavin R (OGQ From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Thursday, August 28, 2025 1:09 PM To: McLellan, Bryan J (OGC) Cc: Sean McLaughlin; Cody Dinger Subject: RE: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish Attachments: [EXTERNAL] FW: Source Depths '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. Bryan, Attached is the e-mailfrom Halliburton statingthat they received verbal approvalfrom the NRC to abandon the sources. I will provide them details of our abandonment plan. Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Nathan Sperry Sent: Thursday, August 28, 2025 12:41 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish Bryan, While drilling ahead with total losses at 4,574' MD, drilling became very difficult (torque, sticking). We began backreaming out of the hole and made it to 4,426' where the BHA became stuck. We were able to pump but did not have any returns at surface and the well was taking —5 bbls/hr static losses from surface. We jarred on the fish for —6 hrs before backing off and tripping for a fishing assembly. We ran a fishing assembly yesterday, engaged the fish at 1330 hrs, and jarred for —13 hrs with zero movement in either direction. I propose to abandon our fish in the hole by pumping a 31 bbls, 700 ft long 15.8ppg balanced cement plug (with red dye) on top of the fish and sidetracking off the top of it. Our hole depth is 4,574' MD. The bottom of the fish is 4,426' and the top of the fish is 3,840'. The fish is 586' long. We will run in the hole with our kickoff assembly, tag the TOC, orient, and sidetrack off it. We will leave a minimum of 200' MD of cement on top of the fish. If we are not departed from the wellbore by 3,640' MD, we will stop sidetracking and will contact you to discuss a forward plan. Halliburton is working on an updated directional plan and I should have something to share in a couple of hours. The uppermost source is 485' below the top of the fish. If we kickoff 200' above the top of the fish, we would have 60' of separation from the uppermost source as we drill by. If you approve of our plan, we will follow up with a 10-403. FYI I'm cc'ing Sean McLaughlin as I will be out of the office starting Friday afternoon and Sean will be covering through Monday. Regards, Nate Sperry Drilling Engineer HilcorpAlaska, LLC 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. Gluyas, Gavin R (OGC) From Sent: To: Cc: Subject: Attachments Importance: Sure thing, see attached. Nate Sperry Drilling Engineer Hilcorp Alaska, LLC Nathan Sperry <Nathan.Sperry@hilcorp.com> Thursday, August 28, 2025 3:22 PM McLellan, Bryan J (OGC); Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC); Roby, David S (OGC); Starns, Ted C (OGC) Cody Dinger; Sean McLaughlin RE: [EXTERNAL] Fwd: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish BRU 234-27_OHL_W_FLAGS.pdf High From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, August 28, 2025 2:20 PM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Nathan Sperry <Natha n.Sperry@hilcorp.com> Subject: [EXTERNAL] Fwd: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish ICAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Nathan, can you send OH logs and indicate sands and gas zones? Thx Bryan Sent from my Phone Begin forwarded message: From: Nathan Sperry <Nathan.S e[Lrry(o)hilcorn com> Date: August 28, 2025 at 12:41:30 PM AKDT To: "McLellan, Bryan J (OGC)" <bryan.mclellan@)alaska.gov> Cc: Sean McLaughlin <Sean.Mclaughlin(ahilcorn com>, Cody Dinger <cdingerPhilcorp.com> Subject: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish ICAUTION: 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. Bryan, While drilling ahead with total losses at 4,574' MD, drilling became very difficult (torque, sticking). We began backreaming out of the hole and made it to 4,426' where the BHA became stuck. We were able to pump but did not have any returns at surface and the well was taking —5 bbls/hr static losses from surface. We jarred on the fish for —6 hrs before backing off and tripping for a fishing assembly. We ran a fishing assembly yesterday, engaged the fish at 1330 hrs, and jarred for-13 hrs with zero movement in either direction. I propose to abandon our fish in the hole by pumping a 31 bbls, 700 ft long 15.8ppg balanced cement plug (with red dye) on top of the fish and sidetracking off the top of it. Our hole depth is 4,574' MD. The bottom of the fish is 4,426' and the top of the fish is 3,840'. The fish is 586' long. We will run in the hole with our kickoff assembly, tag the TOC, orient, and sidetrack off it. We will leave a minimum of 200' MD of cement on top of the fish. If we are not departed from the wellbore by 3,640' MD, we will stop sidetracking and will contact you to discuss a forward plan. Halliburton is working on an updated directional plan and I should have something to share in a couple of hours. The uppermost source is 485' below the top of the fish. If we kickoff 200' above the top of the fish, we would have 60' of separation from the uppermost source as we drill by. If you approve of our plan, we will follow up with a 10-403. FYI I'm cc'ing Sean McLaughlin as I will be out of the office starting Friday afternoon and Sean will be covering through Monday. Regards, Nate Sperry Drilling Engineer HilcorpALaska, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and maybe 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. Gluyas, Gavin R (OGQ From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Thursday, August 28, 2025 4:25 PM To: McLellan, Bryan J (OGC) Subject: RE: [EXTERNAL] Fwd: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish Very slight but that could be to formations above the fish as well. Tagging TOC would be a positive indicator for the top of the plug. It's unlikely that the bottom would dropout without the top of the plug following it downhole. I'm working on getting a directional pdf from Halliburton w/the AC scan. Will send as soon as I have it. Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, August 28, 2025 4:23 PM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Subject: RE: [EXTERNAL] Fwd: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish ICAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Nathan, Is the well still on static losses? Will cement be lost through the BHA to TD? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Brya n.mcleRanCdalaska.gov +1 (907) 250-9193 I From: Nathan Sperry <Nathan.Soerrv@hilcoro.com> Sent: Thursday, August 28, 2025 3:22 PM To: McLellan, Bryan J (OGC) <brvan.mcIellan@alaska.Rov>; Davies, Stephen F (OGC) <steve.davies@alaska.eov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov> Cc: Cody Dinger <cdinger@hilcoro.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] Fwd: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish Importance: High Sure thing, see attached. Nate Sperry Drilling Engineer HilcorpAlaska, LLC From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, August 28, 2025 2:20 PM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.robv@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Nathan Sperry <Nathan.Sperrv@hilcorp.com> Subject: [EXTERNAL] Fwd: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish ICAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Nathan, can you send OH logs and indicate sands and gas zones? Thx Bryan Sent from my iPhone Begin forwarded message: From: Nathan Sperry <Nathan.SperryCa)hilcorp.com> Date: August 28, 2025 at 12:41:30 PM AKDT To: "McLellan, Bryan J (OGC)" <bryan.mclellanCabalaska.gov> Cc: Sean McLaughlin <Sean.Mclaughlin(@hilcorp.com>, Cody Dinger < lingerPhilr Im.> Subject: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish ICAUTION: 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. Bryan, While drilling ahead with total losses at 4,574' MD, drilling became very difficult (torque, sticking). We began backreaming out of the hole and made it to 4,426' where the BHA became stuck. We were able to pump but did not have any returns at surface and the well was taking —5 bbls/hr static losses from surface. We jarred on the fish for —6 hrs before backing off and tripping for a fishing assembly. We ran a fishing assembly yesterday, engaged the fish at 1330 hrs, and jarred for-13 hrs with zero movement in either direction. I propose to abandon our fish in the hole by pumping a 31 bbls, 700 ft long 15.8ppg balanced cement plug (with red dye) on top of the fish and sidetracking off the top of it. Our hole depth is 4,574' MD. The bottom of the fish is 4,426' and the top of the fish is 3,840'. The fish is 586' long. We will run in the hole with our kickoff assembly, tag the TOC, orient, and sidetrack off it. We will leave a minimum of 200' MD of cement on top of the fish. If we are not departed from the weltbore by 3,640' MD, we will stop sidetracking and will contact you to discuss a forward plan. HaRiburton is working on an updated directional plan and I should have something to share in a couple of hours. The uppermost source is 485' below the top of the fish. If we kickoff 200' above the top of the fish, we would have 60' of separation from the uppermost source as we drill by. If you approve of our plan, we will follow up with a 10-403. FYI I'm cc'ing Sean McLaughlin as I will be out of the office starting Friday afternoon and Sean will be covering through Monday. Regards, Nate Sperry Drilling Engineer HilcorpALaska, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. while all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 senders 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. Gluyas, Gavin R (OGC) From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Thursday, August 28, 2025 5:26 PM To: McLellan, Bryan J (OGC) Cc: Sean McLaughlin; Cody Dinger Subject: Re: [EXTERNAL] RE: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish AC looks good. The separation factor is over 6 at that depth On Aug 28, 2025, at 4:16 PM, McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> wrote: ICAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Nathan, How does the anti -collision scan look at the point you will drill by the radioactive source. Do the elipses of uncertainty overlap at that point? If so, you should set a shallower minimum so you can have certainty about a minimum distance between wellbores. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Brya n.mcleRan(a)alaska.gov +1 (907) 250-9193 <i m age001.j pg> From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Thursday, August 28, 2025 1:09 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: RE: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish ICAUTION: 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. Bryan, Attached is the e-mail from Halliburton stating that they received verbal approval from the NRC to abandon the sources. I will provide them details of our abandonment plan. Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Nathan Sperry Sent: Thursday, August 28, 2025 12:41 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish Bryan, While drilling ahead with total losses at 4,574' MD, drilling became very difficult (torque, sticking). We began backreaming out of the hole and made it to 4,426' where the BHA became stuck. We were able to pump but did not have any returns at surface and the well was taking —5 bbls/hr static losses from surface. We jarred on the fish for —6 hrs before backing off and tripping for a fishing assembly. We ran a fishing assembly yesterday, engaged the fish at 1330 hrs, and jarred for-13 hrs with zero movement in either direction. I propose to abandon our fish in the hole by pumping a 31 bbls, 700 ft long 15.8ppg balanced cement plug (with red dye) on top of the fish and sidetracking off the top of it. Our hole depth is 4,574' MD. The bottom of the fish is 4,426' and the top of the fish is 3,840'. The fish is 586' long. We will run in the hole with our kickoff assembly, tag the TOC, orient, and sidetrack off it. We will leave a minimum of 200' MD of cement on top of the fish. If we are not departed from the wellbore by 3,640' MD, we will stop sidetracking and will contact you to discuss a forward plan. Halliburton is working on an updated directional plan and I should have something to share in a couple of hours. The uppermost source is 485' below the top of the fish. If we kickoff 200' above the top of the fish, we would have 60' of separation from the uppermost source as we drill by. If you approve of our plan, we will follow up with a 10-403. FYI I'm cc'ing Sean McLaughlin as I will be out of the office starting Friday afternoon and Sean will be covering through Monday. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC 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 senders phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as It considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Gluyas, Gavin R (OGQ From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Thursday, August 28, 2025 9:05 PM To: McLellan, Bryan J (OGC); Dewhurst, Andrew D (OGC) Cc: Sean McLaughlin; Cody Dinger Subject: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish Attachments: BRU 234-27 wp06_proposal report.pdf; BRU 234-27 wp06.txt '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. Bryan, Here is our sidetrack plan assumingwe kick off 200' above the top of the fish. Our goal is to kickoff higher. Due to weather, our cementers were unable to fly over today. The rig is on standby and will be ready to cement as soon as the cementers are able to fly over in the morning. Please let me know if you need more information, would like to discuss altering the plan, or intend to approve as proposed. Hilcorp will follow up with a 10-403 once we have agreement on the abandonment plan. Thankyou, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC 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. Gluyas, Gavin R (OGQ From: McLellan, Bryan J (OGQ Sent: Thursday, August 28, 2025 9:17 PM To: Nathan Sperry Subject: Re: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish The plan sounds good. Verbal approval is granted. Follow up with sundry. Regards Bryan Sent from my Phone On Aug 28, 2025, at 9:05 PM, Nathan Sperry <Nathan.Sperry@hilcorp.com> wrote: ICAUTION: 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. Bryan, Here is our sidetrack plan assuming we kickoff 200' above the top of the fish. Our goal is to kickoff higher. Due to weather, our cementers were unable to fly over today. The rig is on standby and will be ready to cement as soon as the cementers are able to fly over in the morning. Please let me know if you need more information, would like to discuss altering the plan, or intend to approve as proposed. Hilcorp will follow up with a 10-403 once we have agreement on the abandonment plan. Thankyou, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC The information contained in this email message is confidential and maybe 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. <BRU 234-27 wp06_proposal report.pdf> <BRU 234-27 wp06.txt> Gluyas, Gavin R (OGQ From: McLellan, Bryan J (OGQ Sent: Thursday, August 28, 2025 9:17 PM To: Nathan Sperry Subject: Re: PTD 225-065 Hilcorp Well BRU 234-27: abandon wellbore with fish The plan sounds good. Verbal approval is granted. Follow up with sundry. Regards Bryan Sent from my Phone On Aug 28, 2025, at 9:05 PM, Nathan Sperry <Nathan.Sperry@hilcorp.com> wrote: ICAUTION: 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. Bryan, Here is our sidetrack plan assuming we kickoff 200' above the top of the fish. Our goal is to kickoff higher. Due to weather, our cementers were unable to fly over today. The rig is on standby and will be ready to cement as soon as the cementers are able to fly over in the morning. Please let me know if you need more information, would like to discuss altering the plan, or intend to approve as proposed. Hilcorp will follow up with a 10-403 once we have agreement on the abandonment plan. Thankyou, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC The information contained in this email message is confidential and maybe 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. <BRU 234-27 wp06_proposal report.pdf> <BRU 234-27 wp06.txt> Gluyas, Gavin R (OGQ From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Monday, September 8, 2025 10:15 AM To: McLellan, Bryan J (OGC); Dewhurst, Andrew D (OGC) Cc: Cody Dinger Subject: PTD 225-065 Hilcorp Well BRU 234-27: OH sidetrack off LCM cement plug Attachments: BRU 234-27 PB2 Geo.txt ICAUTION: 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. Good morning Bryan, We have been continuingto battle total losses on BRU 234-27. At 4,749' MD, we pumped a 50 bbls 15.8ppg LCM cement plugto heal up losses. The mule shoe was parked at 4,615' MD. We ran in with a cleanout assembly and tagged hard cement at 3,996' MD. While reaming the cement, we sidetracked off at 4,170' MD. It appears we had hard cement from 3,996'to TD in the plugback. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC 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 it 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. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/19/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250919 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 212-35T 50283200970000 198161 8/10/2025 AK E-LINE PPROF T40899 BRU 223-34T 50283202060000 225059 8/17/2025 AK E-LINE CBL T40900 BRU 234-27 50283202070000 225065 9/12/2025 AK E-LINE CBL T40901 BRU 242-04 50283201640000 212041 6/9/2025 AK E-LINE Perf T40902 KBU 11-08Z 50133206290000 214044 9/8/2025 AK E-LINE Perf T40903 MPU H-03 50029220630000 190088 9/9/2025 AK E-LINE SetPacker T40904 MPU H-11 50029228020000 197163 2/9/2025 AK E-LINE Caliper T40905 MPU M-62 50029237440000 223006 8/31/2025 AK E-LINE LDL T40906 NCIU A-06 50883200260000 169050 8/25/2025 AK E-LINE TubingCut T40907 NCIU A-21A 50883201990100 225075 8/26/2025 AK E-LINE Perf T40908 ODSK-33 50703205620000 207183 9/10/2025 READ Caliper Survey T40909 ODSN-01a 50703206480100 216008 9/8/2025 READ Caliper Survey T40910 ODSN-06 50703207150000 215098 9/9/2025 READ Jewelry Log T40911 PBU C-34C 50029217850300 225068 8/25/2025 BAKER MRPM T40912 PBU Q-06A 50029203460100 198090 8/21/2025 BAKER SPN T40913 TBU M-25 50733203910000 187086 8/31/2025 AK E-LINE Drift T40914 Please include current contact information if different from above. BRU 234-27 50283202070000 225065 9/12/2025 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.22 13:22:50 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, N2, CTCO 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 6,266'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: 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 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: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA 029657 225-065 50-283-20207-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,738' 10,160psi 2,576' Size 120' 2,839' MD See Attached Schematic 2,980psi 6,890psi 120'120' 2,862' September 28, 2025 Tieback 3-1/2" 6,266' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 234-27CO 802A Same 5,910'3-1/2" ~2,392psi 3,563' 6,150' Length LTP; N/A 2,704' MD/2,426' TVD; N/A, N/A 5,910'6,150'5,797' Beluga River Sterling-Beluga Gas 16" 7-5/8" See Attached Schematic m n P s O 66 t O N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-578 By Gavin Gluyas at 11:06 am, Sep 24, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.09.24 10:32:36 - 08'00' Noel Nocas (4361) BJM 9/25/25 X 10-404 DSR-9/24/25 CT BOP test to 3000 psi Submit remedial cementing plan to AOGCC with CBL and obtain approval before cementing. Submit post-remedial cementing CBL to AOGCC and obtain approval before perforating. A.Dewhurst 25SEP25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.09.26 09:50:13 -08'00'09/26/25 RBDMS JSB 092625 Well Prognosis Well Name: BRU 234-27 API Number: 50-283-20207-00-00 Current Status: New Drill Well Permit to Drill Number: 225-065 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: 2684 psi @ 5835’ TVD (Based on 0.46 psi/ft gradient) Max. Potential Surface Pressure: 2392 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.74 psi/ft using 14.23 ppg EMW FIT at the 7-5/8” surface casing Shallowest Potential Perf TVD: MPSP/(0.74-0.05) = 2392 psi / 0.69 = 3467’ TVD Top of SBGP (CO 802A): ~3119’ MD/~2825’ TVD Well Status: New Drill Well Initial Completion Brief Well Summary BRU 234-27 is the fifth of five grass roots well to be drilled in the 2025 Beluga River drilling campaign targeting the Sterling and Beluga sands. During the drilling of the well the well went on losses and left us several challenges: sticking a LWD BHA that was cemented in place, multiple sidetracks in open hole off the cement plugs that were pumped to attempt to heal losses. TD was achieved and liner run to bottom. While pumping the cement job on production liner, the wiper dart got stuck in drill pipe and the shoe was overdisplaced, then the liner hanger was set on subsequent trips in the well. A CIBP was installed above the float collar and used to set the liner top packer. The objective of this sundry is to mill out the cement from a cement top job, mill up the CIBP at 6150 and the float collar, perforate the well and flow the new well. All sands lie in the Sterling- Beluga Gas Pool (SBGP) per CO 802A and BRU PA. Wellbore Conditions: - Max Inclination – 42° at 1,984’ MD - T & IA PT to 3000 psi (30 min) 9/15/25 - Liner filled with 9.0 ppg drilling mud, tubing is filled with CI 8.4 ppg water - SL tagged hard cement at 2737’ (liner depth) - CIBP set at 6150’ used to set liner top packer - Top Of Pool per CO : ~3119’ MD/~2825’ TVD Procedure: 1. MIRU CT Unit #10 2. PT Lubricator to 250L/3500H a. Provide AOGCC 48hr notice for BOP test 3. MU cleanout BHA with motor & ~2.85” mill. 4. RIH and drill/mill cement at liner top (2737-2739’), CIBP at 6150’, and to the float collar at 6203’. Circulate out mud with water. 5. MIRU E-line and pressure control equipment 6. PT lubricator to 250 psi low / 2,500 psi high 7. Run CBL a. Submit CBL to AOGCC and BLM b. Complete remedial cement squeezes (if necessary) to get a minimum of 100ft of cement over the shallowest proposed perforations. c. Squeezes will be block hesitation squeezes with 15.3 ppg cement or suicide squeeze if there is no cement across proposed perforation intervals. Submit remedial cementing plan to AOGCC with CBL and obtain approval before cementing. -bjm Well Prognosis d. Post squeeze CBL will be performed and submitted to agencies if remedial squeezes are necessary. 8. RIH and set CIBP at 6200’. Pressure test tubing to 2500psi 9. RDMO Eline 10. Coil RIH with reverse jet nozzle and reverse water from well using N2, leaving 2200 psi of N2 on well. 11. RDMO Coil Tubing 12. MIRU E-line and pressure control equipment 13. PT lubricator to 250 psi low / 2,500 psi high 14. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 15. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: 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 b. Complete coil cleanouts as necessary for sand or water production per coil test procedure and equipment listed in steps 1-6 of this procedure. 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 E2 ±4,217' ±4,221' ±3,903' ±3,907' ±4’ BEL E3 ±4,252' ±4,257' ±3,038' ±3,942' ±5’ BEL F6 ±4,835' ±4,839' ±4,512' ±4,516' ±4’ BEL F7 ±4,941' ±4,947' ±4,616' ±4,622' ±6’ BEL F10 ±4,985' ±5,000' ±4,660' ±4,674' ±15’ BEL G ±5,056' ±5,061' ±4,729' ±4,734' ±5’ BEL G1 ±5,079' ±5,083' ±4,752' ±4,756' ±4’ BEL G8 ±5,346' ±5,358' ±5,013' ±5,024' ±12’ BEL G10 ±5,396' ±5,400' ±5,061' ±5,065' ±4’ BEL H1 ±5,486' ±5,489' ±5,149' ±5,152' ±3’ BEL H1 ±5,517' ±5,521' ±5,179' ±5,183' ±4’ BEL H2 ±5,525' ±5,535' ±5,187' ±5,197' ±10’ BEL H4 ±5,611' ±5,631' ±5,271' ±5,291' ±20’ BEL H4 ±5,656' ±5,659' ±5,315' ±5,318' ±3’ BEL H5 ±5,694' ±5,697' ±5,352' ±5,355' ±3’ BEL H5 ±5,702' ±5,705' ±5,360' ±5,363' ±3’ BEL H9 ±5,842' ±5,846' ±5,497' ±5,501' ±4’ BEL H9 ±5,863' ±5,867' ±5,517' ±5,521' ±4’ BEL H10 ±5,902' ±5,908' ±5,555' ±5,561' ±6’ BEL H12 ±5,975' ±5,996' ±5,627' ±5,647' ±21’ BEL H13 ±6,036' ±6,042' ±5,686' ±5,692' ±6’ BEL H14 ±6,057' ±6,068' ±5,707' ±5,717' ±11’ BEL H14 ±6,104' ±6,111' ±5,752' ±5,759' ±7’ BEL H15 ±6,160' ±6,189' ±5,807' ±5,835' ±29’ Well Prognosis Attachments: 1. Current Schematic 2. Proposed Schematic 3. CT Unit BOP Schematic 4. Standard Nitrogen Operations Updated by CAH 09-22-25 SCHEMATIC Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 PBTD 6,172’ MD / TVD 5,819’ TD 6,266’ MD / TVD 5,910’ RKB to GL = 19.8’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875”Surf 2,862’ 3-1/2"Prod Lnr 9.2 L-80 Wedge 563 2.992”2,703’6,266’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 2,738’ 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 2,704’YJ Ranger Liner Hanger & Scout Pkr 5.75” ID on Upper polish 3 2,738’4” Bullet seal assembly, 2.06’ off no-go 4 6,150’CIBP set 9/13/25 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 168 bbl (424 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 127 bbls (calculated 127 bbls), spacer & 63 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2” 140 bbls (329 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, Lost return flow 70 bbls into lead. Did not bump plug, dart was in drill pipe. Overdisplaced 5 bbls. Lost 262 bbls during cement job and liner setting attempt. Pumped top down squeeze #1 with 93 bbls of 15.3 ppg at liner top (still on losses) Pumped top down squeeze #2 with 51 bbls of 15.8 ppg at liner top, set liner top packer, circed 20 bbls to surface. TOC @ xxxx’based on CBL @ x/x/25 6-3/4” hole 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~3,119’ MD/2,825’ TVD Top of PA (BLM) Notes: 10’ Short jt w/ RA tags 5692, 4673, 3654 10’ Short joints 5181, 4160, 3145 Deviation Kick off ~500’ build to 42 deg @ 1985’. Drop to 10-13deg @ 3200’ RA 4485’ RA 4485’ RA 4485’ PB1 w/ BHA PB2 4 Cement tag w SL @ 2737’ on 9/18/25 Superseded Updated by CAH 09-22-25 SCHEMATIC Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 TOC/Sidetrack Point @ 4,170’ MD TD 4,749’ MD / TVD 4,227’ PB2 Schematic PB1 Schematic TOF @ 3,840’ MD BOF @ 4,426’ MD TD 4,574’ MD / TVD 4,255’ Lost in Hole DETAIL (8/29/25) No.Depth Item 1 3,840’Top of Fish (HWDP) See BHA details (attached) recovered 92.66’ of HWDP 4,426’Bottom of Fish (drilling BHA w/ LWD Sources Am241 @ 4331’ & Cs-137 @ 4345’) OPEN HOLE / CEMENT DETAIL 6-3/4” OH Pump 700’ of cement on top of fish (31 bbls of 15.8 ppg red dye) 6-3/4” hole OPEN HOLE / CEMENT DETAIL 6-3/4” OH Pumped 50 bbls LCM Cement 15.8 ppg @ 4,749’ MD. Cleaned out cement from 3,996’ and unintentionally sidetracked at 4,170’ MD. 6-3/4” hole PB1 w/ BHA Superseded Updated by CAH 09-22-25 PROPOSED Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 PBTD 6,172’ MD / TVD 5,819’ TD 6,266’ MD / TVD 5,910’ RKB to GL = 19.8’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875”Surf 2,862’ 3-1/2"Prod Lnr 9.2 L-80 Wedge 563 2.992”2,703’6,266’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 2,738’ 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 2,704’YJ Ranger Liner Hanger & Scout Pkr 5.75” ID on Upper polish 3 2,738’4” Bullet seal assembly, 2.06’ off no-go 4 6,200’CIBP OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 168 bbl (424 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 127 bbls (calculated 127 bbls), spacer & 63 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2” 140 bbls (329 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, Lost return flow 70 bbls into lead. Did not bump plug, dart was in drill pipe. Overdisplaced 5 bbls. Lost 262 bbls during cement job and liner setting attempt. Pumped top down squeeze #1 with 93 bbls of 15.3 ppg at liner top (still on losses) Pumped top down squeeze #2 with 51 bbls of 15.8 ppg at liner top, set liner top packer, circed 20 bbls to surface. TOC @ xxxx’based on CBL @ x/x/25 6-3/4” hole 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~3,119’ MD/2,825’ TVD Top of PA (BLM) BEL E2 ±4,217'±4,221'±3,903'±3,907'±4’Proposed TBD BEL E3 ±4,252'±4,257'±3,038'±3,942'±5’Proposed TBD BEL F6 ±4,835'±4,839'±4,512'±4,516'±4’Proposed TBD BEL F7 ±4,941'±4,947'±4,616'±4,622'±6’Proposed TBD BEL F10 ±4,985'±5,000'±4,660'±4,674'±15’Proposed TBD BEL G ±5,056'±5,061'±4,729'±4,734'±5’Proposed TBD BEL G1 ±5,079'±5,083'±4,752'±4,756'±4’Proposed TBD BEL G8 ±5,346'±5,358'±5,013'±5,024'±12’Proposed TBD BEL G10 ±5,396'±5,400'±5,061'±5,065'±4’Proposed TBD BEL H1 ±5,486'±5,489'±5,149'±5,152'±3’Proposed TBD BEL H1 ±5,517'±5,521'±5,179'±5,183'±4’Proposed TBD BEL H2 ±5,525'±5,535'±5,187'±5,197'±10’Proposed TBD BEL H4 ±5,611'±5,631'±5,271'±5,291'±20’Proposed TBD BEL H4 ±5,656'±5,659'±5,315'±5,318'±3’Proposed TBD BEL H5 ±5,694'±5,697'±5,352'±5,355'±3’Proposed TBD BEL H5 ±5,702'±5,705'±5,360'±5,363'±3’Proposed TBD BEL H9 ±5,842'±5,846'±5,497'±5,501'±4’Proposed TBD BEL H9 ±5,863'±5,867'±5,517'±5,521'±4’Proposed TBD BEL H10 ±5,902'±5,908'±5,555'±5,561'±6’Proposed TBD BEL H12 ±5,975'±5,996'±5,627'±5,647'±21’Proposed TBD BEL H13 ±6,036'±6,042'±5,686'±5,692'±6’Proposed TBD BEL H14 ±6,057'±6,068'±5,707'±5,717'±11’Proposed TBD BEL H14 ±6,104'±6,111'±5,752'±5,759'±7’Proposed TBD BEL H15 ±6,160'±6,189'±5,807'±5,835'±29’Proposed TBD Notes: 10’ Short jt w/ RA tags 5692, 4673, 3654 10’ Short joints 5181, 4160, 3145 Deviation Kick off ~500’ build to 42 deg @ 1985’. Drop to 10-13deg @ 3200’ Bel E2 to Bel H15 RA 4485’ RA 4485’ RA 4485’ PB1 w/ BHA PB2 4 Superseded Updated by CAH 09-22-25 PROPOSED Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 TOC/Sidetrack Point @ 4,170’ MD TD 4,749’ MD / TVD 4,227’ PB2 Schematic PB1 Schematic TOF @ 3,840’ MD BOF @ 4,426’ MD TD 4,574’ MD / TVD 4,255’ Lost in Hole DETAIL (8/29/25) No.Depth Item 1 3,840’Top of Fish (HWDP) See BHA details (attached) recovered 92.66’ of HWDP 4,426’Bottom of Fish (drilling BHA w/ LWD Sources Am241 @ 4331’ & Cs-137 @ 4345’) OPEN HOLE / CEMENT DETAIL 6-3/4” OH Pump 700’ of cement on top of fish (31 bbls of 15.8 ppg red dye) 6-3/4” hole OPEN HOLE / CEMENT DETAIL 6-3/4” OH Pumped 50 bbls LCM Cement 15.8 ppg @ 4,749’ MD. Cleaned out cement from 3,996’ and unintentionally sidetracked at 4,170’ MD. 6-3/4” hole PB1 w/ BHA Superseded Updated by CAH 09-25-25 SCHEMATIC Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 PBTD 6,172’ MD / TVD 5,819’ TD 6,266’ MD / TVD 5,910’ RKB to GL = 19.8’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875”Surf 2,862’ 3-1/2"Prod Lnr 9.2 L-80 Wedge 563 2.992”2,703’6,266’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 2,738’ 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 2,704’YJ Ranger Liner Hanger & Scout Pkr 5.75” ID on Upper polish 3 2,738’4” Bullet seal assembly, 2.06’ off no-go 4 6,150’CIBP set 9/13/25 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 168 bbl (424 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 127 bbls (calculated 127 bbls), spacer & 63 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2” 140 bbls (329 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, Lost return flow 70 bbls into lead. Did not bump plug, dart was in drill pipe. Overdisplaced 5 bbls. Lost 262 bbls during cement job and liner setting attempt. Pumped top down squeeze #1 with 93 bbls of 15.3 ppg at liner top (still on losses) Pumped top down squeeze #2 with 51 bbls of 15.8 ppg at liner top, set liner top packer, circed 20 bbls to surface. TOC @ xxxx’based on CBL @ x/x/25 6-3/4” hole 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~3,119’ MD/2,825’ TVD Top of PA (BLM) Notes: 10’ Short jt w/ RA tags 5692, 4673, 3654 10’ Short joints 5181, 4160, 3145 Deviation Kick off ~500’ build to 42 deg @ 1985’. Drop to 10-13deg @ 3200’ RA 4485’ RA 4485’ RA 4485’ PB1 ST @ 3234’ PB2 ST @ 4170’ 4 Cement tag w SL @ 2737’ on 9/18/25 Updated by CAH 09-25-25 SCHEMATIC Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 TOC/Sidetrack Point @ 4,170’ MD TD 4,749’ MD / TVD 4,227’ Sidetrack Point @ 3234’ TOF @ 3,840’ MD BOF @ 4,426’ MD TD 4,574’ MD / TVD 4,255’ PB2 Schematic PB1 Schematic OPEN HOLE / CEMENT DETAIL 6-3/4” OH Pumped 50 bbls LCM Cement 15.8 ppg @ 4,749’ MD. Cleaned out cement from 3,996’ and unintentionally sidetracked at 4,170’ MD. 6-3/4” hole PB1 w/ BHA Lost in Hole DETAIL (8/29/25) No.Depth Item 1 3,840’Top of Fish (HWDP) See BHA details (attached) recovered 92.66’ of HWDP 4,426’Bottom of Fish (drilling BHA w/ LWD Sources Am241 @ 4331’ & Cs-137 @ 4345’) OPEN HOLE / CEMENT DETAIL 6-3/4” OH Pump 700’ of cement on top of fish (31 bbls of 15.8 ppg red dye) 6-3/4” hole Updated by CAH 09-22-25 PROPOSED Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 PBTD 6,172’ MD / TVD 5,819’ TD 6,266’ MD / TVD 5,910’ RKB to GL = 19.8’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875”Surf 2,862’ 3-1/2"Prod Lnr 9.2 L-80 Wedge 563 2.992”2,703’6,266’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf 2,738’ 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 2,704’YJ Ranger Liner Hanger & Scout Pkr 5.75” ID on Upper polish 3 2,738’4” Bullet seal assembly, 2.06’ off no-go 4 6,200’CIBP OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 168 bbl (424 sx) 12 ppg lead cement followed by 37 bbl (200 sx) 15.8 tail cement. Bumped plug at 127 bbls (calculated 127 bbls), spacer & 63 bbls of lead cement to surface, 0 bbls of losses during job 3-1/2” 140 bbls (329 sx) 12 ppg Lead followed with 24 bbls (122 sx) of 15.3 ppg tail, Lost return flow 70 bbls into lead. Did not bump plug, dart was in drill pipe. Overdisplaced 5 bbls. Lost 262 bbls during cement job and liner setting attempt. Pumped top down squeeze #1 with 93 bbls of 15.3 ppg at liner top (still on losses) Pumped top down squeeze #2 with 51 bbls of 15.8 ppg at liner top, set liner top packer, circed 20 bbls to surface. TOC @ xxxx’based on CBL @ x/x/25 6-3/4” hole 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status Top of Pool per CO 802A: ~3,119’ MD/2,825’ TVD Top of PA (BLM) BEL E2 ±4,217'±4,221'±3,903'±3,907'±4’Proposed TBD BEL E3 ±4,252'±4,257'±3,038'±3,942'±5’Proposed TBD BEL F6 ±4,835'±4,839'±4,512'±4,516'±4’Proposed TBD BEL F7 ±4,941'±4,947'±4,616'±4,622'±6’Proposed TBD BEL F10 ±4,985'±5,000'±4,660'±4,674'±15’Proposed TBD BEL G ±5,056'±5,061'±4,729'±4,734'±5’Proposed TBD BEL G1 ±5,079'±5,083'±4,752'±4,756'±4’Proposed TBD BEL G8 ±5,346'±5,358'±5,013'±5,024'±12’Proposed TBD BEL G10 ±5,396'±5,400'±5,061'±5,065'±4’Proposed TBD BEL H1 ±5,486'±5,489'±5,149'±5,152'±3’Proposed TBD BEL H1 ±5,517'±5,521'±5,179'±5,183'±4’Proposed TBD BEL H2 ±5,525'±5,535'±5,187'±5,197'±10’Proposed TBD BEL H4 ±5,611'±5,631'±5,271'±5,291'±20’Proposed TBD BEL H4 ±5,656'±5,659'±5,315'±5,318'±3’Proposed TBD BEL H5 ±5,694'±5,697'±5,352'±5,355'±3’Proposed TBD BEL H5 ±5,702'±5,705'±5,360'±5,363'±3’Proposed TBD BEL H9 ±5,842'±5,846'±5,497'±5,501'±4’Proposed TBD BEL H9 ±5,863'±5,867'±5,517'±5,521'±4’Proposed TBD BEL H10 ±5,902'±5,908'±5,555'±5,561'±6’Proposed TBD BEL H12 ±5,975'±5,996'±5,627'±5,647'±21’Proposed TBD BEL H13 ±6,036'±6,042'±5,686'±5,692'±6’Proposed TBD BEL H14 ±6,057'±6,068'±5,707'±5,717'±11’Proposed TBD BEL H14 ±6,104'±6,111'±5,752'±5,759'±7’Proposed TBD BEL H15 ±6,160'±6,189'±5,807'±5,835'±29’Proposed TBD Notes: 10’ Short jt w/ RA tags 5692, 4673, 3654 10’ Short joints 5181, 4160, 3145 Deviation Kick off ~500’ build to 42 deg @ 1985’. Drop to 10-13deg @ 3200’ Bel E2 to Bel H15 RA 4485’ RA 4485’ RA 4485’ 4 PB1 ST @ 3234’ PB2 ST @ 4170’ Updated by CAH 09-22-25 PROPOSED Beluga River Unit BRU 234-27 (I Pad) PTD: 225-065 API: 50-283-20207-00-00 TOC/Sidetrack Point @ 4,170’ MD TD 4,749’ MD / TVD 4,227’ Sidetrack point @ 3234’ TOF @ 3,840’ MD BOF @ 4,426’ MD TD 4,574’ MD / TVD 4,255’ PB2 Schematic PB1 Schematic OPEN HOLE / CEMENT DETAIL 6-3/4” OH Pumped 50 bbls LCM Cement 15.8 ppg @ 4,749’ MD. Cleaned out cement from 3,996’ and unintentionally sidetracked at 4,170’ MD. 6-3/4” hole PB1 w/ BHA Lost in Hole DETAIL (8/29/25) No.Depth Item 1 3,840’Top of Fish (HWDP) See BHA details (attached) recovered 92.66’ of HWDP 4,426’Bottom of Fish (drilling BHA w/ LWD Sources Am241 @ 4331’ & Cs-137 @ 4345’) OPEN HOLE / CEMENT DETAIL 6-3/4” OH Pump 700’ of cement on top of fish (31 bbls of 15.8 ppg red dye) 6-3/4” hole STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Page 15/17 Well Name: BRU 234-27 Report Printed: 9/25/2025WellViewAdmin@hilcorp.com Daily Reports API / UWI 5028320207 Surface Legal Location S27 T13N R10W Field Name Beluga River (BRU) License No. State/Province ALASKA Well Configuration Type Directional Original KB/RT Elevation (ft) 105.60 RKB to GL (ft) 18.50 Original Spud Date 8/18/2025 16:00 Rig Release Date PBTD (All) Total Depth All (TVD) Start Time End Time Operation 14:00 19:30 Install high pressure cement hoses on YJ Cement head. Halliburton pumped 5 bbls water to flush and fill lines. Shut in at Halliburton cement head and PT lines at 368 psi low 4560 psi high. Good tests. Lined up YJ cement head to Halliburton, pumped 30 bbls 10.5 ppg Tuned Spacer at 3.5 bpm-508 psi, followed with 140 bbls (329 sx) 12 ppg Type I II Lead cement at 4 bpm, 508 - 126 psi, lost return flow 70 bbl into lead, followed with 24 bbls (122 sx) 15.3 ppg Type I II Tail cement at 4 bpm 89psi. Had 2 pps Bridgemaker LCM in lead. YJ released dart, Halliburton then displaced with 8.6 ppg 3% KCL mud at 4 bpm- 95 psi, slowed to 3bbl/min 10 bbl once dart passed through running tool, increase rate to 4bbl/min 95 psi FCP was 977 psi at 3.0bbl/min. Lost return flow 28bbl into displacement. Did not bump plug calculated at 68 bbls. Pumped additional 5bbl in attempt to bump. Halliburton held 510 psi for 3 minute, bled off pressure and got back 0.1 bbls to truck and floats held. CIP at 17:39 9/11/2025. Unable to pressure up to set and release from the hanger. R/D cement hoses. Left hand release off of LTP as per YJ rep. L/D cement head. M/U TD to stump to circulate. Pressured up to 180 psi on drill string and PU to un-sting running tool seen return flow before pack-off was out of the LTP. Once unstung increase rate to 320GPM at 360 psi. No spacer or cement to surface. Lost 262 bbls during the cmt job. 19:30 22:30 POOH on elevators f/ 2700' t/ surface. Found drill pipe wiper dart in last stand of drill pipe above the running tool. L/D Yellow Jacket running tool. P/U-42k, S/O-39k. Disp: Calc- 17.64 bbls, Act-43.43 bbls diff 25.79 22:30 23:00 P/U 4.5" DP single and perform weekly BOP funciton test. Function, Pipe rams, blinds, annular, and HCR's. Monitor well on TT: Static loss rate of 15.49 bbl/hr. 23:00 00:00 M/U top down squeeze asssembly as per YJ reps. P/U 4.5" DP single and M/U XO, pump out sub, XO and seal assembly. 00:00 02:00 RIH with top down squeeze assembly f/ 46' to TOL at 2704'. Engage seals and no-go out at 2712'. Disp: Calc-18.9bbls, Act-12.4bbls. 02:00 04:00 Close bag and establish injection rate of 2.5bbl/min at 140PSI. R/U cementers. 04:00 06:00 PJSM with cementers. Pump 5bbl of water ahead and PT lines to 1500psi. Pump 36bbl of 15.3ppg cement at 2bbl/min 80psi. Shut in bag and pump another 57bbl of 15.3ppg cement at 2bbl/min 80-145psi for a total of 93bbls. Displace with 10bbl of water and 26 bbl of mud at 4bbl/min 130psi. Unsting from seal assembly, P/U t/ 2681'. Report Number 29 Report Start Date 9/12/2025 Report End Date 9/13/2025 Ops and Depth @ Morning Report RIH w/ seal assmebly t/2680' AFE Number 251-00095 Last 24hr Summary POOH w/ top down squeeze assembly #1 F/ 2681’ T/ surface and LD assembly. R/U TRS equipment and LD cement stinger that was racked back in derrick. RU E-Line & RIH with gr junk basket, centralizer & CCL down t/6150’. POOH and M/U RBT tool for a bond long. Unable to get a good calibration on the tool, POOH and L/D. M/U 2.75” CIBP, RIH and set on depth at 6150’. POOH and R/D E-line. M/U YJ seal assembly and RIH w/ 32 jnts of 4.75” drill collars t/ 999’. Cont. to TIH out of derrick 24hr Forecast Space out and sting into liner top with seal assembly, pressure and set hanger. P/U out of liner top above tops seals, expose ports in seal assembly and establish injection rate. If injection rate is satisfactory R/U cementers and pump 50 bbls top-down squeeze. If hanger set stack weight on liner top and set packer. POOH, L/D 4.75” collars and seal assembly. M/U Polish mills, RIH, dress liner top and polish the seal bore extension. Daily Job Total (Cost) 270,690.00 Cumulative (Cost) 11,289,492.00 Start Time End Time Operation 06:00 06:30 Pumped wiper ball 27bbl, pressured up to 750psi shut down pump. 06:30 09:00 POOH w/ top down squeeze assembly f/2681' t/ surface. L/D tools. Disp: Calc- 18.9 bbl, Act-54.6 bbl. Lost 35.7 bbls. 09:00 09:30 Grease and inspect Topdrive, drawworks, brake linkage and crown section. 09:30 11:00 R/U 3.5" TRS equipment. RIH w/ 10 stands of 3.5" cement work string. 11:00 12:00 POOH L/D 12 jnts of 3.5" tubing. 12:00 12:30 Cont. to POOH and L/D remaining 8 jnts of 3.5" tubing. 12:30 13:30 R/D TRS tubing equipment. Clean and clear rig floor. Monitor well on TT- 3.44 bbl/hr static loss rate. 13:30 18:00 Wait on E-Line. Truck had power issues had to switch out trucks. R/U E-line. M/U 2.5" gauge ring and RIH t/3710'. POOH to surface, change gauge ring to 2.75". RIH w/ 2.75" gaug ring, CCL and junk basket t/6150'. POOH to surface. Monitor well on TT 3.02 bbl/hr static loss rate. 18:00 21:30 M/U 1 11/16' RBT tool to perform CBL on the 3.5" liner. RIH t/ 2807'. Couldnt get a good calibration on the tool. POOH and L/D RBT tool. 21:30 00:30 M/U 2.75" retrievable CIBP. RIH t/ 6150' and set CIBP. Monitor well on TT: 1.72bbl/hr static loss rate. 00:30 01:30 POOH w/ E-Line to surface. L/D tools and R/D. 01:30 02:00 Grease and inspect Topdrive, drawworks, brake linkage and crown section. 02:00 06:00 P/U and M/U YJ seall assembly. P/U 32 joints of 4 3/4" drill collars f/10' t/999'. M/U XO and RIH w/ 8 stands of 4.5" HWDP out of derrick. f/999' t/1495'. Cont TIH w/4.5" DP f/1495' t/2680'. Report Number 30 Report Start Date 9/13/2025 Report End Date 9/14/2025 Ops and Depth @ Morning Report LD remaing DP in derrick AFE Number 251-00095 Last 24hr Summary TIH w/ squeeze assembly F/ 2684’, Space out 5’ off nogo, pressure up set hanger and confirm set. PU expose ports bellow two top seals establish injection rat 2.5BPM 220PSI. RU cementers & pump 51 BBLs 15.8ppg surface cement tail squeezing last 15 BBLs at 1 BPM. CBU at 4 BPM, 20 BBLs of cement to surface. Set Packer & confirm w/ 2000 psi-good. LD cement head, E-Kelly. TOOH and LD drill collars. M/U polish mill assembly and RIH. Tag cement at 2710’, mill up cement. Dress liner top and polish seal bore extension as per YJ rep. Displace well over to CIW and negative pressure test 30min-good test. POOH L/D 4.5” DP and polish mills. RIH L/D remaining DP in derrick. 24hr Forecast Finish L/D all drill pipe. R/U and test casing to 3000 psi. Pull wear ring and clean well head with profile brush. R/U TRS equipment and RIH w/ 3.5” tie-back as per tally. Space out, M/U hanger and land out. R/U and perform MIT’s. Set TWC, N/D, BOPE’s, and N/U dry hole tree. RDMO Daily Job Total (Cost) 235,377.00 Cumulative (Cost) 11,524,869.00 Page 16/17 Well Name: BRU 234-27 Report Printed: 9/25/2025WellViewAdmin@hilcorp.com Daily Reports API / UWI 5028320207 Surface Legal Location S27 T13N R10W Field Name Beluga River (BRU) License No. State/Province ALASKA Well Configuration Type Directional Original KB/RT Elevation (ft) 105.60 RKB to GL (ft) 18.50 Original Spud Date 8/18/2025 16:00 Rig Release Date PBTD (All) Total Depth All (TVD) Start Time End Time Operation 06:00 07:30 PU & MU 1 joint of drill pipe & cement head. Lower in hole & engauge seals and tag NoGo at 2713'. PU 5' & set liner hanger at 2150 psi. Pressure up to 3000 psi & hold for 5 minutes. Bleed pressure off & set down 10K to confirm hanger set. Good. Pressure up T/ 1000 psi PU & locate ports above bottom 2 sets of seals. Establish injection rate at 2.5 BPM with 225 psi. 07:30 08:30 RU cement standpipe hose to cement head. 08:30 10:00 PJSM with all parties involved for squeeze job. HES pump 5 BBLs of water ahead & shut lower TIW on cement head. PT to 1200 psi. good. HES pump 15 more BBLs water at 2 BPM with 150 psi. Pump 51 BBLs of 15.8ppg Surface Tail cement at 2.8 BPM with 160 psi. Displaced 10 BBLs of water & slowed pump down to 1BPM & shut bag & squeeze 15 BBLs of cement between 7-5/8" casing and Liner Top assembly at 1 BPM with 95 psi. Let pressure bleed off and open bag. Circulate 100 BBLs of mud at 4 BPM with 420 psi. Dump 20 BBLs of cement to cuttings tank & 7 BBLs of contaminated mud. Set down and set Packer with 3 to 4 inches of movement with 43K down. Close bag & perform confirmation test on equipment with 2500 psi. from HES unit. Good. Bleed pressure off & open bag. 10:00 11:00 R/D cement head and cementers. L/D cement head a E-kelly. 11:00 12:00 Pump 25 bbl scrub pill, drop wiper ball and circulate surface to surface. 4bbl/min = 170PSI. 12:00 15:30 POOH f/2675' t/999' racking back pipe in derrick. Cont POOH L/D 4.75" drill collars f/999' to surface. 15:30 16:00 P/U diffuser and flush stack with black water. 16:00 18:30 M/U Polish mills and RIH f/ surface t/2710' tag cement. Ream out cement down to 2712' 130GPM=150PSI, 30RPM=3.2k Tq. Wash down t/2739' tag liner top. Dress liner top and polish seal bore extension as per YJ rep. 18:30 19:30 PJSM for displacement. Pump 20 bbl spacer followed with 183 bbl of CIW. 19:30 20:00 Perform 30 minute negative pressure test-good. 20:00 00:00 POOHf/2723' to surface L/D 4.5" dp, cleaning, redoping connections and sucking wiper balls. L/D Polish mill assembly. P/U cement head and break off XO's. 00:00 01:30 M/U mule shoe and RIH w/ 40 stands out of the derrick f/ surface t/2500'. 01:30 02:00 Pump pipe volume to flush drill pipe. 02:00 04:00 POOHf/2500' to surface L/D 4.5" dp, cleaning, redoping connections and sucking wiper balls. 04:00 05:00 RIH w/ 8 stands of HWDP and 7 stands of DP out of the derrick f/ surface t/1395'. Pump a string volume to clean pipe. 05:00 06:00 POOH f/1395' t/ surface L/D 4.5" dp, cleaning, redoping connections and sucking wiper balls. Report Number 31 Report Start Date 9/14/2025 Report End Date 9/15/2025 Ops and Depth @ Morning Report POOH L/D 4.5" DP at 2702' AFE Number 251-00095 Last 24hr Summary LD remaining drill pipe & HWDP. PT liner lap T/ 3000psi for 30 charted minutes-good. Pull wear ring & brush wellhead for hanger. RIH w/3-1/2” Tie-Back assembly T/ 2730’ and was unable to get complete seal assembly engaged. Stand back 3-1/2” tubing. Seals and nogo had cement on them. MU polish mill assembly & RIH w/4.5” DP singles from cat walk. Clean out cement from hanger/packer. POOH and LD mills. MU dummy seals & TIH t/2739’ and land out on nogo. 24hr Forecast POOH L/D 4.5” DP and dummy seal assembly. R/U TRS equipment M/U new seal assembly and RIH w/ 3.5” tie-back as per tally. Space out, M/U hanger and land out. R/U and perform MIT’s. Set TWC. Flush surface lines with barakleen pill. N/D, BOPE’s, and N/U dry hole tree. RDMO. Daily Job Total (Cost) 704,353.00 Cumulative (Cost) 12,229,222.00 Start Time End Time Operation 06:00 07:30 P/U Sperry I-Star tool service brake and remove battery sections. 07:30 09:00 R/U test equipment and test liner lap to 3000psi/30min charted-good. 09:00 10:00 Pull wear bushing and P/U scrubber brush. Flush and clean hanger profile at 80gpm 15RPM. 10:00 11:00 R/U TRS 3.5" tubing equipment. 11:00 12:00 PJSM running tie-back. P/U and M/U YJ seal assembly. RIH w/3.5" tie-back f/ 41' t/655'. P/U-20k, S/O-20k. 12:00 16:30 Cont. to RIH w/ 3.5" tie-back as per tally f/655' t/2732'. Tagged at 2723'. Worked string down t/2732' with pumps and rotary could not locate on to nogo after multiple attempts made. Applied 500psi to test seals. Could not confirm complete seal engagement. P/U-32k, S/O- 28k. 16:30 19:30 POOH w/ 3.5" tie-back. L/D jnts 86 and 85 f/2732' t/2681'. Cont to POOH racking back 3.5" tubing in derrick f/2681' to surface. L/D seal assembly. Observed hard cement on combo collar above locator sub and damage to the seal assembly. 19:30 23:30 M/U YJ polish mill and single in hole w/4.5" DP from catwalk f/ 37' t/2723'. 6k tag at 2723'. P/U-49k, S/O-42k, ROT-43k. 23:30 00:00 P/U t/2718' engauge pumps, rotary and ream down t/2733'. 250GPM=460PSI, 20RPM=2.1k Tq. Pump hi-vis sweep at 2733'. Seen a slight bobble and pump pressure increase at 2732'. At BU prior to sweep coming back started seeing cement cuttings on the shakers. Sweep brought back an increased amount of cement. 00:00 01:30 P/U another single from the cat walk and ream down t/2738'. Cont. working pipe to clean up cement. Increase RPM to 40 when working string up and slow RPM to 15 when working down. Pump 2 more hi-vis sweeps. Sweep 2 bought back a slight increase in cement and sweep 3 seen no inccrease. Work string and circulate until shakers clean. P/U above liner top and dry drift down to nogo f/2704' t/2739' x2 no set downs observed. P/U-44k, S/O-42k. 01:30 03:00 L/D top single. POOH f/2733' t/ surface. L/D polish mills. 03:00 06:00 P/U and M/U dummy seal assembly (stripped seals from damaged seal assembly.). TIH f/ 40' t/2739' and land out on nogo. Page 17/17 Well Name: BRU 234-27 Report Printed: 9/25/2025WellViewAdmin@hilcorp.com Daily Reports API / UWI 5028320207 Surface Legal Location S27 T13N R10W Field Name Beluga River (BRU) License No. State/Province ALASKA Well Configuration Type Directional Original KB/RT Elevation (ft) 105.60 RKB to GL (ft) 18.50 Original Spud Date 8/18/2025 16:00 Rig Release Date PBTD (All) Total Depth All (TVD) Report Number 32 Report Start Date 9/15/2025 Report End Date 9/16/2025 Ops and Depth @ Morning Report Rig Down AFE Number 251-00095 Last 24hr Summary BRU 234-27: POOH LD drill pipe & dummy seals. MU new seals & TIH with 3-1/2” tie-back. Space out, MU tubing hanger & land upper completion, 2.06’ off NoGo. Lock in hanger & pull test T/ 38K. Test hanger T/ 5000psi for 10 minutes. Perform Tubing & IA MIT tests T/ 3000psi for 30 charted minutes each. Good. Flush surface lines w/ Barakleen pill. N/D BOPE’s N/U dry hole tree. R/D and L/D top drive. Prep derrick to scope down. R/D pits. Inspect mud pump fluid ends. 24hr Forecast Cont to R/D. R/D office trailers and move to Diamind pad. Scatter rig. Lay felt, liner and rig mats on PCU D10 Daily Job Total (Cost) 450,426.00 Cumulative (Cost) 12,679,648.00 Start Time End Time Operation 06:00 08:30 POOH L/D 4.5" DP f/2734 t/surface. L/D dummy seal assembly. 08:30 09:00 P/U and M/U hanger profile scrubber. RIH and clean profile 15RPM and 120GPM. 09:00 10:00 Clean clear rig floor. PJSM-running tubing. R/U TRS 3.5" tubing equipment. 10:00 12:00 MU new YJ seal assembly and RIH out of the derrick f/ 39' t/1480'. 12:00 14:00 Cont. to TIH w/ 3.5" tir-back f/1480' t/2681'. P/U jnt 85 and locate nogo at2739'. L/D Jnt 85 and M/U hanger. Land hanger 2.06' off nogo. Set snap ring on hanger and P/U 38k to confirm set. 14:00 16:00 R/U test equipment and perform MIT-T 3000PSI-good test. Pumped 13.75 gallons bled back 12.5 gallons. R/U on IA and perform MIT-IA 3000PSI/30min-good test. Pumped 48.75 gallons bled back 48.75 gallons. 16:00 18:00 Install TWC in hanger. Flush surface lines and equipment with Barakleen pill. 18:00 21:30 Bleed down accumulator and disconnect hi-pressure lines. Remove flow line, riser, kill and chike line. Remove BOP and spacer spool from well head. 21:30 22:30 Install dry hole tree. Test void, and hanger neck seals to 5000PSI/10min. Removed two way check. 22:30 00:00 R/D top drive, install in cradle and lower to cat walk. 00:00 06:00 Install shipping beams. Remove and cap equalizer lines to pits. R/D mud lines. R/D pason lines to pits. Pull apart fluid ends on pumps and inspect liners, swabs, seats and valves. Prep derrick to scope down, remove hydraulic lines, Tee-bar, turn buckles and hinge pin on torque tube. R/D and L/d gas buster. Remove hydraulic lines from HPU to sub structure. Break apart stand pipe and bleeder line connections on rig floor. Rig released 9-16-2025 06:00 David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/23/2025 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Well: BRU 234-27 + PB1 + PB2 PTD: 225-065 API: 50-283-20207-00-00 (BRU 234-27) API: 50-283-20207-70-00 (BRU 234-27PB1) API: 50-283-20207-71-00 (BRU 234-27PB2) FINAL LWD FORMATION EVALUATION LOGS (08/18/2025 to 09/10/2025) DGR, PCG and BaseStar Gamma Ray, ADR and StrataStar Resistivity, LithoStar Density, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey Main Folder Contents: Sub-Folder Contents: Please include current contact information if different from above. T40919 T40920 T40921 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.24 08:00:05 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 4,574'N/A Casing Collapse Structural Conductor Surface 5,350psi Intermediate Production Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Yes Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Nathan Sperry Contact Email:nathan.sperry@hilcorp.com Contact Phone:907-777-8450 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng N/A Other: Abandon BHA w Sources 8/29/2025 N/A N/A N/A Perforation Depth MD (ft): N/A N/A 16" 7-5/8" 120' 2,862' MD 9,470psi 120' 2,658' 120' 2,862' Length Size Proposed Pools: N/A TVD Burst N/A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AKA029657 225-065 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-283-20207-00-00 Hilcorp Alaska, LLC BRU 234-27 AOGCC USE ONLY Bryan Mclellan 8/28/2025 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Drilling Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Beluga River Unit Sterling-Beluga Gas Pool Same 4,255'3,840'3,532'2,071psi See schematic m n P s 2 6 5 6 t c N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 1:00 pm, Aug 29, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.08.29 09:47:37 - 08'00' Sean McLaughlin (4311) 325-531 A.Dewhurst 29AUG25 10-407 DSR-9/9/25 The final wellbore diagram submitted with the 10-407 must include depths of PB1 hole TD, top and bottom of fish, top of RA source, sidetrack depth. BJM 9/19/25 See attached approval from NRC. JLC 9/19/2025 Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.09.20 12:24:45 -08'00' 09/20/25 RBDMS JSB 092625 Well Prognosis Well: BRU 234-27 Date: 8/28/25 Well Name:BRU 234-27 API Number:50-283-20207-00-00 Current Status:Abandon BHA w Sources Estimated Start Date:8/28/25 Rig:HEC 147 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:225-065 First Call Engineer:Nathan Sperry 907-777-8450 Second Call Engineer Sean Mclaughlin 907-223-6784 AFE Number: Well Status: While drilling ahead in BRU 234-27 with total losses at 4,574’ MD, drilling became very difficult (torque, sticking). We began backreaming out of the hole and made it to 4,426’ where the BHA became stuck. We were able to pump but did not have any returns at surface and the well was taking ~5 bbls/hr static losses from surface. We jarred on the fish for ~6 hrs before backing off and tripping for a fishing assembly. We ran a fishing assembly yesterday, engaged the fish at 1330 hrs, and jarred for ~13 hrs with zero movement in either direction. Hilcorp proposes to abandon our fish in the hole by pumping a 31 bbls, 700 ft long 15.8ppg balanced cement plug (with red dye) on top of the fish and sidetracking off the top of it. Our hole depth is 4,574’ MD. The bottom of the fish is 4,426’ and the top of the fish is 3,840’. The fish is 586’ long. We will run in the hole with our kickoff assembly, tag the TOC, orient, and sidetrack off it. We will leave a minimum of 200’ MD of cement on top of the fish. If we are not departed from the wellbore by 3,640’ MD, we will stop sidetracking and will contact you to discuss a forward plan. The uppermost source is 485’ below the top of the fish. If we kick off 200’ above the top of the fish, we will have 60’ of separation from the uppermost source as we drill by. The NRC has been notified and verbally approved our plan to abandon sources. Attachments: 1.Current Schematic 2.BHA Tally 3.Proposed Abandonment Schematic 4.Proposed Final Schematic 5.Directional Plan 6 Updated by CJD 8/28/25 Current Schematic Beluga River Unit BRU 234-27 (I Pad) PTD:225-065 API: 50-283-20207-00-00 TOF @ 3,840’ MD BOF @ ±4,423’ MD TD 4,574’ MD / TVD 4,255’ RKB to GL = 18.5’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875”Surf 2,862’ 16” 7-5/8” 9-7/8” hole Lost in Hole DETAIL No.Depth Item 1 3,840’Top of Fish (HWDP) See BHA details (attached) recovered 92.66’ of HWDP 4,426’Bottom of Fish OPEN HOLE / CEMENT DETAIL 7-5/8"L – 943 ft3 / T – 208 ft3 (75% excess) 6-3/4” hole 1 Top of RA source @ 4325' MD. -bjm WELL INFORMATION Created On : Aug 25 2025 Customer :Hilcorp Alaska, LLC Well Name :BRU 234-27 Job Number :AK-XX-0910122924 Rig Name :HEC 147 Field Name :Beluga River Country :USA BHA Tally Drillstring IADC Rig BHA#7 Run#500 Length (ft)Length Cumulative COMPONENT DATA (ft) Item #Description Serial Number OD ID Gauge Weight Top Connection Bottom Connection(in)(in)(in)(lbpf) 1 6 3/4" Baker D405TS PDC 5355862 4.240 1.625 6.750 41.05 P 3-1/2" REG 0.64 0.64 2 4 3/4" TerraForce Lobe 5/6 - 8.3 stg 10475810 4.750 2.794 44.57 B 3-1/2" IF B 3-1/2" REG 29.77 30.41 3 4 3/4" PCG-K Collar 90806730 4.750 1.920 97.80 B 3-1/2" IF P 3-1/2" IF 9.26 39.67 4 4 3/4" DM Collar 12941260 4.750 1.250 48.20 B 3-1/2" IF P 3-1/2" IF 9.26 48.93 5 4 3/4" ADR Collar 90806727 5.140 1.250 53.70 B 3-1/2" IF P 3-1/2" IF 26.77 75.70 6 4 3/4" ALD Collar 90806729 4.750 1.250 5.688 45.50 B 3-1/2" IF P 3-1/2" IF 14.34 90.04 Stabilizer 5.688 7 4 3/4" CTN Collar 90806729 5.150 1.250 50.50 B 3-1/2" IF P 3-1/2" IF 10.95 100.99 8 4 3/4" PWD Collar 90804946 4.720 1.250 47.90 B 3-1/2" IF P 3-1/2" IF 9.22 110.21 9 4 3/4" TM Collar 12310751 4.700 1.250 46.10 B 3-1/2" IF P 3-1/2" IF 10.60 120.81 10 3 1/2" IF X CDS-40 X- Over Sub UOCD 4705 5.140 2.250 57.17 B 4.5" CDS-40 P 3-1/2" IF 2.01 122.82 11 8 jnts 4.5" CDS-40 HWDP 4.500 2.813 36.86 B 4.5" CDS40 P 4.5" CDS40 244.94 367.76 12 CDS-40 x 3 1/2 IF X- Over Sub UOCD 4707 5.190 2.750 51.86 B 3-1/2" IF P 4.5" CDS-40 2.59 370.35 13 4 3/4" YellowJacket Jar A23804 HQ 4.810 2.250 48.38 B 3-1/2" IF P 3-1/2" IF 29.16 399.51 14 3 1/2 IF X CDS-40 X- Over Sub UOCD 4709 5.090 2.000 58.64 B 4.5" CDS-40 P 3-1/2" IF 1.95 401.46 15 9 jnts 4.5" CDS-40 HWDP 4.500 2.813 36.86 B 4.5" CDS40 P 4.5" CDS40 277.20 678.66 Total:678.66 BIT DATA Bit Number :2rr2 Nozzles :5x10 Bit Size (in) :6.750 TFA (in2) :0.3835 Manufacturer :Baker / Hughes Christensen Dull Grade In :1-1-WT-A-X-I-NO-HP Model :D405TS Dull Grade Out : Serial Number :5355862 MOTOR DATA Motor Number : Bend (deg) :1.502 OD (in) :4.750 Nozzles (32nd) :0.0 Manufacturer :Sperry Drilling Avg Diff Press : Model :TerraForce Cumul Cir Hrs : Serial Number :10475810 INSITE V11.0.0 Page 1Job No: AK-XX-0910122924 Well Name: BRU 234-27 BHA Tally 184.54184.54 586.00 586.00 5.9 Lost in Hole BHA Weight (klb) (klb) in Air (Total) :27.30 in Mud (Total) :N/A Mud Weight (ppg) : in Air (Below Jars) :15.56 in Mud (Below Jars) :N/A BHA WEIGHT CALCULATION MESSAGE Mud Weight not valid could not calculate BHA weight in mud. COMMENTS Draft INSITE V11.0.0 Page 2Job No: AK-XX-0910122924 Well Name: BRU 234-27 BHA Tally Updated by CJD 8/28/25 Proposed P&A Schematic Beluga River Unit BRU 234-27 (I Pad) PTD:225-065 API: 50-283-20207-00-00 TOF @ 3,840’ MD BOF @ ±4,426’ MD TD 4,574’ MD / TVD 4,255’ RKB to GL = 18.5’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875”Surf 2,862’ 16” 7-5/8” 9-7/8” hole Lost in Hole DETAIL No.Depth Item 1 3,840’Top of Fish (HWDP) See BHA details (attached) recovered 92.66’ of HWDP 4,426’Bottom of Fish OPEN HOLE / CEMENT DETAIL 7-5/8"L – 943 ft3 / T – 208 ft3 (75% excess) 6-3/4” OH Pump 700’ of cement on top of fish (31 bbls of 15.8 ppg red dye) 6-3/4” hole 1 Updated by CJD 8/28/25 Proposed Schematic Beluga River Unit BRU 234-27 (I Pad) PTD:225-065 API: 50-283-20207-00-00 PBTD ±6,200’ MD / TVD ±5,854’ TD 6,266’ MD / TVD 5,915’ RKB to GL = 18.5’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875”Surf 2,862’ 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.992”±2,662’6,266’ 3-1/2”Production Tieback 9.2 L-80 EUE 2.992”Surf ±2,639’ 2/3 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No.Depth Item 1 ±1,500’Chemical Injection Mandrel 2 ±2,662’Liner Hanger / LTP Assembly 3 ±2,662’Seal Stem OPEN HOLE / CEMENT DETAIL 7-5/8"L – 943 ft3 / T – 208 ft3 (75% excess) 3-1/2”L – 782 ft3 / T – 131 ft3 (40% excess) 6-3/4” hole 1 PB1 6WDQGDUG3URSRVDO5HSRUW $XJXVW 3ODQ%58ZS +LOFRUS$ODVND//& %HOXJD5LYHU %58,3DG 5LJ%58 %58 3200 3400 3600 3800 4000 4200 4400 4600 4800 5000 5200 5400 5600 5800 6000True Vertical Depth (400 usft/in)1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000 Vertical Section at 182.24° (400 usft/in) BRU 234-27 td tgt 3 5 0 0 4 0 0 0 4 5 0 0 4 5 7 4 BRU 234-27 PB1 3-1/2" Production Casing 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 2 6 7 BRU 234-27 wp06 KOP : Start Dir 3.5º/100' : 3640' MD, 3336.67'TVD : 135° LT TF End Dir : 3657' MD, 3353.33' TVD Start Dir 3.5º/100' : 3677' MD, 3372.94'TVD End Dir : 3917.08' MD, 3608.06' TVD Start Dir 3.5º/100' : 4167.08' MD, 3851.65'TVD End Dir : 4308.45' MD, 3990.22' TVD Start Dir 3.5º/100' : 4925.37' MD, 4597.76'TVD End Dir : 5173.48' MD, 4842.28' TVD Total Depth : 6266.2' MD, 5915.75' TVD 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: Rig: BRU 234-27 87.10 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2627046.48 315923.80 61° 11' 10.9431 N 151° 2' 35.3647 W SURVEY PROGRAM Date: 2025-08-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 232.60 3640.00 MWD+AX+Sag (1) (BRU 234-27 PB1) 3_MWD+AX+Sag 3640.00 3840.00 BRU 234-27 wp06 (BRU 234-27) 3_MWD_Interp Azi+Sag 3840.00 6266.20 BRU 234-27 wp06 (BRU 234-27) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3052.60 2947.00 3351.08 Sterling A1 3261.60 3156.00 3563.45 Sterling B 3406.60 3301.00 3711.31 Sterling C 3606.60 3501.00 3915.59 Beluga D 3803.60 3698.00 4117.77 Beluga E 4196.60 4091.00 4518.02 Beluga F 4728.60 4623.00 5058.05 Beluga G 5120.60 5015.00 5456.80 Beluga H 5890.60 5785.00 6240.60 Beluga I REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Rig: BRU 234-27, True North Vertical (TVD) Reference:RKB Actual @ 105.60usft (HEC 147) Measured Depth Reference:RKB Actual @ 105.60usft (HEC 147) Calculation Method:Minimum Curvature Project:Beluga River Site:BRU I-Pad Well:Rig: BRU 234-27 Wellbore:BRU 234-27 Design:BRU 234-27 wp06 CASING DETAILS TVD TVDSS MD Size Name 5915.75 5810.15 6266.20 3-1/2 3-1/2" Production Casing SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 3640.00 11.68 182.14 3336.67 -1223.40 -64.81 0.00 0.00 1225.00 KOP : Start Dir 3.5º/100' : 3640' MD, 3336.67'TVD : 135° LT TF 2 3657.00 11.27 179.99 3353.33 -1226.78 -64.88 3.50 -135.00 1228.38 End Dir : 3657' MD, 3353.33' TVD 3 3677.00 11.27 179.99 3372.94 -1230.69 -64.88 0.00 0.00 1232.28 Start Dir 3.5º/100' : 3677' MD, 3372.94'TVD 4 3917.08 13.00 140.00 3608.06 -1274.91 -47.49 3.50 -98.40 1275.79 End Dir : 3917.08' MD, 3608.06' TVD 5 4167.08 13.00 140.00 3851.65 -1317.99 -11.34 0.00 0.00 1317.43 Start Dir 3.5º/100' : 4167.08' MD, 3851.65'TVD 6 4308.45 10.00 160.00 3990.22 -1341.72 3.09 3.50 136.48 1340.57 End Dir : 4308.45' MD, 3990.22' TVD 7 4925.37 10.00 160.00 4597.76 -1442.38 39.73 0.00 0.00 1439.73 Start Dir 3.5º/100' : 4925.37' MD, 4597.76'TVD 8 5173.48 10.77 209.50 4842.28 -1482.88 35.68 3.50 109.78 1480.36 End Dir : 5173.48' MD, 4842.28' TVD 9 6266.20 10.77 209.50 5915.75 -1660.58 -64.86 0.00 0.00 1661.85 BRU 234-27 td tgt Total Depth : 6266.2' MD, 5915.75' TVD -1678 -1650 -1623 -1595 -1568 -1540 -1513 -1485 -1458 -1430 -1403 -1375 -1348 -1320 -1293 -1265 -1238 -1210 South(-)/North(+) (55 usft/in)-193 -165 -138 -110 -83 -55 -28 0 28 55 83 110 138 165 West(-)/East(+) (55 usft/in) BRU 234-27 td tgt Top of Fish Am-241 Be Cs-137 Bit Depth 3250 3500 375 0 4 0 0 0 4 2 5 5 BRU 234-27 PB1 3-1/2" Production Casing 37504 0 0 0 4 2 5 0 4 5 0 0 4750 5000 52 50 550 0 575 0 5916 BRU 234-27 wp06 KOP : Start Dir 3.5º/100' : 3640' MD, 3336.67'TVD : 135° LT TF End Dir : 3657' MD, 3353.33' TVD Start Dir 3.5º/100' : 3677' MD, 3372.94'TVD End Dir : 3917.08' MD, 3608.06' TVD Start Dir 3.5º/100' : 4167.08' MD, 3851.65'TVD End Dir : 4308.45' MD, 3990.22' TVD Start Dir 3.5º/100' : 4925.37' MD, 4597.76'TVD End Dir : 5173.48' MD, 4842.28' TVD Total Depth : 6266.2' MD, 5915.75' TVD CASING DETAILS TVD TVDSS MD Size Name 5915.75 5810.15 6266.20 3-1/2 3-1/2" Production Casing Project: Beluga River Site: BRU I-Pad Well: Rig: BRU 234-27 Wellbore: BRU 234-27 Plan: BRU 234-27 wp06 WELL DETAILS: Rig: BRU 234-27 87.10 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2627046.48 315923.80 61° 11' 10.9431 N 151° 2' 35.3647 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Rig: BRU 234-27, True North Vertical (TVD) Reference:RKB Actual @ 105.60usft (HEC 147) Measured Depth Reference:RKB Actual @ 105.60usft (HEC 147) Calculation Method:Minimum Curvature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eparation Factor3750 3900 4050 4200 4350 4500 4650 4800 4950 5100 5250 5400 5550 5700 5850 6000 6150 6300 6450Measured Depth (300 usft/in)BRU 234-27 PB1No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Rig: BRU 234-27 NAD 1927 (NADCON CONUS)Alaska Zone 0487.10+N/-S +E/-W Northing Easting Latittude Longitude0.000.002627046.48 315923.80 61° 11' 10.9431 N151° 2' 35.3647 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Rig: BRU 234-27, True NorthVertical (TVD) Reference:RKB Actual @ 105.60usft (HEC 147)Measured Depth Reference:RKB Actual @ 105.60usft (HEC 147)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-08-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool232.60 3640.00 MWD+AX+Sag (1) (BRU 234-27 PB1) 3_MWD+AX+Sag3640.00 3840.00 BRU 234-27 wp06 (BRU 234-27) 3_MWD_Interp Azi+Sag3840.00 6266.20 BRU 234-27 wp06 (BRU 234-27) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)3750 3900 4050 4200 4350 4500 4650 4800 4950 5100 5250 5400 5550 5700 5850 6000 6150 6300 6450Measured Depth (300 usft/in)NO GLOBAL FILTER: Using user defined selection & filtering criteria3640.00 To 6266.72Project: Beluga RiverSite: BRU I-PadWell: Rig: BRU 234-27Wellbore: BRU 234-27Plan: BRU 234-27 wp06CASING DETAILSTVD TVDSS MD Size Name5915.75 5810.15 6266.20 3-1/2 3-1/2" Production Casing Global Radiation Safety 3000 N. Sam Houston Parkway East · Plaza 1, Office 5320M Houston, Texas 77032-3219 U.S. Nuclear Regulatory Commission – Region IV 1600 East Lamar Blvd. Arlington, TX 76011 Attn: Division Director - DNMS Re: Notification of Well Logging Sealed Source Abandonment Halliburton Energy Services, Inc. USNRC License No. 42-01068-07 This letter comprises the required 30-day written notification of source abandonment as required by 10 CFR 39.77(d). This is a follow-up to the communications between Halliburton and NRC Region IV in which permission to proceed with the abandonment was granted on August 28, 2025. Date of Occurrence: Company Name: Well Name & Registration No.: Well Location: Rig Name: 26 – August - 2025 HilCorp Alaska, LLC 3800 Center Point Dr. Suite 1400 Anchorage, AK 99503 BRU 234-27 / 50-28320207-00-00 Lat. 61° 11 10.943 North Long 151° 2 35.365 West HEC147 Sources Abandoned: One 296GBq (8Ci) Am241Be doubly encapsulated radioactive sealed source, solid, special form. Eckert & Ziegler, Model LWD4133; Source Serial Number EZ18106 and One 74Gbq (2.0 Ci) Cs-137 doubly encapsulated radioactive sealed source, solid, special form. Eckert & Ziegler, Cs7.P07; Source Serial Number EZ20072D Immobilization method: Approximately a 200-250’ cement plug was pumped from the top of the fish to the kickoff point to sidetrack the well. There is 678.66 feet of the BHA immobilized with approximately 555.84 of BHA between the bottom of the cement plug and top source. Well was sidetracked at 3,640 MD / 3336.67 TVD. September 18, 2025 9/18/2025 Notification of Source Abandonment USNRC License No. 42-01068-07 Page 2 of 3 Results of Efforts to Immobilize and set sources in place: Depth of Well: Depth of Bottom of Fish: Depth of Sources: Depth of Top of Fish: Depth of Bottom of Cement Plug: Depth of Top of Cement Plug: Abandonment procedure successfully completed on 29 – August - 2025 4574 ft. MD / 4255 ft. TVD 4426 ft. MD / 4109 ft. TVD Am241Be source located at 4331 ft. MD / 4015 ft TVD Cs-137 source located at 4345 ft. MD / 4029 ft. TVD 3840 ft. MD / 3532 ft. TVD 5848 ft. MD / 3666.5 ft. TVD 3840 ft. MD / 3532 ft. TVD Description of Recovery Attempts: 8/26/25 Rig up wireline to start free point / run string shot. Attempt to back out of string. No success. 4 additional attempts with string shot with no success. 8/27/25 6th attempt with string shot to unscrew from drill string successful. Pulled out of hole at 0500 to pick up jarring assembly. Screw in to drill string and start pumping at 1330. Begin jarring operations. No success. Attempted to get more aggressive with jarring and pulling on string to maximum safe limit of rig. No movement of pipe observed. Decision was made to back off of fish and come out of hole. First attempt to get off fish was unsuccessful. 2nd attempt currently underway. Decision has been made to apply for permission to abandon from the NRC Warning Plaque:See Attachment 1 for a representation of the plaque. Attached Supporting Documents Hilcorp Alaska. LL Standard Proposal Report Halliburton BHA Tally Well Information Radiation Source Sealed Source Certificates Radiation Source Leak Tests Sincerely, Kevin Bowery Sr. Radiation Safety Officer – NAL / GOM Halliburton Energy Services, Inc. Email: Kevin.Bowery@Halliburton.com ery 9/18/2025 Notification of Source Abandonment USNRC License No. 42-01068-07 Page 3 of 3 Attachment: (1) Representation of Warning Plaque ATTACHMENT 1 Representation of Permanent Warning Plaque Well Name: BRU 234-27 Well Registration No. 50-283-20207-00-00 CAUTION ONE 296 GBq (8 Ci) AM-241BE RADIOACTIVE SOURCE AND ONE 74 GBq (2 Ci) CS-137 RADIOACTIVE SOURCE ABANDONED AUGUST 29, 2025. FIRST SOURCE LOCATED AT 4331 FT. MD. 4015 FT. TVD AND SECOND SOURCE LOCATED AT 4345 FT. MD. 4029 FT TVD. PLUG BACK DEPTH TOP OF CEMENT PLUG 3234 FT. MD & 2937 TVD. AVOID BORE BELOW PLUGBACK AND DO NOT RE- ENTER THIS WELL BELOW PLUG BACK BEFORE CONTACTING THE US NUCLEAR REGULATORY COMMISSION. 6WDQGDUG3URSRVDO5HSRUW $XJXVW 3ODQ%58ZS +LOFRUS$ODVND//& %HOXJD5LYHU %58,3DG 5LJ%58 %58 3200 3400 3600 3800 4000 4200 4400 4600 4800 5000 5200 5400 5600 5800 6000True Vertical Depth (400 usft/in)1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000 Vertical Section at 182.24° (400 usft/in) BRU 234-27 td tgt 3 5 0 0 4 0 0 0 4 5 0 0 4 5 7 4 BRU 234-27 PB1 3-1/2" Production Casing 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 2 6 7 BRU 234-27 wp06 KOP : Start Dir 3.5º/100' : 3640' MD, 3336.67'TVD : 135° LT TF End Dir : 3657' MD, 3353.33' TVD Start Dir 3.5º/100' : 3677' MD, 3372.94'TVD End Dir : 3917.08' MD, 3608.06' TVD Start Dir 3.5º/100' : 4167.08' MD, 3851.65'TVD End Dir : 4308.45' MD, 3990.22' TVD Start Dir 3.5º/100' : 4925.37' MD, 4597.76'TVD End Dir : 5173.48' MD, 4842.28' TVD Total Depth : 6266.2' MD, 5915.75' TVD 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: Rig: BRU 234-27 87.10 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2627046.48 315923.80 61° 11' 10.9431 N 151° 2' 35.3647 W SURVEY PROGRAM Date: 2025-08-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 232.60 3640.00 MWD+AX+Sag (1) (BRU 234-27 PB1) 3_MWD+AX+Sag 3640.00 3840.00 BRU 234-27 wp06 (BRU 234-27) 3_MWD_Interp Azi+Sag 3840.00 6266.20 BRU 234-27 wp06 (BRU 234-27) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3052.60 2947.00 3351.08 Sterling A1 3261.60 3156.00 3563.45 Sterling B 3406.60 3301.00 3711.31 Sterling C 3606.60 3501.00 3915.59 Beluga D 3803.60 3698.00 4117.77 Beluga E 4196.60 4091.00 4518.02 Beluga F 4728.60 4623.00 5058.05 Beluga G 5120.60 5015.00 5456.80 Beluga H 5890.60 5785.00 6240.60 Beluga I REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Rig: BRU 234-27, True North Vertical (TVD) Reference:RKB Actual @ 105.60usft (HEC 147) Measured Depth Reference:RKB Actual @ 105.60usft (HEC 147) Calculation Method:Minimum Curvature Project:Beluga River Site:BRU I-Pad Well:Rig: BRU 234-27 Wellbore:BRU 234-27 Design:BRU 234-27 wp06 CASING DETAILS TVD TVDSS MD Size Name 5915.75 5810.15 6266.20 3-1/2 3-1/2" Production Casing SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 3640.00 11.68 182.14 3336.67 -1223.40 -64.81 0.00 0.00 1225.00 KOP : Start Dir 3.5º/100' : 3640' MD, 3336.67'TVD : 135° LT TF 2 3657.00 11.27 179.99 3353.33 -1226.78 -64.88 3.50 -135.00 1228.38 End Dir : 3657' MD, 3353.33' TVD 3 3677.00 11.27 179.99 3372.94 -1230.69 -64.88 0.00 0.00 1232.28 Start Dir 3.5º/100' : 3677' MD, 3372.94'TVD 4 3917.08 13.00 140.00 3608.06 -1274.91 -47.49 3.50 -98.40 1275.79 End Dir : 3917.08' MD, 3608.06' TVD 5 4167.08 13.00 140.00 3851.65 -1317.99 -11.34 0.00 0.00 1317.43 Start Dir 3.5º/100' : 4167.08' MD, 3851.65'TVD 6 4308.45 10.00 160.00 3990.22 -1341.72 3.09 3.50 136.48 1340.57 End Dir : 4308.45' MD, 3990.22' TVD 7 4925.37 10.00 160.00 4597.76 -1442.38 39.73 0.00 0.00 1439.73 Start Dir 3.5º/100' : 4925.37' MD, 4597.76'TVD 8 5173.48 10.77 209.50 4842.28 -1482.88 35.68 3.50 109.78 1480.36 End Dir : 5173.48' MD, 4842.28' TVD 9 6266.20 10.77 209.50 5915.75 -1660.58 -64.86 0.00 0.00 1661.85 BRU 234-27 td tgt Total Depth : 6266.2' MD, 5915.75' TVD -1678 -1650 -1623 -1595 -1568 -1540 -1513 -1485 -1458 -1430 -1403 -1375 -1348 -1320 -1293 -1265 -1238 -1210 South(-)/North(+) (55 usft/in)-193 -165 -138 -110 -83 -55 -28 0 28 55 83 110 138 165 West(-)/East(+) (55 usft/in) BRU 234-27 td tgt Top of Fish Am-241 Be Cs-137 Bit Depth 3250 3500 375 0 4 0 0 0 4 2 5 5 BRU 234-27 PB1 3-1/2" Production Casing 37504 0 0 0 4 2 5 0 4 5 0 0 4750 5000 52 50 550 0 575 0 5916 BRU 234-27 wp06 KOP : Start Dir 3.5º/100' : 3640' MD, 3336.67'TVD : 135° LT TF End Dir : 3657' MD, 3353.33' TVD Start Dir 3.5º/100' : 3677' MD, 3372.94'TVD End Dir : 3917.08' MD, 3608.06' TVD Start Dir 3.5º/100' : 4167.08' MD, 3851.65'TVD End Dir : 4308.45' MD, 3990.22' TVD Start Dir 3.5º/100' : 4925.37' MD, 4597.76'TVD End Dir : 5173.48' MD, 4842.28' TVD Total Depth : 6266.2' MD, 5915.75' TVD CASING DETAILS TVD TVDSS MD Size Name 5915.75 5810.15 6266.20 3-1/2 3-1/2" Production Casing Project: Beluga River Site: BRU I-Pad Well: Rig: BRU 234-27 Wellbore: BRU 234-27 Plan: BRU 234-27 wp06 WELL DETAILS: Rig: BRU 234-27 87.10 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2627046.48 315923.80 61° 11' 10.9431 N 151° 2' 35.3647 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Rig: BRU 234-27, True North Vertical (TVD) Reference:RKB Actual @ 105.60usft (HEC 147) Measured Depth Reference:RKB Actual @ 105.60usft (HEC 147) Calculation Method:Minimum Curvature 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH 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B0:'$;6DJ(OOLSVHHUURUWHUPVDUHFRUUHODWHGDFURVVVXUYH\WRROWLHRQSRLQWV6HSDUDWLRQLVWKHDFWXDOGLVWDQFHEHWZHHQHOOLSVRLGV&DOFXODWHGHOOLSVHVLQFRUSRUDWHVXUIDFHHUURUV&OHDUDQFH)DFWRU 'LVWDQFH%HWZHHQ3URILOHV'LVWDQFH%HWZHHQ3URILOHV(OOLSVH6HSDUDWLRQ'LVWDQFH%HWZHHQFHQWUHVLVWKHVWUDLJKWOLQHGLVWDQFHEHWZHHQZHOOERUHFHQWUHV$OOVWDWLRQFRRUGLQDWHVZHUHFDOFXODWHGXVLQJWKH0LQLPXP&XUYDWXUHPHWKRG$XJXVW &203$663DJHRI 0.001.002.003.004.00Separation Factor3750 3900 4050 4200 4350 4500 4650 4800 4950 5100 5250 5400 5550 5700 5850 6000 6150 6300 6450Measured Depth (300 usft/in)BRU 234-27 PB1No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Rig: BRU 234-27 NAD 1927 (NADCON CONUS)Alaska Zone 0487.10+N/-S +E/-W Northing Easting Latittude Longitude0.000.002627046.48 315923.80 61° 11' 10.9431 N151° 2' 35.3647 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Rig: BRU 234-27, True NorthVertical (TVD) Reference:RKB Actual @ 105.60usft (HEC 147)Measured Depth Reference:RKB Actual @ 105.60usft (HEC 147)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-08-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool232.60 3640.00 MWD+AX+Sag (1) (BRU 234-27 PB1) 3_MWD+AX+Sag3640.00 3840.00 BRU 234-27 wp06 (BRU 234-27) 3_MWD_Interp Azi+Sag3840.00 6266.20 BRU 234-27 wp06 (BRU 234-27) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)3750 3900 4050 4200 4350 4500 4650 4800 4950 5100 5250 5400 5550 5700 5850 6000 6150 6300 6450Measured Depth (300 usft/in)NO GLOBAL FILTER: Using user defined selection & filtering criteria3640.00 To 6266.72Project: Beluga RiverSite: BRU I-PadWell: Rig: BRU 234-27Wellbore: BRU 234-27Plan: BRU 234-27 wp06CASING DETAILSTVD TVDSS MD Size Name5915.75 5810.15 6266.20 3-1/2 3-1/2" Production Casing WELL INFORMATION Created On : Aug 25 2025 Customer :Hilcorp Alaska, LLC Well Name :BRU 234-27 Job Number :AK-XX-0910122924 Rig Name :HEC 147 Field Name :Beluga River Country :USA BHA Tally Drillstring IADC Rig BHA#7 Run#500 Length (ft)Length Cumulative COMPONENT DATA (ft) Item #Description Serial Number OD ID Gauge Weight Top Connection Bottom Connection(in)(in)(in)(lbpf) 1 6 3/4" Baker D405TS PDC 5355862 4.240 1.625 6.750 41.05 P 3-1/2" REG 0.64 0.64 2 4 3/4" TerraForce Lobe 5/6 - 8.3 stg 10475810 4.750 2.794 44.57 B 3-1/2" IF B 3-1/2" REG 29.77 30.41 3 4 3/4" PCG-K Collar 90806730 4.750 1.920 97.80 B 3-1/2" IF P 3-1/2" IF 9.26 39.67 4 4 3/4" DM Collar 12941260 4.750 1.250 48.20 B 3-1/2" IF P 3-1/2" IF 9.26 48.93 5 4 3/4" ADR Collar 90806727 5.140 1.250 53.70 B 3-1/2" IF P 3-1/2" IF 26.77 75.70 6 4 3/4" ALD Collar 90806729 4.750 1.250 5.688 45.50 B 3-1/2" IF P 3-1/2" IF 14.34 90.04 Stabilizer 5.688 7 4 3/4" CTN Collar 90806729 5.150 1.250 50.50 B 3-1/2" IF P 3-1/2" IF 10.95 100.99 8 4 3/4" PWD Collar 90804946 4.720 1.250 47.90 B 3-1/2" IF P 3-1/2" IF 9.22 110.21 9 4 3/4" TM Collar 12310751 4.700 1.250 46.10 B 3-1/2" IF P 3-1/2" IF 10.60 120.81 10 3 1/2" IF X CDS-40 X- Over Sub UOCD 4705 5.140 2.250 57.17 B 4.5" CDS-40 P 3-1/2" IF 2.01 122.82 11 8 jnts 4.5" CDS-40 HWDP 4.500 2.813 36.86 B 4.5" CDS40 P 4.5" CDS40 244.94 367.76 12 CDS-40 x 3 1/2 IF X- Over Sub UOCD 4707 5.190 2.750 51.86 B 3-1/2" IF P 4.5" CDS-40 2.59 370.35 13 4 3/4" YellowJacket Jar A23804 HQ 4.810 2.250 48.38 B 3-1/2" IF P 3-1/2" IF 29.16 399.51 14 3 1/2 IF X CDS-40 X- Over Sub UOCD 4709 5.090 2.000 58.64 B 4.5" CDS-40 P 3-1/2" IF 1.95 401.46 15 9 jnts 4.5" CDS-40 HWDP 4.500 2.813 36.86 B 4.5" CDS40 P 4.5" CDS40 277.20 678.66 Total:678.66 BIT DATA Bit Number :2rr2 Nozzles :5x10 Bit Size (in) :6.750 TFA (in2) :0.3835 Manufacturer :Baker / Hughes Christensen Dull Grade In :1-1-WT-A-X-I-NO-HP Model :D405TS Dull Grade Out : Serial Number :5355862 MOTOR DATA Motor Number : Bend (deg) :1.502 OD (in) :4.750 Nozzles (32nd) :0.0 Manufacturer :Sperry Drilling Avg Diff Press : Model :TerraForce Cumul Cir Hrs : Serial Number :10475810 INSITE V11.0.0 Page 1Job No: AK-XX-0910122924 Well Name: BRU 234-27 BHA Tally BHA Weight (klb) (klb) in Air (Total) :27.30 in Mud (Total) :23.55 Mud Weight (ppg) :9.00 in Air (Below Jars) :15.56 in Mud (Below Jars) :13.42 COMMENTS Motor assembly for 6-3/4” Production Hole section 4-3/4” Terraforce Mud Motor @ 1.50°, 1.00 Rev/Gal Gamma = 34.37’, Dir = 43.73’, Res = 62.02’, ALD = 80.24’, CTN = 94.95’, PWD =106.53’ RFO = 386 / 481 X 360° = 288.89° Planned Parameters: 170-220 GPM, 40 - 80 RPM, 3k-10k WOB Torque Bit to 8K, 3-1/2” IF = 10K Jar Hrs. In = 103.98 / Jar Hrs. Out = XXX INSITE V11.0.0 Page 2Job No: AK-XX-0910122924 Well Name: BRU 234-27 BHA Tally Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Beluga River Unit Field, Sterling-Beluga Gas Pool, BRU 234-27 Hilcorp Alaska, LLC Permit to Drill Number: 225-065 Surface Location: 1853' FSL, 2032' FEL, Sec 27, T13N, R10W, SM, AK Bottomhole Location: 199' FSL, 2102' FEL, Sec 27, 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. 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: This well is being drilled on a new pad, it is only ~1/2-mile from an offset well with mud log (BRU 212- 26). It would not significantly add to the geologic knowledge of the area. Requirement to acquire mud log and submit cuttings is waived as per 20 AAC 25.071(c). 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 31st day of July 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.31 09:10:53 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 6,263' TVD: 5,916' 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): 105.6' 15. Distance to Nearest Well Open Surface: x-315923 y-2627046 Zone-4 87.1' to Same Pool:1345' to BRU 241-24T 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 42 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# P-110 GBCD 2,839' Surface Surface 2,839' 2,545' 6-3/4" 3-1/2" 9.2# L-80 Wedge 563 3,624' 2,639' 2,355' 6,263' 5,916' Tieback 3-1/2" 9.2# L-80 EUE 2,639' Surface Surface 2,639 2,355' 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 BRU 234-27 Beluga River Unit Sterling-Beluga Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 782 ft3 / T - 131 ft3 2071 748' FSL, 2102' FEL, Sec 27, T13N, R10W, SM, AK 199' FSL, 2102' FEL, Sec 27, T13N, R10W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1853' FSL, 2032' FEL, Sec 27, T13N, R10W, SM, AK AKA029657 18. Casing Program:Top - Setting Depth - BottomSpecifications 2662 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) Driven L - 943 ft3 / T - 128 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): LengthCasing Size Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate Drilling Manager Sean Mclaughlin 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): 8/11/2025 3178' to nearest unit boundary Nathan Sperry nathan.sperry@hilcorp.com 907-777-8450 Tieback Assy. 1474 Cement Volume MD s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 1:39 pm, Jun 24, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.06.23 16:24:32 - 08'00' Sean McLaughlin (4311) BOP test to 3000 psi. Annular test to 2500 psi. Submit FIT/LOT results within 48 hrs of completing test. 225-065 A.Dewhurst 30JUL25BJM 7/29/25 50-283-20207-00-00 DSR-6/30/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.31 09:11:04 -08'00' 07/31/25 07/31/25 RBDMS JSB 080125 BRU 234-27 Drilling Program Beluga River Unit June 19, 2025 BRU 234-27 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-Built NAD27 & NAD83).................................................................................49 Page 2 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 1.0 Well Summary Well BRU 234-27 Pad & Old Well Designation BRU I Pad – Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Sterling/Beluga Planned Well TD, MD / TVD 6263’ MD / 5916’ TVD PBTD, MD / TVD 6263’ MD / 5916’ TVD AFE Drilling Days 16 AFE Completion Days 3 Maximum Anticipated Pressure (Surface)2071 psi Maximum Anticipated Pressure (Downhole/Reservoir)2662 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 105.6’ Ground Elevation 87.1’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 2.0 Management of Change Information Page 4 Version 0.0 April 2, 2025 BRU 234-27 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 Hydril 563 10160 10540 207 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update x Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of multiple individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 2. Spills: x Notify Drlg Manager 1. Sean Mclaughlin: C: 907-223-6784 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com,andcdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com,and cdinger@hilcorp.com Page 6 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 7.0 Drilling / Completion Summary BRU 234-27 is an S-shaped directional grassroots development well to be drilled from BRU I 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 ~42 deg. and TD of the well will be 6263’ TMD/ 5916’ TVD, ending with 10 deg inclination left in the hole. Vertical separation will be 1662 ft. Drilling operations are expected to commence approximately August 11 th, 2025. The Hilcorp Rig #147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 2,839’ MD / 2,545’ 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 (13.2# minimum to drill ahead). 6. Drill 6-3/4” hole section to production TD. Perform Wiper trip. 7. Run and cmt 3-1/2” production liner. 8. Displace well to 6% KCL completion fluid. 9. POOH and LDDP. 10. RIH and land 3-1/2” tieback string in liner top. 11. Test IA to 3000; Test tubing to 3000 psi 12. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: Surface hole: GR + Res MWD Production Hole: Triple Combo Page 8 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with all relevant AOGCC regulations and all BLM regulations pertaining to Onshore Order No.1. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of BRU 234-27. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. And BLM 48 hrs notice prior to testing. x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14-day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC and BLM approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the BLM APD and the AOGCC PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. BLM Regulation Variance Requests: x Onshore Oil and Gas Order No. 1, Section III. D. 3. C. o Hilcorp requests approval to install a 2-1/16” 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. Page 9 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only 6-3/4” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48 hours’ notice prior to testing BOPs. x Any other notifications required in APD. Required BLM Notifications: x 48 hours before spud. Follow up with actual spud date and time within 24 hours. x 72 hours before casing running and cmt operations x 72 hours before BOPE tests x 72 hours before logging, coring, & testing x Any other notifications required in APD Additional requirements may be stipulated on APD and Sundry. Page 10 Version 0.0 April 2, 2025 BRU 234-27 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 234-27 Drilling Procedure 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install landing ring on conductor. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 147, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.8 Mix mud for 9-7/8” hole section. 9.9 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. Page 12 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 10.0 N/U 21-1/4” 2M Diverter 10.1 N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x NOTE:Ensure closing time on diverter annular is in line with API RP 64: 2..1.1.Annular element ID 20” or smaller: Less than 30 seconds 2..1.2.Annular element ID greater than 20”: Less than 45 seconds 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking. x A prohibition on ignition sources or running equipment. x A prohibition on staged equipment or materials. x Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. 10.5 Estimated diverter line orientation on BRU I Pad (orientation is subject to change on location): Orient diverter discharge to ensure adequate egress from the pad in the event gas is venting from diverter. -bjm Page 13 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure Orient diverter discharge to ensure adequate egress from the pad in the event gas is venting from diverter. -bjm Page 14 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 11.0 Drill 9-7/8” Hole Section 11.1 P/U 9-7/8” directional drilling assy: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 4-1/2” Workstring & HWDP will come from Hilcorp. 11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 9-7/8” hole section to 2,839’ MD/ 2,545’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make a wiper trip halfway through the surface hole interval. Make additional wiper trips if hole conditions dictate. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale x Take MWD surveys every stand drilled (60’ intervals). 11.5 9-7/8” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Page 15 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH Surface Interval 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.6 At TD, pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.7 TOH with the drilling assy, handle BHA as appropriate. Page 16 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker TRS 7-5/8” casing running equipment. x Ensure Casing x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 7-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 17 Version 0.0 April 2, 2025 BRU 234-27 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 234-27 Drilling Procedure 13.0 Cement 7-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume 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 234-27 Drilling Procedure Estimated Total Cement Volume: Verified cement calcs. -bjm Page 20 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure Cement Slurry Design: 13.8 Attempt to reciprocate casing during cement pumping as 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. Lead Slurry (2339’ MD to surface)Tail Slurry (2839’ to 2339’ 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 Page 21 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 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 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 234-27 Drilling Procedure 14.0 BOP N/U and Test 14.1 ND diverter line and diverter 14.2 N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test packoff to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Land out test plug (if not installed previously). x Test BOP to 250/3000 psi for 5/10 min. x Test VBR’s with 3-1/2” and 4-1/2” test joints x Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint x Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 9.0 ppg 6% KCL PHPA mud system. 14.7 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. Page 23 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 15.0 Drill 6-3/4” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH and conduct shallow hole test of MWD to confirm all LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 6-3/4” hole section mud program summary: Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT Production Hole 9.0 – 9.2 40-53 15-25 15-25 8.5-9.5 11.0 Page 24 Version 0.0 April 2, 2025 BRU 234-27 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. CBU and condition mud for FIT. 15.12 Conduct FIT to 14.0 ppg EMW. A 13.2# ppg FIT will result in a 20 bbl KTV assuming an 8.65ppg PP and a 9.2ppg MW (swabbed kick). 15.13 Drill 6-3/4” hole section to 6263’ MD / 5916’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ to 1500’ 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 (3355’ to 5058’ 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. 15.14 At TD, pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 15.15 TOH with the drilling assy, laying down drill pipe. LD density and porosity tools. x Perform 10 minute flowchecks prior to tripping off bottom, prior to tripping above the surface shoe, and prior to laying down the BHA. Page 25 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 16.0 Run 3-1/2” Production Liner 16.1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” HYDRIL 563 x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with Baker landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 3-1/2” production liner x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint to the 7-5/8” shoe. Leave the centralizers free floating. 16.5. Continue running 3-1/2” production liner Page 26 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure Page 27 Version 0.0 April 2, 2025 BRU 234-27 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 234-27 Drilling Procedure 17.0 Cement 3-1/2” Production Liner 17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 17.3. Pump 5 bbls spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Page 29 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure Estimated Total Cement Volume: Verified cement calcs. -bjm Page 30 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure Cement Slurry Design: Lead Slurry Tail Slurry (500’ 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 following service company procedure to release from the hanger and set the LTP. 17.14. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.15. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight Page 31 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 17.16. 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). 17.17. 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. 17.18. 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. 17.19. RD cementers and flush equipment. POOH, LDDP and running tool. Backup release from liner hanger (verify with service company rep): 17.20. 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. 17.21. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 17.22. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. 17.23. WOC until the compressive strength hits at least 500 psi before testing casing to 3000 psi and chart for 30 minutes. Page 32 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and nathan.sperry@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 33 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 18.0 3-1/2” Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per service company procedure. 18.3. POOH, and LDDP and polish mill. 18.4. If not completed, test 3-1/2” casing to 3000 psi and chart for 30 minutes Page 34 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 19.0 3-1/2” Tieback Run, ND/NU, RDMO 19.1 PU 3-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 EUE. Ensure any jewelry is picked up per tally. x Install chemical injection mandrel at ~1,500’ MD. 19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 19.3 Circulate inhibited completion fluid. 19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance of seals from no-go. 19.5 Install packoff and test hanger void. 19.6 Test 3-1/2” liner and tieback to 3000 psi and chart for 30 minutes. 19.7 Test 7-5/8” x 3-1/2” annulus to 3000 psi and chart for 30 minutes. 19.8 Install BPV in wellhead 19.9 N/D BOPE 19.10 N/U dry-hole tree and test 19.11 RDMO Hilcorp Rig #147 Page 35 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 20.0 CBL and Nitrogen Operation (Post Rig Work) Pre-Sundry work: 1. Review all approved COAs 2. MIRU E-line and pressure control equipment 3. Log well with CBL tool in 2-1/2” liner (send results to AOGCC to review) 4. RDMO E-line Coiled Tubing Procedure 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3500psi high a. Provide AOGCC 48hr notice for BOP test 3. MU cleanout BHA 4. RIH to PBTD, cleanout well as necessary (based on CBL depth) and swap well over to 8.4 ppg water a. If well is left with 9.4 ppg mud or less, mud may be circulated out with Nitrogen, based on Operations Engineer direction without swapping to water. 5. Once well is clean with 8.4 ppg water a. Reverse circulate water 6. RDMO CT 7. Leave N2 pressure on well when coil is rigged down Submit Completion sundry for perforating well. Attachments to be included 1. Coil Tubing BOP Diagram 2. Standard Nitrogen Operations Page 36 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure Page 37 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure Page 38 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 21.0 Diverter Schematic Page 39 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 22.0 BOP Schematic Page 40 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 23.0 Wellhead Schematic Page 41 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 24.0 Anticipated Drilling Hazards 9-7/8” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 – 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help ensure good cement to surface after running the casing, condition the mud to a YP of 25 – 30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 42 Version 0.0 April 2, 2025 BRU 234-27 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. Sterling A - Beluga F sands are severely depleted. -bjm Page 43 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 25.0 Hilcorp Rig 147 Layout Page 44 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 26.0 FIT/LOT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 45 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 27.0 Choke Manifold Schematic Page 46 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 28.0 Casing Design Information Page 47 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 29.0 6-3/4” Hole Section MASP Page 48 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 30.0 Spider Plot w/ 660’ Radius for SSSV Page 49 Version 0.0 April 2, 2025 BRU 234-27 Drilling Procedure 31.0 Surface Plat (As-Built NAD27 & NAD83) !"##$ % & ' 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000True Vertical Depth (800 usft/in)-800 -400 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 Vertical Section at 182.24° (800 usft/in) 7-5/8" x 9-7/8" 3-1/2" x 6-3/4" 5 0 0 1 0 0 0 1 5 0 0 20002 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 2 6 3 BRU 234-27 wp03 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 1742.99' MD, 1616.91' TVD Start Dir 3º/100' : 1942.99' MD, 1765.54'TVD End Dir : 3009.66' MD, 2711.84' TVD Total Depth : 6263' MD, 5915.75' TVD Sterling A1 Sterling B Sterling C Beluga D Beluga E Beluga F Beluga G Beluga H Beluga I Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: BRU 234-27 87.10 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2627046.48 315923.80 61° 11' 10.9431 N 151° 2' 35.3647 W SURVEY PROGRAM Date: 2025-05-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.50 2839.00 BRU 234-27 wp03 (BRU 234-27) 3_MWD+AX+Sag 2839.00 6263.00 BRU 234-27 wp03 (BRU 234-27) 3_MWD+AX+Sag REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well BRU 234-27, True North Vertical (TVD) Reference:RKB As-Built @ 105.60usft (HEC 147) Measured Depth Reference:RKB As-Built @ 105.60usft (HEC 147) Calculation Method: Minimum Curvature Project:Beluga River Site:BRU I-Pad Well:BRU 234-27 Wellbore:BRU 234-27 Design:BRU 234-27 wp03 CASING DETAILS TVD TVDSS MD Size Name 2545.32 2439.72 2839.00 7-5/8 7-5/8" x 9-7/8" 5915.75 5810.15 6263.00 3-1/2 3-1/2" x 6-3/4" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.50 0.00 0.00 18.50 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 3 800.00 15.00 200.00 794.31 -61.15 -22.26 3.00 200.00 61.97 4 1742.99 42.00 180.00 1616.91 -500.27 -64.86 3.00 -28.87 502.43 End Dir : 1742.99' MD, 1616.91' TVD 5 1942.99 42.00 180.00 1765.54 -634.10 -64.86 0.00 0.00 636.15 Start Dir 3º/100' : 1942.99' MD, 1765.54'TVD 6 3009.66 10.00 180.00 2711.84 -1095.64 -64.86 3.00 180.00 1097.34 End Dir : 3009.66' MD, 2711.84' TVD 7 6263.00 10.00 180.00 5915.75 -1660.58 -64.86 0.00 0.00 1661.85 Total Depth : 6263' MD, 5915.75' TVD -1800 -1700 -1600 -1500 -1400 -1300 -1200 -1100 -1000 -900 -800 -700 -600 -500 -400 -300 -200 -100 0 100 South(-)/North(+) (200 usft/in)-500 -400 -300 -200 -100 0 100 200 300 400 500 600 700 800 900 West(-)/East(+) (200 usft/in) 7-5/8" x 9-7/8" 3-1/2" x 6-3/4" 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 5916 BRU 234-27 wp03 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 1742.99' MD, 1616.91' TVD Start Dir 3º/100' : 1942.99' MD, 1765.54'TVD End Dir : 3009.66' MD, 2711.84' TVD Total Depth : 6263' MD, 5915.75' TVD CASING DETAILS TVD TVDSS MD Size Name 2545.32 2439.72 2839.00 7-5/8 7-5/8" x 9-7/8" 5915.75 5810.15 6263.00 3-1/2 3-1/2" x 6-3/4" Project: Beluga River Site: BRU I-Pad Well: BRU 234-27 Wellbore: BRU 234-27 Plan: BRU 234-27 wp03 WELL DETAILS: BRU 234-27 87.10 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2627046.48 315923.80 61° 11' 10.9431 N 151° 2' 35.3647 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well BRU 234-27, True North Vertical (TVD) Reference:RKB As-Built @ 105.60usft (HEC 147) Measured Depth Reference:RKB As-Built @ 105.60usft (HEC 147) Calculation Method:Minimum Curvature ( $ ) * # $ + ,-. + / /0 ! ! &*$ 12 "## $ %&'()*'+,-& !. .% !/' .0 1. + $ %&'()*'+,-& !. 3 2 + 0 ! 1 1 *) 4 .) 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'')'' '')'' ')'' ')'' 5?:&''<@''<"5 ''<1A5 & ! )22 & *&*)2& ('')! * );* -5@&! )22<"5 &*&*)2&<1A5 & 2 )22 & !*()( * )&' * );* 5?:&''<@&2 )22<"5 &!*()( <1A5 ''2)** !&&); & '2()* * );* -5@''2)**<"5 !&&); <1A5 * *)'' ( 2&()!( & **')(; * );* 1 5B@**<"5 (2&()!(<1A5 !"#$%!&'#!&'#!&'#(&)*+!"#$%#!&'##!&'##!&'#(& ,&*$- *.,%)/0%+1'12'34&5&236.17825'9478&2&190/* ,+: # ;21 ).6'/ +211&2 )2< %*,2 =+2 %+' % !%2> ))!%2<-6 2 ) !"#"$ $ ?+ ?+%& )!&'##!&'#(&04#0@4#*;< %*,. )/< *. )/6 . )/;< %*, )> % !%2> ))!%2<-6 2 ) 4 +211&2 )2< %*,2 ,&*$- *.,%)/)*+!"#$%#!&'##!&'##!&'#(&< %*,. )/ %< 0!"#$%'(()*)'(()*)'(()*(&+( ,"& ,&+ ,-&-- %&.-.,"&/ )'(()*)'(()*)'(()*(&++ ,%& ,&-, ,"&* %&(-%,%& )'(()*)'(()*)'(()*(.&% ,*%& *&+( ,*"&( %&(-,*%&/ ) >. )/?. )/ A$ ?"-&% 0-(+& '(.)*( (123!4! 50-(+& ,0,(& '(.)*( (123!4! 5 6 7 89)& 7 :&/ 7 7 $ &/ ; $#< $) =& 5 :: & 7 752676/7 8 7 6& 0.001.002.003.004.00Separation Factor0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600Measured Depth (800 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:BRU 234-27 NAD 1927 (NADCON CONUS)Alaska Zone 0487.10+N/-S +E/-W Northing EastingLatittudeLongitude0.000.002627046.48 315923.80 61° 11' 10.9431 N 151° 2' 35.3647 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well BRU 234-27, True NorthVertical (TVD) Reference: RKB As-Built @ 105.60usft (HEC 147)Measured Depth Reference:RKB As-Built @ 105.60usft (HEC 147)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-05-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.50 2839.00 BRU 234-27 wp03 (BRU 234-27) 3_MWD+AX+Sag2839.00 6263.00 BRU 234-27 wp03 (BRU 234-27) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600Measured Depth (800 usft/in)BRU 233-27GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.50 To 6263.00Project: Beluga RiverSite: BRU I-PadWell: BRU 234-27Wellbore: BRU 234-27Plan: BRU 234-27 wp03CASING DETAILSTVD TVDSS MD Size Name2545.32 2439.72 2839.00 7-5/8 7-5/8" x 9-7/8"5915.75 5810.15 6263.00 3-1/2 3-1/2" x 6-3/4" 1 Dewhurst, Andrew D (OGC) From:Brad Gorham <brad.gorham@hilcorp.com> Sent:Thursday, 31 July, 2025 09:08 To:Dewhurst, Andrew D (OGC) Cc:Rixse, Melvin G (OGC); Guhl, Meredith D (OGC); Davies, Stephen F (OGC); Joseph Lastufka Subject:RE: [EXTERNAL] MPU H-21 PTD (225-060): Question Andy, You are correct that the I-10 does not fall within the ¼ mile radius, good catch. The other wells - J-40, I-11 and I-11L1 - were included as they do intersect the pool within a ¼ miles radius of the proposed H-21 well. Appreciate you updaƟng the informaƟon with regard to D-14. Let me know if you have any further quesƟons or concerns. Thanks, Brad From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Wednesday, July 30, 2025 10:59 AM To: Brad Gorham <brad.gorham@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: [EXTERNAL] MPU H-21 PTD (225-060): Question Brad, I’m completing my review of the MPU H-21 PTD and have a question: x Looking over the AOR, it appears to me that the following wells do not intersect the injection zone within the ¼-mile radius. Would you please conﬁrm that? o MPU J-40 o MPU I-10 o MPU I-11 o MPU I-11L1 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 Also, since we received your note about changing the rig from the D-19 to D-14 before the PTD was issued, I have inserted the relevant attachments into this PTD. That way, we won’t need the separate 403. This will also make the record clearer/cleaner. Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. 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Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. STERLING-BELUGA GAS BRU 234-27 Though this well is being drilled on a new pad, it is only ~1/2-mile from an offset well with mud log (BRU 212-26). So it would not significantly add to the geologic knowledge of the area. Requirement to acquire mud log and submit cuttings is waived as per 20 AAC 25.071(c). -A.Dewhurst 30JUL25 BELUGA RIVER 225-065 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 234-27Initial Class/TypeDEV / PENDGeoArea820Unit50220On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250650Field & Pool:BELUGA RIVER, STRLG-BELUGA GAS - 92500NA1Permit fee attachedYesAKA0296572Lease number appropriateYes3Unique well name and numberYesBELUGA RIVER, STRLG-BELUGA GAS - 92500 - governed by CO 8024Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18Conductor string providedYes19Surface casing protects all known USDWsYes20CMT vol adequate to circulate on conductor & surf csgYes21CMT vol adequate to tie-in long string to surf csgYes22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYes26Adequate wellbore separation proposedYes27If diverter required, does it meet regulationsYes28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP 2071 psi, BOP rated to 5kpsi (BOP test to 3000 psi)30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNo33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)YesH2S not anticipated based on offset wells.35Permit can be issued w/o hydrogen sulfide measuresYesMax pore pressure anticipated to be 8.65 ppg EMW, though may sands severlely under-pressured (2.25 ppg EMW36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate30-Jul-25ApprBJMDate25-Jul-25ApprADDDate30-Jul-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 7/31/2025