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Home My WebLink About225-0881. 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): 6,144' N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Chad Helgeson, Operations Engineer Contact Email:chelgeson@hilcorp.com Contact Phone: 907-777-8405 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0058810 / ADL0063048 225-088 50-283-20209-00-00 Hilcorp Alaska, LLC Proposed Pools: 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 9.3# / L-80 TVD Burst 2,327' 10,160psi 2,209' 120' 2,493' MD 7-5/8" See Attached Schematic 2,980psi 6,890psi 120'120' February 14, 2026 Tieback 3-1/2" 6,142' Perforation Depth MD (ft): 16" Pretty Creet Unit (PCU) D-1120 AAC 25.055 Same 5,718'3-1/2" ~1507psi Pretty Creek Undefined Gas Size 2,493' Other: See Attached Schematic 3,849' 5,420 & 5,462 Length LTP; N/A 2,293' MD/ 2,046' TVD ; N/A 5,720' 5,420' 5,006' 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 326-053 By Grace Chistianson at 8:18 am, Jan 26, 2026 A.Dewhurst 26JAN26 DSR-2/2/26 10-404 Dump bail 25' of sand on top of existing CIBP at 5420' MD before adding additional perfs. Tag CIBP (or fill) before dumping cement to verify location of base of cement. BJM 2/6/26JLC 2/6/2026 02/06/26 Well Prognosis Well Name: PCU-11 API Number: 50-283-20209-00-00 Current Status: Producing Gas Well Permit to Drill Number: 225-088 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: 1700 psi @ 3864 TVD (Based on 0.44 psi/ft gradient) Max. Potential Surface Pressure: 1507 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.728 psi/ft using 14.0 ppg EMW FIT at the 7-5/8 surface casing shoe Shallowest Potential Perf TVD: MPSP/(0.728-0.05) = 2018 psi / 0.678 = 2976 TVD Well Status: Online producing well Brief Well Summary PCU D-11 was drilled in October 2025 and brought online in the Sterling C5 Sand. The current open sands were originally correlated as Beluga D Sands from the original discovery well. After meeting with AOGCC in early December to show a new regional correlation with all 4 newly drilled Pretty Creek wells, it was agreed that the current open zone should have been correlated as a Sterling sand and would be classified in the Sterling Pool. Therefore all current sands and proposed sands would be in the Sterling Pool and allowed to be commingled. The well has seen stable production around 1 mmscfd over the last month, but is declining and would like to add more rate with the proposed perforations. Wellbore Conditions: - Flowing at 1,003 mcf @ 832 psi - Max Inclination 38° at 1,682 MD - Max DLS °/100 6° at 1,305 MD Procedure: 1. Review all approved COAs 2. MIRU E-Line and pressure control equipment 3. PT lubricator to 250 psi low / 2,500 psi high 4. 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 ST X3 ±3,629' ±3,645' ±3,241' ±3,257' ±16' ST C3 ±4,142' ±4,151' ±3,747' ±3,756' ±9' ST C4Lwr ±4,172' ±4,181' ±3,777' ±3,786' ±9' a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations 5. RDMO Attachments: 1. Current Schematic 2. Proposed Schematic Updated by DMA 01-16-26 SCHEMATIC Pretty Creek Unit PCU D-11 PTD: 255-088 API: 50-283-20209-00-00 PBTD = 5,420 MD / TVD = 5,006 TD = 6,144 MD / TVD = 5,720 RKB to GL = 20.68 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875Surf 2,493 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.9922,2936,142 3-1/2Production Tieback 9.3 L-80 EUE 2.992Surf 2,327 2/3 16 7-5/8 9-7/8 hole 3-1/2 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 150 bbl (344 sx) 12 ppg Type I II lead cement followed by 23 bbls (112 sx) 15.8 Type I II tail cement. Bumped plug @ 107 bbls. 64 bbls of lead cement to surface, 0 bbls of losses during job. 3-1/2 147 bbl (371 sx) 12 ppg lead cement followed by 24 bbl (110 sx) 15.3 tail cement. Bumped plug @ 59 bbls. 30 bbls of returned spacer & 53 bbls of lead cement to surface, 0 bbls of losses during job: TOC @ 2322 based on CBL on 10/16/25 6-3/4 hole JEWELRY DETAIL No. Depth Item 1 Cactus CTF-ONE-CTL 11 x 4-1/2 Hanger w/ 4 Type H BPV profile 2 2,293YJ Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 3 2,327Bullet Seal assembly 1.32 off no-go at 2,316 4 5,420CIBP 5 5,462CIBP Notes: 10 Short jt w/ RA tags 5630 10 Short joints 4156, 3706 Deviation 38° @ 1682, Max dogleg 6° @ 1,305 Geology Geologist John Salsbury adjusted formation tops met with AOGCC on Dec 3 to communicate the new interpretation. Previous reports may have had different perf interval names. The correct sands are listed on this schematic. JS/CJD (12/5/25) 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status ST C5 4,222'4,231'3,8263,8359'1/10/26 Open ST C5 4,222' 4,231'3,826 3,8359' 10/29/25 Open ST C5 4,250' 4,260' 3,854' 3,864' 10' 1/10/26 Open ST C5 4,250' 4,260' 3,854' 3,864' 10' 10/26/25 Open BEL H7 5,435' 5,455'5,021 5,04120' 10/24/25 Isolated BEL H7 5,469' 5,474'5,055 5,0605' 10/24/25 Isolated BEL H9 5,583' 5,592'5,167 5,1769' 10/24/25 Isolated RA Pup 5,630 H7 - H9 ST C5 4 5 Updated by CAH 1-20-26 PROPOSED Pretty Creek Unit PCU D-11 PTD: 255-088 API: 50-283-20209-00-00 PBTD = 5,420 MD / TVD = 5,006 TD = 6,144 MD / TVD = 5,720 RKB to GL = 20.68 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875Surf 2,493 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.9922,2936,142 3-1/2Production Tieback 9.3 L-80 EUE 2.992Surf 2,327 2/3 16 7-5/8 9-7/8 hole 3-1/2 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 150 bbl (344 sx) 12 ppg Type I II lead cement followed by 23 bbls (112 sx) 15.8 Type I II tail cement. Bumped plug @ 107 bbls. 64 bbls of lead cement to surface, 0 bbls of losses during job. 3-1/2 147 bbl (371 sx) 12 ppg lead cement followed by 24 bbl (110 sx) 15.3 tail cement. Bumped plug @ 59 bbls. 30 bbls of returned spacer & 53 bbls of lead cement to surface, 0 bbls of losses during job: TOC @ 2322 based on CBL on 10/16/25 6-3/4 hole JEWELRY DETAIL No. Depth Item 1 Cactus CTF-ONE-CTL 11 x 4-1/2 Hanger w/ 4 Type H BPV profile 2 2,293YJ Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 3 2,327Bullet Seal assembly 1.32 off no-go at 2,316 4 5,420CIBP 5 5,462CIBP Notes: 10 Short jt w/ RA tags 5630 10 Short joints 4156, 3706 Deviation 38° @ 1682, Max dogleg 6° @ 1,305 Geology Geologist John Salsbury adjusted formation tops met with AOGCC on Dec 3 to communicate the new interpretation. Previous reports may have had different perf interval names. The correct sands are listed on this schematic. JS/CJD (12/5/25) 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status ST X3 ±3,629'±3,645'±3,241'±3,257'±16'TBD Future ST C3 ±4,142' ±4,151' ±3,747' ±3,756' ±9' TBD Future ST C4Lwr ±4,172' ±4,181' ±3,777' ±3,786' ±9' TBD Future ST C5 4,222' 4,231'3,826 3,8359' 1/10/26 Open ST C5 4,222' 4,231'3,826 3,8359' 10/29/25 Open ST C5 4,250' 4,260' 3,854' 3,864' 10' 1/10/26 Open ST C5 4,250' 4,260' 3,854' 3,864' 10' 10/26/25 Open BEL H7 5,435' 5,455'5,021 5,04120' 10/24/25 Isolated BEL H7 5,469' 5,474'5,055 5,0605' 10/24/25 Isolated BEL H9 5,583' 5,592'5,167 5,1769' 10/24/25 Isolated RA Pup 5,630 H7 - H9 ST C5 4 5 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): 6,144' N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Chad Helgeson, Operations Engineer Contact Email:chelgeson@hilcorp.com Contact Phone: 907-777-8405 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0058810 / ADL0063048 225-088 50-283-20209-00-00 Hilcorp Alaska, LLC Proposed Pools: 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 9.3# / L-80 TVD Burst 2,327' 10,160psi 2,209'2,493' 120' 2,493' MD 7-5/8" See Attached Schematic 2,980psi 6,890psi 120'120' January 14, 2026 Tieback 3-1/2" 6,142' Perforation Depth MD (ft): 16" Pretty Creet Unit (PCU) D-1120 AAC 25.055 Same 5,718'3-1/2" 1507 Pretty Creek Undefined Gas Size Other: See Attached Schematic 3,849' 5,420 & 5,462 Length LTP; N/A 2,293' MD/ 2,046' TVD ; N/A 5,720' 5,420' 5,006' No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.12.29 15:32:22 - 09'00' Noel Nocas (4361) 325-776 By Grace Christianson at 4:26 pm, Dec 29, 2025 BJM 1/5/26 SFD 12/31/2025 DSR-12/30/25 Perforate Dump bail 25' of cement on top of existing CIBP @ 5420' MD before setting any additional plugs in the well. 10-404 JLC 1/5/2026 01/05/26 Well Prognosis Well Name:PCU-11 API Number:50-283-20209-00-00 Current Status:Producing Gas Well Permit to Drill Number:225-088 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:1700 psi @ 3864 TVD (Based on 0.44 psi/ft gradient) Max. Potential Surface Pressure:1507 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient:0.728 psi/ft using 14.0 ppg EMW FIT at the 7-5/8 surface casing shoe Shallowest Potential Perf TVD:MPSP/(0.728-0.05) = 2018 psi / 0.678 = 2976 TVD Well Status:Online producing well Brief Well Summary PCU D-11 was drilled in October 2025 and brought online in the Sterling C5 Sand. The current open sands were originally correlated as Beluga D Sands from the original discovery well. After meeting with AOGCC in early December to show a new regional correlation with all 4 newly drilled Pretty Creek wells, it was agreed that the current open zone should have been correlated as a Sterling sand and would be classified in the Sterling Pool. Therefore all current sands and proposed sands would be in the Sterling Pool and allowed to be commingled (if necessary). The well has seen stable production and even slight increasing from 1 mmscfd to 1.1 mmscfd over the last month. The objective of this work is to reperforate the Sterling C5 open sands to remove any potential skin and retest. If desired production is not achieved during these perforations, then the additional sterling sands may be added. Wellbore Conditions: - Flowing at 1,170 mcf @ 821 psi - Max Inclination 38° at 1,682 MD - Max DLS °/100 6° at 1,305 MD Procedure: 1. Review all approved COAs 2. MIRU E-Line and pressure control equipment 3. PT lubricator to 250 psi low / 2,500 psi high 4. 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 a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations 5. RDMO Well Prognosis Attachments: 1. Current Schematic 2. Proposed Schematic Updated by CJD 12/15/25 Schematic Pretty Creek Unit PCU D-11 PTD: 255-088 API: 50-283-20209-00-00 PBTD = 5,420 MD / TVD = 5,006 TD = 6,144 MD / TVD = 5,720 RKB to GL = 20.68 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8"Surf Csg 29.7 P-110 GBCD 6.875Surf 2,493 3-1/2"Prod Lnr 9.2 L-80 Hyd 563 2.9922,2936,142 3-1/2Production Tieback 9.3 L-80 EUE 2.992Surf 2,327 2/3 16 7-5/8 9-7/8 hole 3-1/2 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 150 bbl (344 sx) 12 ppg Type I II lead cement followed by 23 bbls (112 sx) 15.8 Type I II tail cement. Bumped plug @ 107 bbls. 64 bbls of lead cement to surface, 0 bbls of losses during job. 3-1/2 147 bbl (371 sx) 12 ppg lead cement followed by 24 bbl (110 sx) 15.3 tail cement. Bumped plug @ 59 bbls. 30 bbls of returned spacer & 53 bbls of lead cement to surface, 0 bbls of losses during job: TOC @ 2322 based on CBL on 10/16/25 6-3/4 hole JEWELRY DETAIL No. Depth Item 1 Cactus CTF-ONE-CTL 11 x 4-1/2 Hanger w/ 4 Type H BPV profile 2 2,293YJ Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 3 2,327Bullet Seal assembly 1.32 off no-go at 2,316 4 5,420CIBP 5 5,462CIBP Notes: 10 Short jt w/ RA tags 5630 10 Short joints 4156, 3706 Deviation 38° @ 1682, Max dogleg 6° @ 1,305 Geology Geologist John Salsbury adjusted formation tops met with AOGCC on Dec 3 to communicate the new interpretation. Previous reports may have had different perf interval names. The correct sands are listed on this schematic. JS/CJD (12/5/25) 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status ST C5 4,222' 4,231'3,826 3,8359' 10/29/25 Open ST C5 4,250' 4,260' 3,854' 3,864' 10' 10/26/25 Open BEL H7 5,435' 5,455'5,021 5,04120' 10/24/25 Isolated BEL H7 5,469' 5,474'5,055 5,0605' 10/24/25 Isolated BEL H9 5,583' 5,592'5,167 5,1769' 10/24/25 Isolated RA Pup 5,630 H7 - H9 ST C5 4 5 Updated by CAH 12/29/25 PROPOSED Pretty Creek Unit PCU D-11 PTD: 255-088 API: 50-283-20209-00-00 PBTD = 5,420 MD / TVD = 5,006 TD = 6,144 MD / TVD = 5,720 RKB to GL = 20.68 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8" Surf Csg 29.7 P-110 GBCD 6.875 Surf 2,493 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 2.992 2,293 6,142 3-1/2 Production Tieback 9.3 L-80 EUE 2.992 Surf 2,327 2/3 16 7-5/8 9-7/8 hole 3-1/2 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 150 bbl (344 sx) 12 ppg Type I II lead cement followed by 23 bbls (112 sx) 15.8 Type I II tail cement. Bumped plug @ 107 bbls. 64 bbls of lead cement to surface, 0 bbls of losses during job. 3-1/2 147 bbl (371 sx) 12 ppg lead cement followed by 24 bbl (110 sx) 15.3 tail cement. Bumped plug @ 59 bbls. 30 bbls of returned spacer & 53 bbls of lead cement to surface, 0 bbls of losses during job: TOC @ 2322 based on CBL on 10/16/25 6-3/4 hole JEWELRY DETAIL No. Depth Item 1 Cactus CTF-ONE-CTL 11 x 4-1/2 Hanger w/ 4 Type H BPV profile 2 2,293 YJ Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 3 2,327 Bullet Seal assembly 1.32 off no-go at 2,316 4 5,420 CIBP 5 5,462 CIBP Notes: 10 Short jt w/ RA tags 5630 10 Short joints 4156, 3706 Deviation 38° @ 1682, Max dogleg 6° @ 1,305 Geology Geologist John Salsbury adjusted formation tops met with AOGCC on Dec 3 to communicate the new interpretation. Previous reports may have had different perf interval names. The correct sands are listed on this schematic. JS/CJD (12/5/25) 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status ST X3 ±3,629' ±3,645' ±3,241' ±3,257' ±16' TBD Future ST C3 ±4,142' ±4,151' ±3,747' ±3,756' ±9' TBD Future ST C4Lwr ±4,172' ±4,181' ±3,777' ±3,786' ±9' TBD Future ST C5 ±4,222' ±4,231' ±3,826 ±3,835 ±9' TBD Future ST C5 4,222' 4,231' 3,826 3,835 9' 10/29/25 Open ST C5 ±4,222' ±4,231' ±3,826 ±3,835 ±9' TBD Future ST C5 4,250' 4,260' 3,854' 3,864' 10' 10/26/25 Open BEL H7 5,435' 5,455' 5,021 5,041 20' 10/24/25 Isolated BEL H7 5,469' 5,474' 5,055 5,060 5' 10/24/25 Isolated BEL H9 5,583' 5,592' 5,167 5,176 9' 10/24/25 Isolated RA Pup 5,630 H7 - H9 ST C5 4 5 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/20/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251120 Well API # PTD # Log Date Log Company Log Type AOGCC E-Set# BCU 23 50133206350000 214093 10/14/2025 AK E-LINE PPROF T41129 BR 09-86 50733204480000 193062 10/28/2025 AK E-LINE Perf T41130 BRU 213-26T 50283202040000 225038 10/30/2025 AK E-LINE Perf T41131 END 1-57 50029218730000 188114 11/16/2025 READ PressTempSurvey T41132 END 2-28B 50029218470200 203006 11/15/2025 READ PressTempSurvey T41133 END 2-30B 50029222280200 208187 11/18/2025 READ PressTempSurvey T41134 END 2-52 50029217500000 187092 10/28/2025 HALLIBURTON LDL T41135 KALOTSA 10 50133207320000 224147 11/7/2025 AK E-LINE Perf T41136 MPF-92 50029229240000 198193 11/8/2025 READ CaliperSurvey T41137 MPH-01 50029220610000 190086 11/7/2025 READ CaliperSurvey T41138 MPI-14 50029232140000 204119 11/8/2025 READ CaliperSurvey T41139 MPU H-01 50029220610000 190086 11/4/2025 AK E-LINE Drift/CBL/Caliper/Packer T41138 MPU I-14 50029232140000 204119 11/8/2025 AK E-LINE RigAssist T41139 MPU J-02 50029220710000 190096 11/6/2025 AK E-LINE Caliper/Gyro T41140 NCIU A-07A 50883200270100 225094 11/1/2025 AK E-LINE CBL T41141 NCIU A-07A 50883200270100 225094 11/4/2025 AK E-LINE Perf T41141 ODSN-01A 50703206480100 216008 10/24/2025 HALLIBURTON PACKER T41142 ODSN-25 50703206560000 212030 10/23/2025 HALLIBURTON PACKER T41143 ODSN-26 50703206420000 211121 11/4/2025 HALLIBURTON PERF T41144 PBU 02-10B 50029201630200 200064 10/27/2025 HALLIBURTON RBT T41145 PBU A-24B 50029207430200 225067 10/20/2025 BAKER MRPM T41146 PBU B-05E 50029202760500 225093 10/23/2025 HALLIBURTON RBT T41147 PBU B-05E 50029202760500 225093 10/23/2025 BAKER MRPM T41147 PBU B-20A 50029208420100 212026 10/16/2025 BAKER SPN T41148 PBU F-18B 50029206360200 225099 11/5/2025 HALLIBURTON RBT-COILFLAG T41149 PCU D-10 50283202080000 225082 10/31/2025 AK E-LINE Patch T41150 PCU D-10 50283202080000 225082 10/17/2025 AK E-LINE Perf T41150 PCU D-10 50283202080000 225082 10/22/2025 AK E-LINE Perf T41150 PCU D-10 50283202080000 225082 10/29/2025 AK E-LINE Perf T41150 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.20 13:27:19 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PCU D-11 50283202090000 225088 10/16/2025 AK E-LINE CBL T41151 PCU D-11 50283202090000 225088 10/24/2025 AK E-LINE Perf T41151 Please include current contact information if different from above. T41151PCU D-11 50283202090000 225088 10/16/2025 AK E-LINE CBL PCU D-11 50283202090000 225088 10/24/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.20 13:27:31 -09'00' Hilctarp Alaska UX. Date: 11/ 12/2025 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 To: Alaska Oil & Gas Conservation Commission Petroleum Geology Assistant 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PCU D-11 PTD: 225-088 API: 50-283-20209-00-00 Washed and Dried Well Samples (10/08/2025) 30' Frequency B Set (3 Boxes): WELT. 13©X SAMPLE WERVAL (FEET 1 MD) PCU D-11 BOX 1 OF 3 2490' - 3900' MD PCU D-11 BOX 2 OF 3 3900' - 5310' MD PCU D-11 BOX 3 OF 3 5310' — 6144' MD Please include current contact information if different from above. aas-o8�) NOV 12 2U25 lggb Please acknowledge receipt by signing and returning one copy of this transmittal. Received ey� Date: ,� ►1 Zs 2� 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: 10/27/2025 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Well: PCU D-11 PTD: 225-088 API: 50-283-20209-00-00 FINAL LWD + PixStar FORMATION EVALUATION LOGS (10/02/2025 to 10/08/2025) ROP; iCruise, DGR and BaseStar Gamma Ray ADR and StrataStar Resistivity LithoStar Density and Thermal Neutron PixStar Ultrasonic Caliper Imager Pressure While Drilling (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey LWD + PWD Folder Contents: PixStar Folder Contents: Please include current contact information if different from above. 225-088 T41042 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.28 10:18:20 -08'00' David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: Date: 10/27/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL Well: PCU D-11 PTD: 225-088 API: 50-283-20209-00-00 FINAL MUDLOGS - EOW DRILLING REPORTS (10/05/2025 to 10/08/2025) 1. FINAL EOW REPORT 2. DAILY REPORTS 3. DIGITAL DATA (LAS) 4. LITHOLOGY DESCRIPTIONS 5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS) Formation Log LWD Combo Log Gas Ratio Log Drilling Dynamics Log SFTP Transfer - Main Folder Contents: Please include current contact information if different from above. 225-088 T41039 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.27 15:04:26 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz Subject:RE: PCU D-11 (PTD#225-088) Cement bond log Date:Thursday, October 23, 2025 10:09:00 AM Chad, Hilcorp has approval to proceed with the perforating per sundry 325-645. I see now that Scott had sent an email with the CBL. I missed that when reviewing the sundry. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Thursday, October 23, 2025 9:58 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: PCU D-11 (PTD#225-088) Cement bond log Bryan, Thanks for getting us the Sundry for PCU D-11. I see on the sundry it says we need to submit the CBL and get approval to perf before we can perf. I was under the impression that Scott sent you the CBL last week, so wasn’t sure if you saw it or not. Attached is the CBL for PCU D-11 showing that we have cement up to the liner top at 2322’. Do we have approval to perforate D-11? 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 theindividual 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. 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: 10/27/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL Well: PCU D-11 PTD: 225-088 API: 50-283-20209-00-00 FINAL MUDLOGS - EOW DRILLING REPORTS (10/05/2025 to 10/08/2025) 1. FINAL EOW REPORT 2. DAILY REPORTS 3. DIGITAL DATA (LAS) 4. LITHOLOGY DESCRIPTIONS 5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS) Formation Log LWD Combo Log Gas Ratio Log Drilling Dynamics Log SFTP Transfer - Main Folder Contents: Please include current contact information if different from above. 225-088 T41039 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.27 15:04:26 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz Subject:RE: PCU D-11 (PTD#225-088) Cement bond log Date:Thursday, October 23, 2025 10:09:00 AM Chad, Hilcorp has approval to proceed with the perforating per sundry 325-645. I see now that Scott had sent an email with the CBL. I missed that when reviewing the sundry. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Thursday, October 23, 2025 9:58 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: PCU D-11 (PTD#225-088) Cement bond log Bryan, Thanks for getting us the Sundry for PCU D-11. I see on the sundry it says we need to submit the CBL and get approval to perf before we can perf. I was under the impression that Scott sent you the CBL last week, so wasn’t sure if you saw it or not. Attached is the CBL for PCU D-11 showing that we have cement up to the liner top at 2322’. Do we have approval to perforate D-11? 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 theindividual 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. 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 Completon, 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): 6,144' N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Chad Helgeson, Operations Engineer Contact Email:chelgeson@hilcorp.com Contact Phone: 907-777-8405 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng See Attached Schematic 3,849' N/A Length LTP; N/A 2,292' MD/ 2,046' TVD ; N/A 5,720' 6,142' 5,718' 16" Pretty Creet Unit (PCU) D-1120 AAC 25.055 Same 5,718'3-1/2" 2018 Pretty Creek Undefined Gas Size October 21, 2025 Tieback 3-1/2" 6,142' Perforation Depth MD (ft): See Attached Schematic 2,980psi 6,890psi 120'120' 2,493' 120' 2,493' MD 7-5/8" 9.2# / L-80 TVD Burst 2,326' 10,160psi 2,209' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 58810 / ADL 63048 225-088 50-283-20209-00-00 Hilcorp Alaska, LLC Proposed Pools: 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY m n P s 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 9:32 am, Oct 20, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.10.17 14:58:13 - 08'00' Noel Nocas (4361) 325-645 DSR-10/22/25 Submit CBL and obtain approval from AOGCC before perforating. BJM 10/20/25 Undefined Gas Perforate 10-407 SFD 10/21/2025 10/23/25 Well Prognosis Well Name: PCU-11 API Number: 50-283-20209-00-00 Current Status: New Drill Well Permit to Drill Number: 225-088 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: 2277 psi @ 5176 TVD (Based on 0.44 psi/ft gradient) Max. Potential Surface Pressure:2018 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.728 psi/ft using 14.0 ppg EMW FIT at the 7-5/8 surface casing shoe Shallowest Potential Perf TVD: MPSP/(0.728-0.05) = 2018 psi / 0.678 = 2976 TVD Well Status: New Drill Well Initial Completion Brief Well Summary PCU D-11 is the second well drilled on Diamond pad and the 3rd of three grass roots well to be drilled in the 2025 Pretty Creek drilling campaign targeting the Sterling and Beluga sands. The objective of this sundry is to perforate and flow the new drill well. Wellbore Conditions: - Max Inclination 38° at 1,682 MD - Max DLS °/100 6° at 1,305 MD - T & IA PT to 3000 psi (30 min) on 10/10/25 - Min ID- 2.992 3-1/2 tubing/liner - Liner is full of ~9.7 ppg 6% KCl mud - Tubing and IA are displaced to 8.4 ppg CIW Work to be completed on PTD# 225-088 Step 20.0: Eline Run CBL o Send results to AOGCC to review prior to perforating CT Mud displacement & CT N2 blowdown Procedure: 1. Review all approved COAs 2. MIRU E-Line and pressure control equipment 3. PT lubricator to 250 psi low / 2,500 psi high 4. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 5. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: Below are proposed targeted sands in order of testing (bottom/up), but additional sands may be added/removed depending on results of these perfs, between the proposed top and bottom perfs Sands Top MD Btm MD Top TVD Btm TVD Amt ST X3 ±3,629' ±3,645' ±3,241' ±3,257' ±16' ST C3 ±4,142' ±4,151' ±3,747' ±3,756' ±9' ST C5 ±4,172' ±4,181' ±3,777' ±3,786' ±9' BEL D3 ±4,222' ±4,231' ±3,826' ±3,835' ±9' 0.05 psi/ft gas gradient Well Prognosis BEL D6 ±4,271' ±4,281' ±3,874' ±3,884' ±9' BEL D6 ±4,296' ±4,300' ±3,899' ±3,903' ±5' BEL D6 ±4,309' ±4,319' ±3,912' ±3,922' ±10' BEL D6 ±4,388' ±4,406' ±3,990' ±4,007' ±18' BEL E6 ±4,465' ±4,470' ±4,065' ±4,070' ±5' BEL E6 ±4,476' ±4,487' ±4,076' ±4,087' ±11' BEL E6 ±4,529' ±4,540' ±4,128' ±4,139' ±11' BEL F7 ±4,855' ±4,859' ±4,450' ±4,453' ±4' BEL F10 ±4,878' ±4,881' ±4,472' ±4,475' ±3' BEL H7 ±5,435' ±5,455' ±5,021' ±5,041' ±20' BEL H7 ±5,469' ±5,474' ±5,055' ±5,060' ±5' BEL H9 ±5,583' ±5,592' ±5,167' ±5,176' ±9' 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 6. RDMO 7. Turn well over to production & flow test well 8. Test SVS as necessary once well has reached stable flow rates a. Notify state 24 hrs prior to testing within 5 days of stable production Attachments: 1. Current Schematic 2. Proposed Schematic 3. Standard Well Procedure N2 Operations Updated by SRW 10/14/25 Schematic Pretty Creek Unit PCU D-11 PTD: 255-088 API: 50-283-20209-00-00 PBTD = 6,142 MD / TVD = 5,718 TD = 6,144 MD / TVD = 5,720 RKB to GL = 20.68 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875Surf 2,493 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 /GB Acme 2.992 2,293 6,142 3-1/2Production Tieback 9.2 L-80 EUE 2.992Surf 2,326 2/3 16 7-5/8 9-7/8 hole 3-1/2 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 150 bbl (344 sx) 12 ppg Type I II lead cement followed by 23 bbls (112 sx) 15.3 Type I II tail cement. Bumped plug @ 114 bbls. 60 bbls of returned spacer & 62 bbls of lead cement to surface, 0 bbls of losses during job. 3-1/2 147 bbl (371 sx) 12 ppg lead cement followed by 24 bbl (110 sx) 15.3 tail cement. Bumped plug @ 62 bbls. 30 bbls of returned spacer & 53 bbls of lead cement to surface, 0 bbls of losses during job: TOC @ xxxx based on CBL on 10/x/25 6-3/4 hole JEWELRY DETAIL No. Depth Item 1 Cactus CTF-ONE-CTL 11 x 4-1/2 Hanger w/ 4 Type H BPV profile 2 2,292YJ Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 3 2,327Bullet Seal assembly 1.32 off no-go at 2,316 Notes: 10 Short jt w/ RA tags 5630 10 Short joints 4156, 3706 Deviation 38° @ 1682, Max dogleg 6° @ 1,305 1 RA Pup 5,630 Updated by SRW 10/14/25 Proposed Schematic Pretty Creek Unit PCU D-11 PTD: 255-088 API: 50-283-20209-00-00 PBTD = 6,142 MD / TVD = 5,718 TD = 6,144 MD / TVD = 5,720 RKB to GL = 20.68 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8"Surf Csg 29.7 L-80 GBCD 6.875Surf 2,493 3-1/2" Prod Lnr 9.2 L-80 Hyd 563 /GB Acme 2.992 2,293 6,142 3-1/2Production Tieback 9.2 L-80 EUE 2.992Surf 2,326 2/3 16 7-5/8 9-7/8 hole 3-1/2 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 150 bbl (344 sx) 12 ppg Type I II lead cement followed by 23 bbls (112 sx) 15.3 Type I II tail cement. Bumped plug @ 114 bbls. 60 bbls of returned spacer & 62 bbls of lead cement to surface, 0 bbls of losses during job. 3-1/2 147 bbl (371 sx) 12 ppg lead cement followed by 24 bbl (110 sx) 15.3 tail cement. Bumped plug @ 62 bbls. 30 bbls of returned spacer & 53 bbls of lead cement to surface, 0 bbls of losses during job: TOC @ xxxx based on CBL on 10/x/25 6-3/4 hole JEWELRY DETAIL No. Depth Item 1 Cactus CTF-ONE-CTL 11 x 4-1/2 Hanger w/ 4 Type H BPV profile 2 2,292YJ Ranger Liner Hanger & Scout Pkr 5.75 ID on Upper polish 3 2,327Bullet Seal assembly 1.32 off no-go at 2,316 Notes: 10 Short jt w/ RA tags 5630 10 Short joints 4156, 3706 Deviation 38° @ 1682, Max dogleg 6° @ 1,305 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Amt Date Status ST X3 ±3,629'±3,645'±3,241'±3,257'±16'TBD Proposed ST C3 ±4,142'±4,151'±3,747'±3,756'±9'TBD Proposed ST C5 ±4,172'±4,181'±3,777'±3,786'±9'TBD Proposed BEL D3 ±4,222'±4,231'±3,826'±3,835'±9'TBD Proposed BEL D6 ±4,271'±4,281'±3,874'±3,884'±9'TBD Proposed BEL D6 ±4,296'±4,300'±3,899'±3,903'±5'TBD Proposed BEL D6 ±4,309'±4,319'±3,912'±3,922'±10'TBD Proposed BEL D6 ±4,388' ±4,406' ±3,990' ±4,007' ±18' TBD Proposed BEL E6 ±4,465' ±4,470' ±4,065' ±4,070' ±5' TBD Proposed BEL E6 ±4,476' ±4,487' ±4,076' ±4,087' ±11' TBD Proposed BEL E6 ±4,529' ±4,540' ±4,128' ±4,139' ±11' TBD Proposed BEL F7 ±4,855' ±4,859' ±4,450' ±4,453' ±4' TBD Proposed BEL F10 ±4,878' ±4,881' ±4,472' ±4,475' ±3' TBD Proposed BEL H7 ±5,435' ±5,455' ±5,021' ±5,041' ±20' TBD Proposed BEL H7 ±5,469' ±5,474' ±5,055' ±5,060' ±5' TBD Proposed BEL H9 ±5,583' ±5,592' ±5,167' ±5,176' ±9' TBD Proposed RA Pup 5,630 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. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION DIVERTER Test Report for: Reviewed By: P.I. Suprv Comm ________PRETTY CK UNIT D-11 JBR 11/14/2025 MISC. INSPECTIONS: GAS DETECTORS: DIVERTER SYSTEM:MUD SYSTEM: P/F P/F P/F Alarm Visual Alarm Visual Time/Pressure Size Number of Failures:0 Remarks:Test with 4-1/2" TJ TEST DATA Rig Rep:Jon Van EvraOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley Contractor/Rig No.:Hilcorp 147 PTD#:2250880 DATE:10/1/2025 Well Class:DEV Inspection No:divKPS251002115109 Inspector Kam StJohn Inspector Insp Source Related Insp No: Test Time:1 ACCUMULATOR SYSTEM: Location Gen.:P Housekeeping:P Warning Sign P 24 hr Notice:P Well Sign:P Drlg. Rig.P Misc:NA Methane:P P Hydrogen Sulfide:P P Gas Detectors Misc:0 NA Designed to Avoid Freeze-up?P Remote Operated Diverter?P No Threaded Connections?P Vent line Below Diverter?P Diverter Size:21.25 P Hole Size:9.88 P Vent Line(s) Size:16 P Vent Line(s) Length:127 P Closest Ignition Source:85 P Outlet from Rig Substructure:106 P Vent Line(s) Anchored:P Turns Targeted / Long Radius:P Divert Valve(s) Full Opening:P Valve(s) Auto & Simultaneous: Annular Closed Time:23 P Knife Valve Open Time:9 P Diverter Misc:0 NA Systems Pressure:P3100 Pressure After Closure:P1500 200 psi Recharge Time:P23 Full Recharge Time:P121 Nitrogen Bottles (Number of):P4 Avg. Pressure:P2375 Accumulator Misc:NA0 P PTrip Tank: P PMud Pits: P PFlow Monitor: 0 NAMud System Misc:           Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Pretty Creek Unit Field, Undefine Gas, PCU D-11 Hilcorp Alaska, LLC Permit to Drill Number: 225-088 REVISED Surface Location: 1404' FNL, 925' FWL, Sec 27, T14N, R9W, SM, AK Bottomhole Location: 2623' FNL, 431' FEL, Sec 28, T14N, R9W, SM, AK Dear Mr. McLaughlin: Enclosed is the approved REVISED application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 30th day of September 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.09.30 09:20:53 -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: 6,014' TVD: 5,565' 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): 63.9' 15. Distance to Nearest Well Open Surface: x-345667 y-2660306 Zone-4 45.4' to Same Pool: 1771' to PCU 05 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 45 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# L-80 GBCD 2,500' Surface Surface 2,500' 2,164' 6-3/4" 3-1/2" 9.2# L-80 563/ACME 3,714' 2,300' 2,007' 6,014' 5,565' Tieback 3-1/2" 9.2# L-80 EUE 2,300' Surface Surface 2,300' 2,007' 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 PCU D-11 Pretty Creek Unit Undefined Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL REVISED 20 AAC 25.005 L - 805 ft3 / T - 131 ft3 2003 2331' FNL, 106' FEL, Sec 28, T14N, R9W, SM, AK 2623' FNL, 431' FEL, Sec 28, T14N, R9W, SM, AK LOCI 25-001 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1404' FNL, 925' FWL, Sec 27, T14N, R9W, SM, AK ADL 58810 / ADL 63048 18. Casing Program:Top - Setting Depth - BottomSpecifications 2560 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) Driven L - 816 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): 9/30/2025 2331' to nearest unit boundary Nate Sperry nathan.sperry@hilcorp.com 907-777-8450 Tieback Assy. 1428 Cement Volume MD Yeees ype of W L l R L 1b S Class: os N Yees NNNo s N NNNo D s s sD 84 o esss: well is p G S S 20 SS S Yees NNNos No S G E S Yees NNNo 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) 9/29/25Monty M Myers By Grace Christianson at 10:19 am, Sep 29, 2025 10:19 am, Sep 29, 2025 A.Dewhurst 29SEP25 50-283-20209-00-00 DSR-9/29/25 225-088 CT BOP test to 3000 psi Submit FIT/LOT data within 48 hrs of performing test. BOP test to 3000 psi. Annular test to 2500 psi BJM 9/29/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.09.30 09:21:05 -08'00' 09/30/25 09/30/25 9/5/2025 JSB RBDMS JSB 100125 PCU D-11 Drilling Program Pretty Creek Unit August 11, 2025 PCU D-11 Drilling Procedure Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Planned Wellbore Schematic........................................................................................................6 7.0 Drilling / Completion Summary...................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications....................................................................8 9.0 R/U and Preparatory Work........................................................................................................10 10.0 N/U 21-1/4” 2M Diverter.............................................................................................................11 11.0 Drill 9-7/8” Hole Section..............................................................................................................12 12.0 Run 7-5/8” Surface Casing..........................................................................................................14 13.0 Cement 7-5/8” Surface Casing....................................................................................................17 14.0 BOP N/U and Test........................................................................................................................21 15.0 Drill 6-3/4” Hole Section..............................................................................................................22 16.0 Run 3-1/2” Production Liner......................................................................................................24 17.0 Cement 3-1/2” Production Liner................................................................................................27 18.0 3-1/2” Liner Tieback Polish Run................................................................................................31 19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................32 20.0 CBL and Nitrogen Operation (Post Rig Work)........................................................................33 21.0 Diverter Schematic ......................................................................................................................36 22.0 BOP Schematic.............................................................................................................................37 23.0 Wellhead Schematic.....................................................................................................................38 24.0 Anticipated Drilling Hazards......................................................................................................39 25.0 Hilcorp Rig 147 Layout...............................................................................................................41 26.0 FIT/LOT Procedure ....................................................................................................................42 27.0 Choke Manifold Schematic.........................................................................................................43 28.0 Casing Design Information.........................................................................................................44 29.0 6-3/4” Hole Section MASP..........................................................................................................45 30.0 Spider Plot....................................................................................................................................46 31.0 Surface Plat As-Built (Slot 4)......................................................................................................47 Page 2 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 1.0 Well Summary Well PCU D-11 Pad & Old Well Designation Pretty Creek Diamond Pad– Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Sterling/Beluga Planned Well TD, MD / TVD 6014’ MD / 5565’ TVD PBTD, MD / TVD 5954’ MD AFE Drilling Days 18 Maximum Anticipated Pressure (Surface)2003 psi Maximum Anticipated Pressure (Downhole/Reservoir)2560 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 63.9’ Ground Elevation 45.4’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 2.0 Management of Change Information Page 4 Rev 2 September 26, 2025 PCU D-11 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 GBDC 6890 4790 683 Prod 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 GB ACME 10160 10540 168 ** Liner must overlap surface casing by at least 100’. 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update x Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times. a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 2. Spills: x Notify Drlg Manager 1. Sean Mclaughlin: C: 907-223-6784 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com,andcdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com,and cdinger@hilcorp.com Page 6 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 7.0 Drilling / Completion Summary PCU D-11 is an S-shaped directional grassroots development well to be drilled from Pretty Creek Diamond Pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Sterling and Beluga sands. The base plan is an S-shaped directional wellbore with a kickoff point at ~300’ MD. Maximum hole angle will be ~45 deg. and TD of the well will be 6014’ MD / 5565’ TVD, ending with 10 deg inclination left in the hole. Drilling operations are expected to commence approximately September 30 th, 2025. The Hilcorp Rig # 147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 2500’ MD / 2164’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a cement evaluation log (CBL/VDL or temperature log for example)maybe runto determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the 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. Test casing to 3500 psi. Perform FIT to 13.6ppg minimum (target 14.0ppg). 5. ND diverter, N/U & test 11” x 5M BOP to 3000 psi 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 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of PCU D-11. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14-day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. Page 9 Rev 2 September 26, 2025 PCU D-11 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. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email:bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Rev 2 September 26, 2025 PCU D-11 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 11 Rev 2 September 26, 2025 PCU D-11 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 Pretty Creek Pad (actual orientation may change from proposed): Page 12 Rev 2 September 26, 2025 PCU D-11 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 2500’ MD/ 2164’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale x Take MWD surveys every stand drilled (60’ intervals). 11.5 9-7/8” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 13 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH Surface 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.6 At TD, pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.7 TOH with the drilling assy, handle BHA as appropriate. Page 14 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker 7-5/8” casing running equipment. x Ensure 7-5/8” Casing x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 7-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 15 Rev 2 September 26, 2025 PCU D-11 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. Page 16 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 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 17 Rev 2 September 26, 2025 PCU D-11 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 18 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry Tail Slurry (500’) System Extended Conventional Density 12 lb/gal 15.8 lb/gal Yield 2.44 ft3/sk 1.16 ft3/sk Mixed Water 14.40 gal/sk 5.03 gal/sk Mixed Fluid 14.40 gal/sk 5.03 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A CalSeal Accelerator D-Air 5000 Anti Foam VersaSet Thixotropic Calcium Chloride Accelerator D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner BridgeMaker II Lost Circulation Verified cement calcs. -bjm Page 19 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hange elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.7 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require running steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.14 R/D cement equipment. Flush out wellhead with FW. 13.15 Back out and L/D landing joint. Flush out wellhead with FW. 13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.17 Lay down landing joint and pack-off running tool. Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job Page 20 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and nathan.sperry@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 21 Rev 2 September 26, 2025 PCU D-11 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 22 Rev 2 September 26, 2025 PCU D-11 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: Interval Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT Production 9.0 – 9.5 40-53 15-25 15-25 8.5-9.5 11.0 Page 23 Rev 2 September 26, 2025 PCU D-11 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 – 9.7 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. x Triple Combo LWD tools required 15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst.7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 14.0 ppg EMW. A 13.6 ppg FIT will result in a 20 bbl KTV. This assumes a 8.85ppg PP and a 9.5ppg MW (swabbed kick). 15.14 Drill 6-3/4” hole section to 6014’ MD / 5564’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 200 - 300 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. x Trip back to the 7-5/8” shoe about ½ way through the hole section x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Verify lost circulation potential zones with town geologist or drilling engineer. If there is lost circulation potential through specific zones, SLOW ROP, add Black products, and background LCM to the mud. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. 15.15 At TD, pump sweeps, CBU, flowcheck, and pull a wiper trip back to the 7-5/8” shoe. TIH. 15.16 CBU. Flowcheck. TOH with the drilling assy, LDDP and BHA. Page 24 Rev 2 September 26, 2025 PCU D-11 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” HYD 563 x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with 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 25 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure Page 26 Rev 2 September 26, 2025 PCU D-11 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 27 Rev 2 September 26, 2025 PCU D-11 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 28 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure Estimated Total Cement Volume: Verified cement calcs. -bjm Page 29 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure Cement Slurry Design: Lead Slurry Tail Slurry (500’) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss HR-5 Retarder HR-5 Retarder D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner SA-1015 Suspension Agent BridgeMaker II Lost Circulation 17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 17.9. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to up as required by service company procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).Hold pressure for 3-5 minutes. 17.11. Slack off total liner weight plus 30k to confirm hanger is set. 17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls. 17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. Page 30 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17.17. Pressure up drill pipe to 500 psi and pick up to remove the bushing from the liner. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 17.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. 17.21. WOC minimum of 500 psi compressive strength. Test casing to 3000 psi and chart for 30 minutes. Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and nathan.sperry@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 31 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 18.0 3-1/2” Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy per service company rep and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per 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 32 Rev 2 September 26, 2025 PCU D-11 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 33 Rev 2 September 26, 2025 PCU D-11 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 3-1/2” 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 34 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure Page 35 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure Page 36 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 21.0 Diverter Schematic Page 37 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 22.0 BOP Schematic Page 38 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 23.0 Wellhead Schematic Page 39 Rev 2 September 26, 2025 PCU D-11 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 40 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022, ensure all LCM inventory is fully stocked before drilling out surface casing. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 41 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 25.0 Hilcorp Rig 147 Layout Page 42 Rev 2 September 26, 2025 PCU D-11 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 43 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 27.0 Choke Manifold Schematic Page 44 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 28.0 Casing Design Information Page 45 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 29.0 6-3/4” Hole Section MASP Page 46 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 30.0 Spider Plot Page 47 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure 31.0 Surface Plat As-Built (Slot 4) Page 48 Rev 2 September 26, 2025 PCU D-11 Drilling Procedure !"## $%& '( ) 0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625True Vertical Depth (750 usft/in)-750 -375 0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 Vertical Section at 228.00° (750 usft/in) PCU D-11 wp05 tgt wp08 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 1 4PCU D-11 wp08 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 1800' MD, 1650.47' TVD Start Dir 3º/100' : 2180' MD, 1919.18'TVD End Dir : 3346.67' MD, 2938.01' TVD Total Depth : 6014' MD, 5564.82' TVD Sterling X2 Sterling B3 Sterling C1 Sterling C5 Beluga D5 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: PCU D-11 45.40 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2660306.95 345667.88 61° 16' 42.7417 N 150° 52' 37.7486 W SURVEY PROGRAM Date: 2025-07-07T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.50 2500.00 PCU D-11 wp08 (PCU D-11) 3_MWD+AX+Sag 2500.00 6014.00 PCU D-11 wp08 (PCU D-11) 3_MWD+AX+Sag REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well PCU D-11, True North Vertical (TVD) Reference:RKB As-Built @ 63.90usft (147) Measured Depth Reference:RKB As-Built @ 63.90usft (147) Calculation Method: Minimum Curvature Project:Beluga River North Site:Diamond Pad Well:PCU D-11 Wellbore:PCU D-11 Design:PCU D-11 wp08 CASING DETAILS TVD TVDSS MD Size Name 2163.90 2100.00 2500.73 7-5/8 7-5/8" x 9-7/8" 5564.82 5500.92 6014.00 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 1800.00 45.00 228.00 1650.47 -374.30 -415.70 3.00 228.00 559.38 End Dir : 1800' MD, 1650.47' TVD 4 2180.00 45.00 228.00 1919.18 -554.10 -615.39 0.00 0.00 828.09 Start Dir 3º/100' : 2180' MD, 1919.18'TVD 5 3346.67 10.00 228.00 2938.01 -908.98 -1009.53 3.00 180.00 1358.46 End Dir : 3346.67' MD, 2938.01' TVD 6 6014.00 10.00 228.00 5564.82 -1218.91 -1353.74 0.00 0.00 1821.63 Total Depth : 6014' MD, 5564.82' TVD FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3161.90 3098.00 3574.01 Sterling X2 3606.90 3543.00 4025.88 Sterling B3 3656.90 3593.00 4076.65 Sterling C1 3784.90 3721.00 4206.63 Sterling C5 3851.90 3788.00 4274.66 Beluga D5 -1250-1125-1000-875-750-625-500-375-250-1250South(-)/North(+) (250 usft/in)-1875 -1750 -1625 -1500 -1375 -1250 -1125 -1000 -875 -750 -625 -500 -375 -250 -125 0 125 250 375 500West(-)/East(+) (250 usft/in)PCU D-11 wp05 tgt wp087-5/8" x 9-7/8"3-1/2" x 6-3/4"25050075010001250150017502000225025002750300032503500375040004250450047505000525055005565PCU D-11 wp08Start Dir 3º/100' : 300' MD, 300'TVDEnd Dir : 1800' MD, 1650.47' TVDStart Dir 3º/100' : 2180' MD, 1919.18'TVDEnd Dir : 3346.67' MD, 2938.01' TVDTotal Depth : 6014' MD, 5564.82' TVDCASING DETAILSTVDTVDSS MDSize Name2163.90 2100.00 2500.73 7-5/8 7-5/8" x 9-7/8"5564.82 5500.92 6014.00 3-1/2 3-1/2" x 6-3/4"Project: Beluga River NorthSite: Diamond PadWell: PCU D-11Wellbore: PCU D-11Plan: PCU D-11 wp08WELL DETAILS: PCU D-1145.40+N/-S +E/-W Northing Easting Latittude Longitude0.00 0.00 2660306.95 345667.88 61° 16' 42.7417 N 150° 52' 37.7486 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well PCU D-11, True NorthVertical (TVD) Reference: RKB As-Built @ 63.90usft (147)Measured Depth Reference:RKB As-Built @ 63.90usft (147)Calculation Method:Minimum Curvature * + # , -. , / / !! !! %'+ % 0) " # $%&'()*+!,-. & !!/)0 0 , # $%&'()*+!,-. 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"/&"+-*%&' ) =/ ,0>/ ,0 ?$ >"+&% 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 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:PCU D-11 NAD 1927 (NADCON CONUS)Alaska Zone 0445.40+N/-S +E/-W Northing EastingLatittudeLongitude0.000.00 2660306.95 345667.8861° 16' 42.7417 N 150° 52' 37.7486 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well PCU D-11, True NorthVertical (TVD) Reference: RKB As-Built @ 63.90usft (147)Measured Depth Reference:RKB As-Built @ 63.90usft (147)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-07-07T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.50 2500.00 PCU D-11 wp08 (PCU D-11) 3_MWD+AX+Sag2500.00 6014.00 PCU D-11 wp08 (PCU D-11) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)PCU D-10GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.50 To 6014.00Project: Beluga River NorthSite: Diamond PadWell: PCU D-11Wellbore: PCU D-11Plan: PCU D-11 wp08CASING DETAILSTVD TVDSS MD Size Name2163.90 2100.00 2500.73 7-5/8 7-5/8" x 9-7/8"5564.82 5500.92 6014.00 3-1/2 3-1/2" x 6-3/4" Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. PCU D-11 UNDEFINED GAS PRETTY CREEK 225-088 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:PRETTY CK UNIT D-11Initial Class/TypeDEV / PENDGeoArea820Unit11620On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250880Field & Pool:PRETTY CREEK, UNDEFINED GAS - 580500NA1 Permit fee attachedYes ADL58810, ADL630482 Lease number appropriateYes3 Unique well name and numberYes PRETTY CREEK, UNDEFINED GAS – 580500 governed by statewide regulations.4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2003 psi, BOP rated to 5k psi (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not expected35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipated pore presure gradient is 8.85 PPG EMW36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate9/29/2025ApprBJMDate9/29/2025ApprADDDate9/29/2025AdministrationEngineeringGeologyGeologic Commissioner:GCWDate:Engineering Commissioner:JLCDatePublic CommissionerDateJLC 9/30/2025 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: Pretty Creek Unit Field, Undefine Gas, PCU D-11 Hilcorp Alaska, LLC Permit to Drill Number: 225-088 Surface Location: 1404' FNL, 925' FWL, Sec 27, T14N, R9W, SM, AK Bottomhole Location: 2262' FNL, 834' FEL, Sec 28, T14N, R9W, SM, AK Dear Mr. McLaughlin: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 5th day of September 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.09.05 09:45:55 -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: 6,087' TVD: 5,565' 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): 63.9' 15. Distance to Nearest Well Open Surface: x-345667 y-2660306 Zone-4 45.4' to Same Pool:1200' to PCU D-10(plan) 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 48 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# L-80 GBCD 2,544' Surface Surface 2,544' 2,164' 6-3/4" 3-1/2" 9.2# L-80 563/ACME 3,743' 2,344' 2,017' 6,087' 5,565' Tieback 3-1/2" 9.2# L-80 EUE 2,344' Surface Surface 2,344' 2,017' 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 9/21/2025 2087' to nearest unit boundary Nate Sperry nathan.sperry@hilcorp.com 907-777-8450 Tieback Assy. 1428 Cement Volume MD Drilling Manager Sean Mclaughlin 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate LengthCasing Size Plugs (measured): (including stage data) Driven L - 832 ft3 / T - 128 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 2560 GL / BF Elevation above MSL (ft): Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 812 ft3 / T - 131 ft3 2003 2087' FNL, 477' FEL, Sec 28, T14N, R9W, SM, AK 2262' FNL, 834' FEL, Sec 28, T14N, R9W, SM, AK LOCI 25-001 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1404' FNL, 925' FWL, Sec 27, T14N, R9W, SM, AK ADL 58810 / ADL 63048 PCU D-11 Pretty Creek Unit Undefined Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Yeees ype of W L l R L 1b S Class: os N Yees NNNo s N NNNo D s s sD 84 o esss: well is p G S S 20 SS S Yees NNNos No S G E S Yees NNNo 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 10:50 am, Aug 13, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.08.13 10:42:55 - 08'00' Sean McLaughlin (4311) 225-088 TS 9/4/25 DSR-8/14/25 BOP test to 3000 psi. Annular test to 2500 psi 50-283-20209-00-00 CT BOP test to 3000 psi Submit FIT/LOT data within 48 hrs of performing test. BJM 9/4/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.09.05 09:46:07 -08'00' 09/05/25 09/05/25 RBDMS JSB 090925 PCU D-11 Drilling Program Pretty Creek Unit August 11, 2025 Type text here PCU D-11 Drilling Procedure Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Planned Wellbore Schematic........................................................................................................6 7.0 Drilling / Completion Summary...................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications....................................................................8 9.0 R/U and Preparatory Work........................................................................................................10 10.0 N/U 21-1/4” 2M Diverter.............................................................................................................11 11.0 Drill 9-7/8” Hole Section..............................................................................................................12 12.0 Run 7-5/8” Surface Casing..........................................................................................................14 13.0 Cement 7-5/8” Surface Casing....................................................................................................17 14.0 BOP N/U and Test........................................................................................................................21 15.0 Drill 6-3/4” Hole Section..............................................................................................................22 16.0 Run 3-1/2” Production Liner......................................................................................................24 17.0 Cement 3-1/2” Production Liner................................................................................................27 18.0 3-1/2” Liner Tieback Polish Run................................................................................................31 19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................32 20.0 CBL and Nitrogen Operation (Post Rig Work)........................................................................33 21.0 Diverter Schematic ......................................................................................................................36 22.0 BOP Schematic.............................................................................................................................37 23.0 Wellhead Schematic.....................................................................................................................38 24.0 Anticipated Drilling Hazards......................................................................................................39 25.0 Hilcorp Rig 147 Layout...............................................................................................................41 26.0 FIT/LOT Procedure ....................................................................................................................42 27.0 Choke Manifold Schematic.........................................................................................................43 28.0 Casing Design Information.........................................................................................................44 29.0 6-3/4” Hole Section MASP..........................................................................................................45 30.0 Spider Plot....................................................................................................................................46 31.0 Surface Plat As-Built (Slot 4)......................................................................................................47 Page 2 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 1.0 Well Summary Well PCU D-11 Pad & Old Well Designation Pretty Creek Diamond Pad– Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Sterling/Beluga Planned Well TD, MD / TVD 6087’ MD / 5565’ TVD PBTD, MD / TVD 6000’ MD AFE Drilling Days 18 Maximum Anticipated Pressure (Surface)2003 psi Maximum Anticipated Pressure (Downhole/Reservoir)2560 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 63.9’ Ground Elevation 45.4’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 2.0 Management of Change Information Page 4 Rev 0.0 August 11, 2025 PCU D-11 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 GBDC 6890 4790 683 Prod 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 GB ACME 10160 10540 168 ** Liner must overlap surface casing by at least 100’. 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update x Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times. a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 2. Spills: x Notify Drlg Manager 1. Sean Mclaughlin: C: 907-223-6784 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com,andcdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com,and cdinger@hilcorp.com Page 6 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 7.0 Drilling / Completion Summary PCU D-11 is an S-shaped directional grassroots development well to be drilled from Pretty Creek Diamond 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 ~48 deg. and TD of the well will be 6087’ MD / 5565’ TVD, ending with 10 deg inclination left in the hole. Drilling operations are expected to commence approximately September 21 st, 2025. The Hilcorp Rig # 147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 2544’ MD / 2164’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a cement evaluation log (CBL/VDL or temperature log for example)maybe runto determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the 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. Test casing to 3500 psi. Perform FIT to 13.6ppg minimum (target 14.0ppg). 5. ND diverter, N/U & test 11” x 5M BOP to 3000 psi 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 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of PCU D-11. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14-day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. Page 9 Rev 0.0 August 11, 2025 PCU D-11 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. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email:bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Rev 0.0 August 11, 2025 PCU D-11 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 11 Rev 0.0 August 11, 2025 PCU D-11 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 Pretty Creek Pad (actual orientation may change from proposed): Page 12 Rev 0.0 August 11, 2025 PCU D-11 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 2544’ MD/ 2164’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale x Take MWD surveys every stand drilled (60’ intervals). 11.5 9-7/8” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 13 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH Surface 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.6 At TD, pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.7 TOH with the drilling assy, handle BHA as appropriate. Page 14 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker 7-5/8” casing running equipment. x Ensure 7-5/8” Casing x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 7-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 15 Rev 0.0 August 11, 2025 PCU D-11 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. Page 16 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 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 17 Rev 0.0 August 11, 2025 PCU D-11 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 18 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry Tail Slurry (500’) System Extended Conventional Density 12 lb/gal 15.8 lb/gal Yield 2.44 ft3/sk 1.16 ft3/sk Mixed Water 14.40 gal/sk 5.03 gal/sk Mixed Fluid 14.40 gal/sk 5.03 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A CalSeal Accelerator D-Air 5000 Anti Foam VersaSet Thixotropic Calcium Chloride Accelerator D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner BridgeMaker II Lost Circulation Verified cement calcs. -bjm Page 19 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hange elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.7 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require running steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.14 R/D cement equipment. Flush out wellhead with FW. 13.15 Back out and L/D landing joint. Flush out wellhead with FW. 13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.17 Lay down landing joint and pack-off running tool. Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold Page 20 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and nathan.sperry@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 21 Rev 0.0 August 11, 2025 PCU D-11 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 22 Rev 0.0 August 11, 2025 PCU D-11 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: Interval Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT Production 9.0 – 9.5 40-53 15-25 15-25 8.5-9.5 11.0 Page 23 Rev 0.0 August 11, 2025 PCU D-11 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 – 9.7 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. x Triple Combo LWD tools required 15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst.7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 14.0 ppg EMW. A 13.6 ppg FIT will result in a 20 bbl KTV. This assumes a 8.85ppg PP and a 9.5ppg MW (swabbed kick). 15.14 Drill 6-3/4” hole section to 6087’ MD / 5564’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 200 - 300 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. x Trip back to the 7-5/8” shoe about ½ way through the hole section x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Verify lost circulation potential zones with town geologist or drilling engineer. If there is lost circulation potential through specific zones, SLOW ROP, add Black products, and background LCM to the mud. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. 15.15 At TD, pump sweeps, CBU, flowcheck, and pull a wiper trip back to the 7-5/8” shoe. TIH. 15.16 CBU. Flowcheck. TOH with the drilling assy, LDDP and BHA. Page 24 Rev 0.0 August 11, 2025 PCU D-11 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” HYD 563 x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with 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 25 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure Page 26 Rev 0.0 August 11, 2025 PCU D-11 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 27 Rev 0.0 August 11, 2025 PCU D-11 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 28 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure Estimated Total Cement Volume: Verified cement calcs. -bjm Page 29 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure Cement Slurry Design: Lead Slurry Tail Slurry (500’) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss HR-5 Retarder HR-5 Retarder D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner SA-1015 Suspension Agent BridgeMaker II Lost Circulation 17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 17.9. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to up as required by service company procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).Hold pressure for 3-5 minutes. 17.11. Slack off total liner weight plus 30k to confirm hanger is set. 17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls. 17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. Page 30 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17.17. Pressure up drill pipe to 500 psi and pick up to remove the bushing from the liner. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 17.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. 17.21. WOC minimum of 500 psi compressive strength. Test casing to 3000 psi and chart for 30 minutes. Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and nathan.sperry@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 31 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 18.0 3-1/2” Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy per service company rep and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per 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 32 Rev 0.0 August 11, 2025 PCU D-11 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 33 Rev 0.0 August 11, 2025 PCU D-11 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 3-1/2” 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 34 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure Page 35 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure Page 36 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 21.0 Diverter Schematic Page 37 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 22.0 BOP Schematic Page 38 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 23.0 Wellhead Schematic Page 39 Rev 0.0 August 11, 2025 PCU D-11 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 40 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022, ensure all LCM inventory is fully stocked before drilling out surface casing. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 41 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 25.0 Hilcorp Rig 147 Layout Page 42 Rev 0.0 August 11, 2025 PCU D-11 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 43 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 27.0 Choke Manifold Schematic Page 44 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 28.0 Casing Design Information Page 45 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 29.0 6-3/4” Hole Section MASP 5,565 TS 9/3/25 6,087 Page 46 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 30.0 Spider Plot Page 47 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure 31.0 Surface Plat As-Built (Slot 4) Page 48 Rev 0.0 August 11, 2025 PCU D-11 Drilling Procedure !"## $% &' ( ) 0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625True Vertical Depth (750 usft/in)-750 -375 0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 Vertical Section at 244.00° (750 usft/in) PCU D-11 wp05 tgt1 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 200025003 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 0 8 7PCU D-11 wp05 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 1900' MD, 1719.3' TVD Start Dir 3º/100' : 2275' MD, 1970.23'TVD End Dir : 3541.67' MD, 3057.88' TVD Total Depth : 6087' MD, 5564.55' TVD Sterling X2 Sterling B3 Sterling C1 Sterling C5 Beluga D5 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: PCU D-11 45.40 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2660306.95 345667.88 61° 16' 42.7417 N 150° 52' 37.7486 W SURVEY PROGRAM Date: 2025-07-07T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.50 2544.00 PCU D-11 wp05 (PCU D-11) 3_MWD+AX+Sag 2544.00 6087.00 PCU D-11 wp05 (PCU D-11) 3_MWD+AX+Sag REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well PCU D-11, True North Vertical (TVD) Reference:RKB As-Built @ 63.90usft (147) Measured Depth Reference:RKB As-Built @ 63.90usft (147) Calculation Method:Minimum Curvature Project:Beluga River North Site:Diamond Pad Well:PCU D-11 Wellbore:PCU D-11 Design:PCU D-11 wp05 CASING DETAILS TVD TVDSS MD Size Name 2163.90 2100.00 2544.28 7-5/8 7-5/8" x 9-7/8" 5564.55 5500.65 6087.00 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 1900.00 48.00 244.00 1719.30 -277.01 -567.96 3.00 244.00 631.91 End Dir : 1900' MD, 1719.3' TVD 4 2275.00 48.00 244.00 1970.23 -399.18 -818.44 0.00 0.00 910.59 Start Dir 3º/100' : 2275' MD, 1970.23'TVD 5 3541.67 10.00 244.00 3057.88 -663.47 -1360.32 3.00 180.00 1513.49 End Dir : 3541.67' MD, 3057.88' TVD 6 6087.00 10.00 244.00 5564.55 -857.23 -1757.58 0.00 0.00 1955.48 Total Depth : 6087' MD, 5564.55' TVD FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3161.90 3098.00 3647.29 Sterling X2 3589.90 3526.00 4081.89 Sterling B3 3636.90 3573.00 4129.61 Sterling C1 3734.90 3671.00 4229.13 Sterling C5 3852.90 3789.00 4348.95 Beluga D5 -1000-900-800-700-600-500-400-300-200-1000100South(-)/North(+) (200 usft/in)-1800 -1700 -1600 -1500 -1400 -1300 -1200 -1100 -1000 -900 -800 -700 -600 -500 -400 -300 -200 -100 0 100West(-)/East(+) (200 usft/in)PCU D-11 wp05 tgt17-5/8" x 9-7/8"3-1/2" x 6-3/4"5 0 0 7 5 0 1 0 0 0 1 2 5 0 1 5 0 0 1 7 5 0 2 0 0 0 2 2 5 0 2 5 0 0 2 7 5 0 3 0 0 0 3 2 5 0 3 5 0 0 3 7 5 0 4 0 0 0 4 2 5 0 4 5 0 0 4 7 5 0 5 0 0 0 5 2 5 0 5 5 6 5 PCU D-11 wp05Start Dir 3º/100' : 300' MD, 300'TVDEnd Dir : 1900' MD, 1719.3' TVDStart Dir 3º/100' : 2275' MD, 1970.23'TVDEnd Dir : 3541.67' MD, 3057.88' TVDTotal Depth : 6087' MD, 5564.55' TVDCASING DETAILSTVDTVDSS MDSize Name2163.90 2100.00 2544.28 7-5/8 7-5/8" x 9-7/8"5564.55 5500.65 6087.00 3-1/2 3-1/2" x 6-3/4"Project: Beluga River NorthSite: Diamond PadWell: PCU D-11Wellbore: PCU D-11Plan: PCU D-11 wp05WELL DETAILS: PCU D-1145.40+N/-S +E/-W Northing Easting Latittude Longitude0.00 0.00 2660306.95 345667.88 61° 16' 42.7417 N 150° 52' 37.7486 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well PCU D-11, True NorthVertical (TVD) Reference:RKB As-Built @ 63.90usft (147)Measured Depth Reference:RKB As-Built @ 63.90usft (147)Calculation Method:Minimum Curvature * ) # + ,- + . ./ !! !! & 0( " # $%&'()*+!,-. % !!/)0 / 0 + # $%&'()*+!,-. 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"%&%,,**+&++' )'()")'()")'()"% %&, ,%& ,-&/ ,,-&*" "&+*%,%& )'()")'()")'()"% %+&,- -+%& %"&/+ --,&" "&,%/-+%&' ) =, )->, )- @% >".&% 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 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:PCU D-11 NAD 1927 (NADCON CONUS)Alaska Zone 0445.40+N/-S +E/-W Northing EastingLatittudeLongitude0.000.00 2660306.95 345667.88 61° 16' 42.7417 N 150° 52' 37.7486 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well PCU D-11, True NorthVertical (TVD) Reference:RKB As-Built @ 63.90usft (147)Measured Depth Reference:RKB As-Built @ 63.90usft (147)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-07-07T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.50 2544.00 PCU D-11 wp05 (PCU D-11) 3_MWD+AX+Sag2544.00 6087.00 PCU D-11 wp05 (PCU D-11) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)PCU D-10 wp05GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.50 To 6087.00Project: Beluga River NorthSite: Diamond PadWell: PCU D-11Wellbore: PCU D-11Plan: PCU D-11 wp05CASING DETAILSTVD TVDSS MD Size Name2163.90 2100.00 2544.28 7-5/8 7-5/8" x 9-7/8"5564.55 5500.65 6087.00 3-1/2 3-1/2" x 6-3/4" Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. PCU D-11 225-088 PRETTY CREEK UNDEFINED GAS WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:PRETTY CK UNIT D-11Initial Class/TypeDEV / PENDGeoArea820Unit11620On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250880Field & Pool:PRETTY CREEK, UNDEFINED GAS - 580500NA1 Permit fee attachedYes ADL58810, ADL630482 Lease number appropriateYes3 Unique well name and numberYes PRETTY CREEK, UNDEFINED GAS – 580500 governed by statewide regulations.4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2003 psi, BOP rated to 5k psi (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not expected35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipated pore presure gradient is 8.85 PPG EMW36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprTCSDate9/3/2025ApprBJMDate9/4/2025ApprTCSDate9/3/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 9/5/2025