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Home My WebLink About225-0371. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,174' N/A Casing Collapse Structural Conductor 1,410psi Surface 683psi Intermediate Production 10,540psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng LTP; N/A 2,412' MD/1,994' TVD; N/A 5,617' 7,102' 5,546' Pretty Creek Undefined Gas 16" 7-5/8" 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Pretty Creek (PCU) 05Undefined Gas Same 5,612'3-1/2" ~1533psi 4,758' N/A Statewide spacing regulations: 20 AAC 25.055 February 5, 2026 Tieback 3-1/2" 7,170' Perforation Depth MD (ft): See Attached Schematic See Attached Schematic 2,980psi 4,790psi 120'120' 2,587' Tubing MD (ft): Size 120' 2,587' MDLength Proposed Pools: 9.2# / L-80 TVD Burst 2,426' 10,160psi 2,076' Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 390780 / ADL 063048 225-037 50-283-20203-00-00 Tubing Size: Hilcorp Alaska, LLC Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com Perforation Depth TVD (ft): 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: PRESENT WELL CONDITION SUMMARY m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2026.01.19 16:02:14 - 09'00' Noel Nocas (4361) 326-035 By Grace Christianson at 8:49 am, Jan 20, 2026 10-404 Place cement on plug at 5495' MD to isolate Beluga before setting additional plugs in the wellbore. Tag CIBP before placing cement to verify depth and cement thickness. If fill is present on plug, discuss cementing plan with AOGCC and obtain approval before placing cement. See attached 1/27/26 email. DSR-1/22/26BJM 1/27/26 A.Dewhurst 21JAN26JLC 1/28/2026 01/28/26 Well Prognosis Well Name: PCU-05 API Number: 50-283-20203-00-00 Current Status: Flowing Gas Well Permit to Drill Number: 225-037 Second Call Engineer: Chad Helgeson (907) 777-8405 (O)(907) 229-4824 (C) First Call Engineer: Ryan LeMay (661) 487-0871 (C) Maximum Expected BHP: 1729 psi @ 3930 TVD (Based on 0.44 psi/ft gradient) Max. Potential Surface Pressure:1533 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.666 psi/ft using 12.81 ppg EMW FIT at the 7-5/8 surface casing shoe Shallowest Potential Perf TVD: MPSP/(0.666-0.05) = 1533 psi / 0.616 = 2489 TVD Brief Well Summary PCU-05 was drilled in the summer of 2025 and brought online in the Sterling Sands. The current open sands were originally correlated as Beluga D Sands from the original discovery well. After meeting with AOGCC in early December 2025 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 is currently flowing 300mcf @ 300 psi. The objective of this sundry is to add perforations and increase the rate. Wellbore Conditions: - Max Inclination 63° at 2,539 MD - Max DLS °/100 8° at 1,044 MD -Min ID- 2.992 3-1/2 tubing/liner 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 ±4,759' ±4,768' ±3,313' ±3,320' ±10' ST A5 ±5,009' ±5,015' ±3,521' ±3,526' ±6' ST A5 ±5,041' ±5,050' ±3,549' ±3,557' ±9' ST C1 ±5,236' ±5,244' ±3,724' ±3,731' ±9' ST C1 ±5,264' ±5,276' ±3,750' ±3,761' ±12' ST C2 ±5,304' ±5,312' ±3,787' ±3,794' ±8' ST C4 ±5,385' ±5,391' ±3,863' ±3,869' ±8' ST C5 ±5,454' ±5,463' ±3,929' ±3,938' ±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 5. RDMO Need to place cement on plug at 5495' MD to isolate Beluga before setting additional plugs in the wellbore. -bjm RIH and set plug above the perforations OR patch across the perforations Well Prognosis 6. Turn well over to production & flow test well Attachments: 1. Current Schematic 2. Proposed Schematic Updated by CAH 01-14-26 SCHEMATIC Pretty Creek Unit PCU-05 PTD: 225-037 API: 50-283-20203-00-00 PBTD = 5,495 / TVD = 3,967 TD = 7,174 / TVD = 5,617 RKB to GL = 18.5 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120 7-5/8" Surf Csg 29.7 L-80 & P-110 GBBTC & DWC/C 6.875Surf 2,587 3-1/2"Prod Lnr 9.2 L-80 GB ACME 2.9922,4127,170 3-1/2"Prod Tieback 9.3 L-80 8RD EUE 2.992Surf 2,426 16 7-5/8 9-7/8 hole 3-1/2 JEWELRY DETAIL No. Depth ID OD Item 1 21Cactus CTF-ONE-CTL hanger, w/ 4 type H BPV profile 2 2,4124.7905-1/2 x 7-5/8 Innovex Hanger/Liner top Packer 3 2,4263.0 4.54 Bullet Seal Assembly spaced 1.23 off no-go 4 5,495NA 2.992 CIBP (7/20/25) 5 5,616NA 2.992 CIBP (7/17/25) 6 6,050NA 2.992 CIBP (7/14/25) 7 6,300NA 2.992 CIBP (7/13/25) 8 6,380NA 2.992 CIBP (7/12/25) 9 6,595NA 2.992 CIBP w/30ft of cement (7/11/25) 10 6,750NA 2.992 CIBP (7/10/25) OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 155 bbl (358 sx) 12 ppg lead cement followed by 37 bbl (193 sx) 15.8 tail cement. Bumped plug at 129 bbls (calculated 131 bbls), spacer & 69 bbls of contaminated lead cement to surface, no losses during job. 3-1/2 192 bbls (458 sx) of 12 ppg Type I/II lead followed by 24 bbls (122sx) of 15.3 ppg tail in 6.75 hole. Bumped plug, went on losses after lead hit liner top packer. No cement after setting liner hanger. TOC based on CBL @ 2730 dated 7/3/25. 6-3/4 hole 2/3 1 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments ST C5 5,441 5,449 3,917 3,924 8 7/20/25 Open ST C5 5,465 5,470 3,940 3,945 5 7/20/25 Open BEL D6 5,499 5,508 3,972 3,981 9 7/19/25 Plugged BEL F4 5,933 5,943 4,396 4,406 9 7/15/25 Plugged BEL F4 5,953 5,957 4,416 4,420 4 7/15/25 Plugged BEL F7 6,068 6,079 4,529 4,540 11 7/14/25 Plugged BEL G5 6,311 6,325 4,768 4,782 14 7/13/25 Plugged BEL G10 6,388 6,396 4,844 4,852 8 7/12/25 Plugged BEL H4 6,606 6,614 5,059 5,067 7 7/11/25 Plugged BEL H4 6,625 6,630 5,078 5,083 5 7/11/25 Plugged BEL H6 6,757 6,766 5,209 5,217 9 7/9/25 Plugged BEL H6 6,804 6,824 5,254 5,274 20 7/9/25 Plugged NOTES: 10 Short jt w/ RA tags 6104, 5418 10 Short joints 5197, 4640 Deviation Kick off ~545 build to 63 deg @ 2539. Drop to 10deg @ 5750. Max dog leg 8deg/100 @ 1044 and 6deg/100 @ 4730 Fish details 4ft spent gun, CCL tool, 7ft weight bar, 9/32 rope socket Fill @ 5725 (7/16/25) 4 5 6 7 8 9 10 Updated by CAH 01-14-26 PROPOSED Pretty Creek Unit PCU-05 PTD: 225-037 API: 50-283-20203-00-00 PBTD = 5,495 / TVD = 3,967 TD = 7,174 / TVD = 5,617 RKB to GL = 18.5 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120 7-5/8" Surf Csg 29.7 L-80 & P-110 GBBTC & DWC/C 6.875Surf 2,587 3-1/2"Prod Lnr 9.2 L-80 GB ACME 2.9922,4127,170 3-1/2"Prod Tieback 9.3 L-80 8RD EUE 2.992Surf 2,426 16 7-5/8 9-7/8 hole 3-1/2 JEWELRY DETAIL No. Depth ID OD Item 1 21Cactus CTF-ONE-CTL hanger, w/ 4 type H BPV profile 2 2,4124.7905-1/2 x 7-5/8 Innovex Hanger/Liner top Packer 3 2,4263.0 4.54 Bullet Seal Assembly spaced 1.23 off no-go 4 5,495NA 2.992 CIBP (7/20/25) 5 5,616NA 2.992 CIBP (7/17/25) 6 6,050NA 2.992 CIBP (7/14/25) 7 6,300NA 2.992 CIBP (7/13/25) 8 6,380NA 2.992 CIBP (7/12/25) 9 6,595NA 2.992 CIBP w/30ft of cement (7/11/25) 10 6,750NA 2.992 CIBP (7/10/25) OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 155 bbl (358 sx) 12 ppg lead cement followed by 37 bbl (193 sx) 15.8 tail cement. Bumped plug at 129 bbls (calculated 131 bbls), spacer & 69 bbls of contaminated lead cement to surface, no losses during job. 3-1/2 192 bbls (458 sx) of 12 ppg Type I/II lead followed by 24 bbls (122sx) of 15.3 ppg tail in 6.75 hole. Bumped plug, went on losses after lead hit liner top packer. No cement after setting liner hanger. TOC based on CBL @ 2730 dated 7/3/25. 6-3/4 hole 2/3 1 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments ST X3 ±4,759 ±4,768 ±3,313 ±3,320 ±10 Proposed TBD ST A5 ±5,009 ±5,015 ±3,521 ±3,526 ±6 Proposed TBD ST A5 ±5,041 ±5,050 ±3,549 ±3,557 ±9 Proposed TBD ST C1 ±5,236 ±5,244 ±3,724 ±3,731 ±9 Proposed TBD ST C1 ±5,264 ±5,276 ±3,750 ±3,761 ±12 Proposed TBD ST C2 ±5,304 ±5,312 ±3,787 ±3,794 ±8 Proposed TBD ST C4 ±5,385 ±5,391 ±3,863 ±3,769 ±8 Proposed TBD ST C5 5,441 5,449 3,917 3,924 8 7/20/25 Open ST C5 ±5,454 ±5,463 ±3,929 ±3,938 ±9 Proposed TBD ST C5 5,465 5,470 3,940 3,945 5 7/20/25 Open BEL D6 5,499 5,508 3,972 3,981 9 7/19/25 Plugged BEL F4 5,933 5,943 4,396 4,406 9 7/15/25 Plugged BEL F4 5,953 5,957 4,416 4,420 4 7/15/25 Plugged BEL F7 6,068 6,079 4,529 4,540 11 7/14/25 Plugged BEL G5 6,311 6,325 4,768 4,782 14 7/13/25 Plugged BEL G10 6,388 6,396 4,844 4,852 8 7/12/25 Plugged BEL H4 6,606 6,614 5,059 5,067 7 7/11/25 Plugged BEL H4 6,625 6,630 5,078 5,083 5 7/11/25 Plugged BEL H6 6,757 6,766 5,209 5,217 9 7/9/25 Plugged BEL H6 6,804 6,824 5,254 5,274 20 7/9/25 Plugged NOTES: 10 Short jt w/ RA tags 6104, 5418 10 Short joints 5197, 4640 Deviation Kick off ~545 build to 63 deg @ 2539. Drop to 10deg @ 5750. Max dog leg 8deg/100 @ 1044 and 6deg/100 @ 4730 Fish details 4ft spent gun, CCL tool, 7ft weight bar, 9/32 rope socket Fill @ 5725 (7/16/25) 4 5 6 7 8 9 10 1 McLellan, Bryan J (OGC) From:McLellan, Bryan J (OGC) Sent:Tuesday, January 27, 2026 2:42 PM To:'Chad Helgeson' Subject:RE: [EXTERNAL] PCU 5 (PTD 225-037) perf sundry Chad, We should probably discuss that topic of the Beluga being devoid of hydrocarbons with our geologists and come to an agreement. For now, and to progress this sundry, I think the latter of your suggestions will work, setting cement on top of either the existing plug or the ll on top of it before setting another plug. Ill include that in the CoAs and sign o . 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: Tuesday, January 27, 2026 11:15 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] PCU 5 (PTD 225-037) perf sundry I am a little nervous about putting 25ft of cement on the existing plug for that isolation with the close perfs. I am comfortable putting 10ft of cement on the plug (if there is not ll on it now), before adding more perfs. I got a SL tag on it last night and seems like we are pretty close to those perfs, so we may not have 10ft or 25ft at this point without more intervention to get cement on the plug. I could potentially bail down to the top of plug and then place cement on the plug if needed, good chance that cement might not be a good seal wall to wall in the pipe. Would it matter if the none of the Beluga sands have any hydrocarbons in them? I know that there has been a lot of discussion about indigenous strata isolation for hydrocarbons, but how would pool isolation need to be de ned if there are no hydrocarbons in the any of zones below the Sterling sands. Do you think we could get an agreement that we will place cement over the next zone we set a plug or on top of any ll we have before we set another plug? Chad CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, January 26, 2026 2:46 PM To: Chad Helgeson <chelgeson@hilcorp.com> Subject: [EXTERNAL] PCU 5 (PTD 225-037) perf sundry Chad, Now that weve agreed to re-de ne the base of the Sterling, we should have a cemented plug between the Beluga and Sterling formations in this well. I see that theres not much room between the CIBP and the bottom of Sterling perfs (only 25). If there is concern about damaging the open perfs in the Sterling by placing cement now, we could discuss placing cement on the existing plug later. The sundry application mentions potentially setting additional plugs, but Id want to make sure there is cement on the plug at 5495 before setting additional plugs shallower. What do you suggest? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250807 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 23 50133206350000 214093 6/26/2025 AK E-LINE PPROF T40741 BCU 25 50133206440000 214132 7/16/2025 AK E-LINE Plug/Cement T40742 BRU 211-35 50283201890000 223050 6/11/2025 AK E-LINE Perf T40743 BRU 211-35 50283201890000 223050 6/20/2025 AK E-LINE PPROF T40743 BRU 213-26 50283201920000 223069 7/7/2025 AK E-LINE Perf T40744 BRU 213-26T 50283202040000 225038 7/2/2025 AK E-LINE Perf T40745 BRU 213-26T 50283202040000 225038 7/4/2025 AK E-LINE Perf T40745 BRU 213-26T 50283202040000 225038 6/28/2025 AK E-LINE Perf T40745 BRU 241-23 50283201910000 223061 7/18/2025 AK E-LINE Perf T40746 GP 11-13RD 50733200260100 191133 6/2/2025 AK E-LINE PPFROF T40747 KBU 32-06 50133206580000 216137 7/1/2025 AK E-LINE PPROF T40748 MPU E-28 50029232590000 202055 5/8/2025 AK E-LINE Caliper T40749 MPU F-21 50029226940000 196135 7/10/2025 AK E-LINE Caliper T40750 MPU G-02 50029219260000 189028 7/6/2025 AK E-LINE Puncher T40751 MPU I-01 50029220650000 190090 7/7/2025 AK E-LINE TubingPunch T40752 NS-19 50029231220000 202207 6/27/2025 AK E-LINE Perf T40753 PBU J-07C 50029202410300 225026 5/29/2025 BAKER MRPM T40754 PBU N-07B 50029201370200 223122 6/7/2025 BAKER MRPM T40755 PCU-05 50283202030000 225037 7/10/2024 AK E-LINE Perf T40756 TBU D-07RD2 50733201170200 192155 7/19/2025 AK E-LINE Perf T40757 TBU M-09 50733204760000 196127 7/18/2025 AK E-LINE Perf T40758 Please include current contact information if different from above. T40756PCU-05 50283202030000 225037 7/10/2024 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.08 11:16:55 -08'00' David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 8/05/2025 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Well: PCU-05 PTD: 225-037 API: 50-283-20203-00-00 FINAL LWD FORMATION EVALUATION LOGS (06/14/2025 to 06/24/2025) DGR and BaseStar Gamma Ray, ADR and StrataStar Resistivity, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey Folder Contents: Please include current contact information if different from above. 225-037 T40733 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.05 15:31:19 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 7/23/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250723 Well API # PTD # Log Date Log Company AOGCC ESet # END 1-25A 50029217220100 197075 6/19/2025 HALLIBURTON T40691 KU 41-08 50133207170000 224005 6/30/2025 AK E-LINE T40692 MPU F-05 50029227620000 197074 7/1/2025 READ T40693 MPU J-02 50029220710000 190096 5/21/2025 YELLOWJACKET T40694 MPU R-106 50029238160000 225033 6/8/2025 HALLIBURTON T40695 MPU R-107 50029238190000 225049 7/11/2025 YELLOWJACKET T40696 ODSK-41 50703205850000 208147 6/13/2025 HALLIBURTON T40697 ODSN-02 50703206710000 213046 6/13/2025 HALLIBURTON T40698 ODSN-16 50703206200000 210053 6/14/2025 HALLIBURTON T40699 ODSN-17 50703206220000 210093 6/14/2025 HALLIBURTON T40700 ODSN-24 50703206620000 212178 6/15/2025 HALLIBURTON T40701 ODSN-28 50703206760000 213148 6/17/2025 HALLIBURTON T40702 ODSN-36 50703205610000 207182 6/12/2025 HALLIBURTON T40703 PBU 07-23C 50029216350300 225043 7/4/2025 HALLIBURTON T40704 PBU 14-18C 50029205510300 225040 6/25/2025 HALLIBURTON T40705 PBU 15-33C 50029224480300 216075 7/3/2025 HALLIBURTON T40706 PBU C-30A 50029217770100 208169 7/1/2025 HALLIBURTON T40707 PBU E-09C 50029204660300 209095 6/30/2025 HALLIBURTON T40708 PBU F-38B 50029220930300 225029 6/12/2025 HALLIBURTON T40709 PBU GNI-02A 50029228510100 206119 7/4/2025 HALLIBURTON T40710 PBU GNI-02A 50029228510100 206119 7/3/2025 HALLIBURTON T40710 PBU GNI-04 50029233670000 207117 6/27/2025 HALLIBURTON T40711 PBU GNI-04 50029233670000 207117 6/27/2025 HALLIBURTON T40711 PBU J-07C 50029202410300 225026 5/30/2025 HALLIBURTON T40712 PBU L-105 50029230750000 202058 6/24/2025 YELLOWJACKET T40713 PBU L-108 50029230900000 202109 6/23/2025 YELLOWJACKET T40714 PBU NK-25 50029227600000 197068 6/5/2025 YELLOWJACKET T40715 PBU P2-06 50029223880000 193103 6/19/2025 HALLIBURTON T40716 PBU S-104 50029229880000 200196 6/21/2025 YELLOWJACKET T40717 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.28 09:54:00 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PCU-05 50283202030000 225037 7/3/2025 YELLOWJACKET T40718 TBU D-08RD 50733201070100 174003 6/4/2025 READ T40719 Please include current contact information if different from above. T40718PCU-05 50283202030000 225037 7/3/2025 YELLOWJACKET Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.28 09:53:40 -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: 07/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PCU-05 PTD: 225-037 API: 50-283-20203-00-00 MUDLOGS - EOW DRILLING REPORTS (06/21/2025 to 06/24/2025) 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. 225-037 T40675 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.17 07:59:12 -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:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20250707 0930 APPROVAL PCU-05 (PTD# 225-037) Cement Bond log Date:Monday, July 7, 2025 9:34:18 AM From: Rixse, Melvin G (OGC) Sent: Monday, July 7, 2025 9:23 AM To: Chad Helgeson <chelgeson@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: PCU-05 (PTD# 225-037) Cement Bond log Chad, Hilcorp is approved to perforate as per sundry 325-395. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. McLellan, Ambruz From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, July 4, 2025 10:02 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: PCU-05 (PTD# 225-037) Cement Bond log Please find attached the Cement bond log for PCU-05 (PT# 225-037). This log is better quality than the last one. Looks like we have cement up to 2730’. Please let us know if we have permission to perforate on this well. It is expected we will be ready for perforations on Tuesday. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified 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 Completion, N2 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,174'N/A Casing Collapse Structural Conductor 1,410psi Surface 683psi Intermediate Production 10,540psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 390780 / ADL 063048 225-037 50-283-20203-00-00 Tubing Size: Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,426' 10,160psi 2,076' Size 120' 2,587' MDLength See Attached Schematic 2,980psi 4,790psi 120'120' 2,587' Tubing MD (ft): July 5, 2025 Tieback 3-1/2" 7,170' Perforation Depth MD (ft): See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Pretty Creek (PCU) 05Undefined Gas Same 5,612'3-1/2" ~2057psi 4,758' N/A Statewide spacing regulations: 20 AAC 25.055 LTP; N/A 2,412' MD/1,994' TVD; N/A 5,617' 7,102' 5,546' Pretty Creek Undefined Gas 16" 7-5/8" 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 3:10 pm, Jul 01, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.07.01 12:07:36 - 08'00' Noel Nocas (4361) 325-395 BJM 7/2/25 10-407 SFD 7/01/2025 July 5, 2025 CT BOP test to 3500 psi. Submit CBL to AOGCC and obtain approval prior to perforating. Yes, for CTCO only 7/1/25 Bryan McLellan X Perforate JLC 7/2/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.02 13:00:45 -08'00'07/02/25 RBDMS JSB 070325 Well Prognosis Well Name: PCU-05 API Number: 50-283-20203-00-00 Current Status: New Drill Well Permit to Drill Number: 225-037 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: 2320 psi @ 5274’ TVD (Based on 0.44 psi/ft gradient) Max. Potential Surface Pressure: 2057 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.666 psi/ft using 12.81 ppg EMW FIT at the 7-5/8” surface casing shoe Shallowest Potential Perf TVD: MPSP/(0.666-0.05) = 2057 psi / 0.616 = 3339’ TVD with H Sands open Well Status: New Drill Well Initial Completion Brief Well Summary PCU-05 is the first 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 the well and flow the new drill well. Wellbore Conditions: - Max Inclination – 63° at 2,539’ MD - Max DLS °/100’ – 8° at 1,044’ MD - T & IA PT to 3000 psi (30 min) - Min ID- 2.992” 3-1/2” tubing/liner - Liner is full of ~9.6 ppg 6% KCl mud - Tubing and IA are displaced to 8.4 ppg CIW Pre-Sundry Work: 1. MIRU E-line and pressure control equipment 2. Log well with CBL tool in 3-1/2” liner a. Send results to AOGCC to review prior to perforating 3. RDMO E-line Procedure: 1. Review all approved COAs 2. MIRU Coil Tubing and pressure control equipment 3. PT BOPE to 250 psi low / 3,500 psi high a. Provide AOGCC 48hr notice for BOP test 4. RIH & clean out wellbore to ~7,100 MD, displace liner to 8.4 ppg water 5. Reverse out wellbore with nitrogen, trap ~2400 psi on wellbore a. ~62 bbls total wellbore volume 6. RDMO Coil Tubing 7. MIRU E-line and pressure control equipment 8. PT lubricator to 250 psi low / 2,500 psi high 9. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 10. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: Verbal approval granted for steps 1-6. Well Prognosis 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 ±4,759' ±4,768' ±3,313' ±3,320' ±10' ST A5 ±5,009' ±5,015' ±3,521' ±3,526' ±6' ST A5 ±5,041' ±5,050' ±3,549' ±3,557' ±9' ST C1 ±5,236' ±5,244' ±3,724' ±3,731' ±9' ST C1 ±5,264' ±5,276' ±3,750' ±3,761' ±12' ST C2 ±5,304' ±5,312' ±3,787' ±3,794' ±8' BEL D5 ±5,441' ±5,449' ±3,917' ±3,924' ±8' BEL D5 ±5,455' ±5,463' ±3,930' ±3,938' ±8' BEL D5 ±5,466' ±5,473' ±3,941' ±3,947' ±7' BEL D6 ±5,499' ±5,508' ±3,972' ±3,981' ±9' BEL E6 ±5,690' ±5,700' ±4,157' ±4,167' ±10' BEL E6 ±5,711' ±5,715' ±4,178' ±4,182' ±4' BEL E6 ±5,744' ±5,752' ±4,210' ±4,218' ±8' BEL F4 ±5,853' ±5,858' ±4,317' ±4,322' ±5' BEL F4 ±5,877' ±5,888' ±4,341' ±4,352' ±11' BEL F4 ±5,933' ±5,943' ±4,396' ±4,406' ±9' BEL F4 ±5,953' ±5,957' ±4,416' ±4,420' ±4' BEL F7 ±6,038' ±6,042' ±4,500' ±4,504' ±4' BEL F7 ±6,068' ±6,079' ±4,529' ±4,540' ±11' BEL G1 ±6,156' ±6,168' ±4,616' ±4,627' ±12' BEL G3 ±6,245' ±6,254' ±4,703' ±4,712' ±9' BEL G5 ±6,311' ±6,325' ±4,768' ±4,782' ±14' BEL G10 ±6,388' ±6,396' ±4,844' ±4,852' ±8' BEL H1 ±6,446' ±6,451' ±4,902' ±4,907' ±5' BEL H4 ±6,547' ±6,552' ±5,001' ±5,006' ±5' BEL H4 ±6,559' ±6,567' ±5,013' ±5,021' ±8' BEL H4 ±6,572' ±6,575' ±5,026' ±5,029' ±3' BEL H4 ±6,606' ±6,614' ±5,059' ±5,067' ±7' BEL H4 ±6,625' ±6,630' ±5,078' ±5,083' ±5' BEL H4 ±6,685' ±6,696' ±5,137' ±5,148' ±11' BEL H6 ±6,749' ±6,766' ±5,200' ±5,217' ±17' BEL H6 ±6,804' ±6,824' ±5,254' ±5,274' ±20' a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Pending well production, all perf intervals may not be completed ii. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations b. The Sterling X3 will not be perforated with the Beluga H Sands open, they must be plugged back with minimum of 25ft of cement before the Sterling X3 sand can be perforated. The Sterling X3 will not be perforated with the Beluga H Sands open, they must be plugged back with minimum of 25ft of cement before the Sterling X3 sand can be perforated. Well Prognosis 11. RDMO 12. Turn well over to production & flow test well 13. 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. Coil Tubing BOP Schematic 4. Standard Well Procedure – N2 Operations Updated by DMA 07-01-25 SCHEMATIC Pretty Creek Unit PCU-05 PTD: 225-037 API: 50-283-20203-00-00 PBTD = 7,102’ / TVD = 5,546’ TD = 7,174’ / TVD = 5,617’ RKB to GL = 19.7’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120’ 7-5/8" Surf Csg 29.7 L-80 & P-110 GBBTC & DWC/C 6.875” Surf 2,587’ 3-1/2"Prod Lnr 9.2 L-80 GB ACME 2.992”2,412’7170’ 3-1/2"Prod Tieback 9.3 L-80 8RD EUE 2.992”Surf 2,426’ 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 21’Cactus CTF-ONE-CTL hanger, w/ 4” type H BPV profile 2 2,412’4.790”5-1/2” x 7-5/8” Innovex Hanger/Liner top Packer 3 2,426’3.0 4.5”4” Bullet Seal Assembly spaced x.xx’ OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 155 bbl (358 sx) 12 ppg lead cement followed by 37 bbl (193 sx) 15.8 tail cement. Bumped plug at 129 bbls (calculated 131 bbls), spacer & 69 bbls of contaminated lead cement to surface, no losses during job. 3-1/2” 192 bbls (458 sx) of 12 ppg Type I/II lead followed by 24 bbls (122sx) of 15.3 ppg tail in 6.75” hole. Bumped plug, went on losses after lead hit liner top packer. No cement after setting liner hanger. TOC based on CBL @ xxxx’ To be completed before perforating. 6-3/4” hole 2/3 1 NOTES: 10’ Short jt w/ RA tags 6104, 5418 10’ Short joints 5197, 4640 Deviation Kick off ~545’ build to 63 deg @ 2539’. Drop to 10deg @ 5750’. Max dog leg 8deg/100 @ 1044 and 6deg/100 @ 4730’ Updated by DMA 07-01-25 PROPOSED Pretty Creek Unit PCU-05 PTD: 225-037 API: 50-283-20203-00-00 PBTD = 7,102’ / TVD = 5,546’ TD = 7,174’ / TVD = 5,617’ RKB to GL = 19.7’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120’ 7-5/8" Surf Csg 29.7 L-80 & P-110 GBBTC & DWC/C 6.875” Surf 2,587’ 3-1/2"Prod Lnr 9.2 L-80 GB ACME 2.992”2,412’7170’ 3-1/2"Prod Tieback 9.3 L-80 8RD EUE 2.992”Surf 2,426’ 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 21’Cactus CTF-ONE-CTL hanger, w/ 4” type H BPV profile 2 2,412’4.790”5-1/2” x 7-5/8” Innovex Hanger/Liner top Packer 3 2,426’3.0 4.5”4” Bullet Seal Assembly spaced x.xx’ OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface: 155 bbl (358 sx) 12 ppg lead cement followed by 37 bbl (193 sx) 15.8 tail cement. Bumped plug at 129 bbls (calculated 131 bbls), spacer & 69 bbls of contaminated lead cement to surface, no losses during job. 3-1/2” 192 bbls (458 sx) of 12 ppg Type I/II lead followed by 24 bbls (122sx) of 15.3 ppg tail in 6.75” hole. Bumped plug, went on losses after lead hit liner top packer. No cement after setting liner hanger. TOC based on CBL @ xxxx’ To be completed before perforating. 6-3/4” hole 2/3 1 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments ST X3 ±4,759 ±4,768 ±3,313 ±3,320 ±10 Proposed TBD ST A5 ±5,009 ±5,015 ±3,521 ±3,526 ±6 Proposed TBD ST A5 ±5,041 ±5,050 ±3,549 ±3,557 ±9 Proposed TBD ST C1 ±5,236 ±5,244 ±3,724 ±3,731 ±9 Proposed TBD ST C1 ±5,264 ±5,276 ±3,750 ±3,761 ±12 Proposed TBD ST C2 ±5,304 ±5,312 ±3,787 ±3,794 ±8 Proposed TBD BEL D5 ±5,441 ±5,449 ±3,917 ±3,924 ±8 Proposed TBD BEL D5 ±5,455 ±5,463 ±3,930 ±3,938 ±8 Proposed TBD BEL D5 ±5,466 ±5,473 ±3,941 ±3,947 ±7 Proposed TBD BEL D6 ±5,499 ±5,508 ±3,972 ±3,981 ±9 Proposed TBD BEL E6 ±5,690 ±5,700 ±4,157 ±4,167 ±10 Proposed TBD BEL E6 ±5,711 ±5,715 ±4,178 ±4,182 ±4 Proposed TBD BEL E6 ±5,744 ±5,752 ±4,210 ±4,218 ±8 Proposed TBD BEL F4 ±5,853 ±5,858 ±4,317 ±4,322 ±5 Proposed TBD BEL F4 ±5,877 ±5,888 ±4,341 ±4,352 ±11 Proposed TBD BEL F4 ±5,933 ±5,943 ±4,396 ±4,406 ±9 Proposed TBD BEL F4 ±5,953 ±5,957 ±4,416 ±4,420 ±4 Proposed TBD BEL F7 ±6,038 ±6,042 ±4,500 ±4,504 ±4 Proposed TBD BEL F7 ±6,068 ±6,079 ±4,529 ±4,540 ±11 Proposed TBD BEL G1 ±6,156 ±6,168 ±4,616 ±4,627 ±12 Proposed TBD BEL G3 ±6,245 ±6,254 ±4,703 ±4,712 ±9 Proposed TBD BEL G5 ±6,311 ±6,325 ±4,768 ±4,782 ±14 Proposed TBD BEL G10 ±6,388 ±6,396 ±4,844 ±4,852 ±8 Proposed TBD BEL H1 ±6,446 ±6,451 ±4,902 ±4,907 ±5 Proposed TBD BEL H4 ±6,547 ±6,552 ±5,001 ±5,006 ±5 Proposed TBD BEL H4 ±6,559 ±6,567 ±5,013 ±5,021 ±8 Proposed TBD BEL H4 ±6,572 ±6,575 ±5,026 ±5,029 ±3 Proposed TBD BEL H4 ±6,606 ±6,614 ±5,059 ±5,067 ±7 Proposed TBD BEL H4 ±6,625 ±6,630 ±5,078 ±5,083 ±5 Proposed TBD BEL H4 ±6,685 ±6,696 ±5,137 ±5,148 ±11 Proposed TBD BEL H6 ±6,749 ±6,766 ±5,200 ±5,217 ±17 Proposed TBD BEL H6 ±6,804 ±6,824 ±5,254 ±5,274 ±20 Proposed TBD NOTES: 10’ Short jt w/ RA tags 6104, 5418 10’ Short joints 5197, 4640 Deviation Kick off ~545’ build to 63 deg @ 2539’. Drop to 10deg @ 5750’. Max dog leg 8deg/100 @ 1044 and 6deg/100 @ 4730’ 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 5 JBR 07/23/2025 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:tested w 4.5" DP good test TEST DATA Rig Rep:Kenneth PorterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley Contractor/Rig No.:Hilcorp 147 PTD#:2250370 DATE:6/14/2025 Well Class:DEV Inspection No:divAGE250620135741 Inspector Adam Earl 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:109 P Closest Ignition Source:90 P Outlet from Rig Substructure:98 P Vent Line(s) Anchored:P Turns Targeted / Long Radius:NA Divert Valve(s) Full Opening:P Valve(s) Auto & Simultaneous: Annular Closed Time:27 P Knife Valve Open Time:3 P Diverter Misc:0 NA Systems Pressure:P2850 Pressure After Closure:P1525 200 psi Recharge Time:P29 Full Recharge Time:P115 Nitrogen Bottles (Number of):P4 Avg. Pressure:P2550 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, Undefined Gas Pool, PCU-05 Hilcorp Alaska, LLC Permit to Drill Number: 225-037 Surface Location: 1701' FNL, 2063' FEL, Sec 33, T14N, R9W, SM, AK Bottomhole Location: 1898' FSL, 1742' 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 AOGCCreserves 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 AOGCCspecifically 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 AOGCCorder, 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 1th day of May 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.16 14:42:14 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 7,161' TVD: 5,598' 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): 97.7' 15. Distance to Nearest Well Open Surface: x-342613 y-2654771 Zone-.4 79.2' to Same Pool: 1850' to PCU-02A 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 60 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 2,587' Surface Surface 2,587' 2,098' 6-3/4" 3-1/2" 9.2# L-80 Hyd 563 4,774' 2,387' 1,996' 7,161' 5,598' Tieback 3-1/2" 9.2# L-80 EUE 2,387' Surface Surface 2,387' 1,996' 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 5/20/2025 3382' to nearest unit boundary Nate Sperry nathan.sperry@hilcorp.com 907-777-8450 Tieback Assy. 1280 Cement Volume MD Drilling Manager Monty Myers 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 - 849 ft3 / T - 128 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 2575 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 - 1075 ft3 / T - 131 ft3 2015 545' FSL, 1863' FEL, Sec 28, T14N, R9W, SM, AK 1898' FSL, 1742' FEL, Sec 28, T14N, R9W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1701' FNL, 2063' FEL, Sec 33, T14N, R9W, SM, AK ADL 390780 / ADL 63048 PCU-05 Pretty Creek Unit Undefined Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 2:42 pm, Apr 09, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.04.09 14:27:21 - 08'00' Sean McLaughlin (4311) BOP test to 3000 psi. Annular tests to 2500 psi. 50-283-20203-00-00225-037 Submit FIT/LOT data within 48 hrs of acquiring results. BJM 5/14/25 DSR-4/11/25*&:SFD 5/16/2025 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.16 14:42:27 -08'00'05/16/25 05/16/25 RBDMS JSB 051925 PCU-05 Drilling Program Pretty Creek Unit April 4, 2025 PCU-05 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......................................................................................................25 17.0 Cement 3-1/2” Production Liner................................................................................................29 18.0 3-1/2” Liner Tieback Polish Run................................................................................................33 19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................34 20.0 Diverter Schematic ......................................................................................................................35 21.0 BOP Schematic.............................................................................................................................36 22.0 Wellhead Schematic.....................................................................................................................37 23.0 Anticipated Drilling Hazards......................................................................................................38 24.0 Hilcorp Rig 147 Layout...............................................................................................................40 25.0 FIT/LOT Procedure ....................................................................................................................41 26.0 Choke Manifold Schematic.........................................................................................................42 27.0 Casing Design Information.........................................................................................................43 28.0 6-3/4” Hole Section MASP..........................................................................................................44 29.0 Spider Plot....................................................................................................................................45 30.0 Surface Plat As-Staked................................................................................................................46 Page 2 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 1.0 Well Summary Well PCU-05 Pad & Old Well Designation Pretty Creek Pad– Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Sterling/Beluga Planned Well TD, MD / TVD 7161’ MD / 5598’ TVD PBTD, MD / TVD 7041’ MD AFE Drilling Days 19 Maximum Anticipated Pressure (Surface)2015 psi Maximum Anticipated Pressure (Downhole/Reservoir)2575 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 97.70’ Ground Elevation 79.20’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 2.0 Management of Change Information Page 4 Rev 0.0 April 7, 2025 PCU-05 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 April 7, 2025 PCU-05 Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update x Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 2. Spills: x Notify Drlg Manager 1. Sean Mclaughlin: C: 907-223-6784 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com,andcdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com,and cdinger@hilcorp.com Page 6 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 6.0 Planned Wellbore Schematic Superseded Page 6 Rev 0.0 April 7, 2025 6.0 Planned Wellbore Schematic Page 7 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 7.0 Drilling / Completion Summary PCU-05 is an S-shaped directional grassroots development well to be drilled from Pretty Creek Pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Sterling and Beluga sands. The base plan is an S-shaped directional wellbore with a kickoff point at ~300’ MD. Maximum hole angle will be ~60 deg. and TD of the well will be 7161’ TMD / 5598’ TVD, ending with 10 deg inclination left in the hole. Drilling operations are expected to commence approximately May 20 th, 2025. The Hilcorp Rig # 147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 2587’ MD / 2098’ 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 12.8# FIT. 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 April 7, 2025 PCU-05 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-05. 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 April 7, 2025 PCU-05 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 April 7, 2025 PCU-05 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 April 7, 2025 PCU-05 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 April 7, 2025 PCU-05 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 2587’ MD/ 2098’ 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 April 7, 2025 PCU-05 Drilling Procedure Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-2772’8.8 – 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 April 7, 2025 PCU-05 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 April 7, 2025 PCU-05 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 April 7, 2025 PCU-05 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 April 7, 2025 PCU-05 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 April 7, 2025 PCU-05 Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (2087’ MD to surface)Tail Slurry (2587’ to 2087’ MD) System Extended Conventional Density 12 lb/gal 15.8 lb/gal Yield 2.44 ft3/sk 1.16 ft3/sk Mixed Water 14.40 gal/sk 5.03 gal/sk Mixed Fluid 14.40 gal/sk 5.03 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A CalSeal Accelerator D-Air 5000 Anti Foam VersaSet Thixotropic Calcium Chloride Accelerator D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner BridgeMaker II Lost Circulation Superseded Verified cement calcs. -bjm Page 18 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: 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. Lead Slurry (2087’ MD to surface) Tail Slurry (2587’ to 2087’ MD) System Extended Conventional Density 12 lb/gal 15.8 lb/gal Yield 2.44 ft3/sk 1.16 ft3/sk Mixed Water 14.40 gal/sk 5.03 gal/sk Mixed Fluid 14.40 gal/sk 5.03 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A CalSeal Accelerator D-Air 5000 Anti Foam VersaSet Thixotropic Calcium Chloride Accelerator D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add. FDP-C1446-21 Slurry Conditioner BridgeMaker II Lost Circulation Page 19 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.6 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require running steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.14 R/D cement equipment. Flush out wellhead with FW. 13.15 Back out and L/D landing joint. Flush out wellhead with FW. 13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.17 Lay down landing joint and pack-off running tool. Ensure to report the following on 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 April 7, 2025 PCU-05 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 April 7, 2025 PCU-05 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 April 7, 2025 PCU-05 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 – 9.7 40-53 15-25 15-25 8.5-9.5 11.0 Page 23 Rev 0.0 April 7, 2025 PCU-05 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 (DEN, POR, RES) 15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst.7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 14.0 ppg EMW. A 12.8# ppg FIT will result in a 26.9 bbl KTV. This assumes an 8.6ppg PP and a 9.2ppg MW (swabbed kick). 15.14 Drill 6-3/4” hole section to 7161’ MD / 5598’ 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, and pull a wiper trip back to the 7-5/8” shoe. 15.16 TOH with the drilling assy, standing back drill pipe. Page 24 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 15.17 LD BHA 15.18 RIH to TD, pump sweep, CBU and condition mud for casing run. 15.19 POOH LDDP and BHA Page 25 Rev 0.0 April 7, 2025 PCU-05 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 Ensure 3-1/2” GB ACME x CDS 40 crossover on rig floor and M/U to FOSV x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 3-1/2” production liner x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint to the 7-5/8” shoe. Leave the centralizers free floating. 16.5. Continue running 3-1/2” production liner Page 26 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure Page 27 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure Page 28 Rev 0.0 April 7, 2025 PCU-05 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 29 Rev 0.0 April 7, 2025 PCU-05 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 30 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure Estimated Total Cement Volume: Verified cement calcs. -bjm Superseded Page 30 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure Estimated Total Cement Volume: Page 31 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure Cement Slurry Design: Lead Slurry (6661’ MD to 2387’ MD)Tail Slurry (7161’ to 6661’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss HR-5 Retarder HR-5 Retarder D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner SA-1015 Suspension Agent BridgeMaker II Lost Circulation 17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 17.9. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to up as required by service company procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).Hold pressure for 3-5 minutes. 17.11. Slack off total liner weight plus 30k to confirm hanger is set. 17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls. 17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. Page 32 Rev 0.0 April 7, 2025 PCU-05 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 33 Rev 0.0 April 7, 2025 PCU-05 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 34 Rev 0.0 April 7, 2025 PCU-05 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.48 hr notice required. 19.7 Test 7-5/8” x 3-1/2” annulus to 3000 psi and chart for 30 minutes.48 hr notice required. 19.8 Install BPV in wellhead 19.9 N/D BOPE 19.10 N/U dry-hole tree and test 19.11 RDMO Hilcorp Rig #147 Page 35 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 20.0 Diverter Schematic Page 36 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 21.0 BOP Schematic Page 37 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 22.0 Wellhead Schematic Page 38 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 23.0 Anticipated Drilling Hazards 9-7/8” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 – 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help ensure good cement to surface after running the casing, condition the mud to a YP of 25 – 30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 39 Rev 0.0 April 7, 2025 PCU-05 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 40 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 24.0 Hilcorp Rig 147 Layout Page 41 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 25.0 FIT/LOT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 42 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 26.0 Choke Manifold Schematic Page 43 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 27.0 Casing Design Information Page 44 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 28.0 6-3/4” Hole Section MASP Page 45 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 29.0 Spider Plot Page 46 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure 30.0 Surface Plat As-Staked Page 47 Rev 0.0 April 7, 2025 PCU-05 Drilling Procedure !" #$ % &' &' &' 0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525True Vertical Depth (850 usft/in)-850 -425 0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 Vertical Section at 5.00° (850 usft/in) 7-5/8" x 9-7/8" 3-1/2" x 6-3/4" 5 0 0 1 0 0 0 1 5 0 0 2000250030003500400045005 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 1 6 1 PCU-05 wp04 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 2300' MD, 1953.99' TVD Start Dir 3º/100' : 4000' MD, 2803.99'TVD End Dir : 5666.67' MD, 4126.33' TVD Total Depth : 7161' MD, 5597.96' 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: Pretty CK Unit 5 79.20 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2654771.83 342613.08 61° 15' 47.8321 N 150° 53' 38.6935 W SURVEY PROGRAM Date: 2025-04-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.50 2588.00 PCU-05 wp04 (Pretty CK Unit 5) 3_MWD+AX+Sag 2588.00 7161.00 PCU-05 wp04 (Pretty CK Unit 5) 3_MWD+AX+Sag REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Pretty CK Unit 5, True North Vertical (TVD) Reference:Permit RKB @ 97.70usft (Original Well Elev) Measured Depth Reference:Permit RKB @ 97.70usft (Original Well Elev) Calculation Method: Minimum Curvature Project:Beluga River North Site:Pretty CK Unit 2 Pad Well:Pretty CK Unit 5 Wellbore:Pretty CK Unit 5 Design:PCU-05 wp04 CASING DETAILS TVD TVDSS MD Size Name 2097.70 2000.00 2587.43 7-5/8 7-5/8" x 9-7/8" 5597.96 5500.26 7161.00 3-1/2 3-1/2" x 6-3/4" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.50 0.00 0.00 18.50 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 3 2300.00 60.00 5.00 1953.99 951.30 83.23 3.00 5.00 954.93 End Dir : 2300' MD, 1953.99' TVD 4 4000.00 60.00 5.00 2803.99 2417.94 211.54 0.00 0.00 2427.17 Start Dir 3º/100' : 4000' MD, 2803.99'TVD 5 5666.67 10.00 5.00 4126.33 3340.33 292.24 3.00 180.00 3353.09 End Dir : 5666.67' MD, 4126.33' TVD 6 7161.00 10.00 5.00 5597.96 3598.83 314.86 0.00 0.00 3612.58 Total Depth : 7161' MD, 5597.96' TVD FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3184.70 3087.00 4606.28 Sterling X2 3606.70 3509.00 5117.67 Sterling B3 3659.70 3562.00 5176.44 Sterling C1 3753.70 3656.00 5278.70 Sterling C5 3858.70 3761.00 5390.43 Beluga D5 -225 0 225 450 675 900 1125 1350 1575 1800 2025 2250 2475 2700 2925 3150 3375 3600 3825 4050 South(-)/North(+) (450 usft/in)-225 0 225 450 675 900 1125 1350 1575 1800 2025 2250 2475 2700 West(-)/East(+) (450 usft/in) 7-5/8" x 9-7/8" 3-1/2" x 6-3/4" 250500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 55005598 PCU-05 wp04 Start Dir 3º/100' : 300' MD, 300'TVD End Dir : 2300' MD, 1953.99' TVD Start Dir 3º/100' : 4000' MD, 2803.99'TVD End Dir : 5666.67' MD, 4126.33' TVD Total Depth : 7161' MD, 5597.96' TVD CASING DETAILS TVD TVDSS MD Size Name 2097.70 2000.00 2587.43 7-5/8 7-5/8" x 9-7/8" 5597.96 5500.26 7161.00 3-1/2 3-1/2" x 6-3/4" Project: Beluga River North Site: Pretty CK Unit 2 Pad Well: Pretty CK Unit 5 Wellbore: Pretty CK Unit 5 Plan: PCU-05 wp04 WELL DETAILS: Pretty CK Unit 5 79.20 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2654771.83 342613.08 61° 15' 47.8321 N 150° 53' 38.6935 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Pretty CK Unit 5, True North Vertical (TVD) Reference: Permit RKB @ 97.70usft (Original Well Elev) Measured Depth Reference:Permit RKB @ 97.70usft (Original Well Elev) Calculation Method:Minimum Curvature ( ) & * +,- * . ./ ! ! !#&! 0% "## #$%&'&()*+ ,-. -"/(!0(1 -/ 0- *#$%&'&()*+ ,-. $ % * ,! 2 0 &) 1 -!) 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