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Home My WebLink About225-126Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/10/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260210 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 224-34T 50283202050000 225044 1/30/2026 AK E-LINE Perf T41349 CLU 11RD 50133205590100 225013 1/24/2026 AK E-LINE Perf T41350 CLU 11RD 50133205590100 225013 1/27/2026 AK E-LINE Plug/Perf T41350 KU 24-07RD2 50133203520200 225126 1/14/2026 AK E-LINE CBL T41351 KU 24-07RD2 50133203520200 225126 1/20/2026 AK E-LINE IPFOF T41351 MPI 2-74 50029237850000 224024 1/25/2026 AK E-LINE Whipstock T41352 MPU 1-36 50029236770000 220047 2/1/2026 AK E-LINE Packer T41353 MPU R-110 50029238260000 225085 10/24/2025 YELLOWJACKET RCBL T41354 NFU 14-25 50231200350000 210111 12/29/2025 YELLOWJACKET CBL T41355 SDI 3-15 50029217510000 187094 1/23/2026 AK E-LINE Whipstock T41356 SRU 214A-27 50133101580100 225133 2/4/2026 YELLOWJACKET SCBL T41357 SRU 231-33 50133101630100 223008 7/31/2025 YELLOWJACKET PLUG-PERF T41358 SRU 242-16 50133204050000 188157 1/24/2026 YELLOWJACKET PLUG-PERF T41359 SU 43-10 50133207390000 225107 1/19/2026 YELLOWJACKET GPT-PLUG- PERF T41360 SU 43-10 50133207390000 225107 12/31/2025 YELLOWJACKET SCBL T41360 Please include current contact information if different from above. T41351KU 24-07RD2 50133203520200 225126 1/14/2026 AK E-LINE CBL KU 24-07RD2 50133203520200 225126 1/20/2026 AK E-LINE IPFOF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.10 14:51:05 -09'00' 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: 02/05/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: KU 24-07RD2 PTD: 225-126 API: 50-133-20352-02-00 FINAL LWD FORMATION EVALUATION LOGS (01/07/2026 to 01/13/2026) x ROP, ADR, DGR, ALD, CTN (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey x Pressure While Drilling (PWD) SFTP Transfer - Data Folders: Please include current contact information if different from above. 225-126 T41343 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 15:36:07 -09'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Stefan Reed Cc:Wallace, Chris D (OGC) Subject:RE: KU 24-07RD2 (PTD# 225-126) Date:Monday, January 19, 2026 5:45:00 PM Attachments:image003.png Stefan, Hilcorp has verbal approval to proceed with the scope of work included in the recent sundry application, with the following conditions: Hilcorp must receive EPA approval for the alternative packer set depth and before beginning waste disposal. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Stefan Reed <stefan.reed@hilcorp.com> Sent: Monday, January 19, 2026 8:51 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: KU 24-07RD2 (PTD# 225-126) Bryan, As discussed, we are planning to pull the ball and rod on KU 24-07RD2 today and begin perforating tomorrow per the submitted sundry. Confirming this is acceptable. Thanks. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2026.01.14 14:27:03 - 09'00' Noel Nocas (4361) 326-031 10-407 CDW 01/15/2026 EPA approval is required before waste disposal may begin. EPA AK-1I018-A Class I, DIO 11 Class II. CDW BJM 1/16/26JLC 1/20/2026 01/20/26 Initial Completion Well: KU 24-07RD2 Well Name: KU 24-07RD2 API Number: 50-133-20352-02-00 Current Status: Class I Disposal Well Permit to Drill Number: 225-126 First Call Engineer: Stefan Reed (907) 777-8433 (206) 755-0301 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (907) 229-4824 (C) Maximum Expected BHP: 2313 psi @ 3,728 TVD (Derived from pressure transient analysis) Max. Potential Surface Pressure: 2200 psi (Permit limit, pump shutdown pressure) Well Status: New Drill Well Initial Completion. Class I Disposal Well Brief Well Summary KU 24-07RD2, sidetrack of KU 24-07RD, is a class I disposal well injecting in the Sterling sands and governed by EPA permit # AK-1I018-A. Hilcorp requests approval according to 20 AAC 25.412(b) to perforate the lowest proposed interval first for injection. The initial proposed perf interval is 4,522-4,560ft (which puts the planned packer 294ft above the perforation if all Sands work. We are hoping this interval will accept the waste below the regulatory pressure limits listed in the EPA Class 1 Permit. Placing the packer at 4,228ft (200 above top of proposed future perforation interval in the A10 sand) allows future perforations within the authorized interval without having to complete a rig workover. Slickline Procedure: 1. MIRU Slickline. 2. PT PCE 250/2500psi. 3. Pull ball/rod and plug body from tubing. 4. Drift w/ 3.70 GR to TD 5. RDMO Slickline. E-line Procedure: Ensure EPA has been notified and inspector provided notice to witness test. 1. MIRU E-line. 2. Pressure test PCE 250/2500psi. 3. RIH and perforate intervals below, from bottom up: Pool Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Sterling A10 ±4,428 ±4,497 ±3,745 ±3,804 ±69 Sterling A11 ±4,522 ±4,560 ±3,825 ±3,858 ±38' a. All perf intervals may not be completed. 4. Stand by for well to stabilize, minimum 12hrs. 5. Make up Pressure/Temperature logging tools. 6. RIH at 30fpm logging baseline temperature/pressure pass from surface to TD. 7. Place tool directly above perfs at ~4,427. Record pressure/temperature while conducting step rate test. 8. Log warmback passes from ~4,128 TD. Discuss time intervals with OE/WSL target 1, 3 and 6 hour warmbacks. 9. RDMO E-Line AOGCC can approve the variance request to the 200 ft packer to perforation requirement. Hilcorp separately must get EPA approval of this change. CDW 01/15/2026 Initial Completion Well: KU 24-07RD2 Step Rate Test and ISIP: Ensure EPA has been notified and inspector provided notice to witness test. 1. Prepare facility to inject water/brine down well. 2. Ensure e-line tools are on depth and ready for well to be on injection. 3. Flow rate to be controlled by pump speed 4. Flow rate will be measured by facility Coriolis meter 5. Surface pressure and rates will be recorded on SCADA system 6. Perform step rate test for 30 minutes at each rate listed below with a max pump rate of 4bpm and maximum surface pressure of 2,200psi: Formation permeability estimated at 200-300mD a. 0.2 bbl/min b. 0.4 bbl/min c. 0.8 bbl/min d. 1.6 bbl/min e. 2.4 bbl/min f. 3.2 bbl/min g. 4.0 bbl/min 7. Record entire step rate test on SCADA system 8. Once step rate test is completed, isolate the well and record the Instantaneous Shut-in pressure (ISIP). Restart Injection: 1. EPA must provide authorization prior to resuming waste injection Attachments: 1. Proposed Schematic 2,200psi: _____________________________________________________________________________________ Updated by SAR 01-16-26 PROPOSED SCHEMATIC Kenai Gas Field Well: KU 24-07RD2 PTD: 225-126 API: 50-133-20352-02-00 TD =4,4 812(MD) / 4,074(TVD)44 20 RKB: GL = 18.5 7 3 2 13-3/8 9-5/85 1 PBTD =4,722(MD) / 3,997(TVD) KU 24-07RD CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 94 /H-40 / Weld 19Surf 179 13-3/8Surface 61 /K-55 /BTC 12.515Surf 2,003 9-5/8" Intermediate 43.5 & 47 / N-80 / BTC 8.681 Surf 2,270 (TOW) 7" Liner 29 / L-80 &P110/ DWC/C 6.184 2,0573,062 29 / P-110IC / TXP BTC 6.184 3,062 3,996 29 / L-80 / CDC-HTQ 6.1843,9964,810 Tubing Detail 4-1/2Tubing 12.6 /L-80 /IBT 3.958Surface 4,254 JEWELRY DETAIL No Depth Item 1 2,0577 Liner Top Packer 2 4,235 4-1/2 Production Packer to be placed within 200 of proposed top perforation. 3 4,252XN Nipple (ID 3.725) OPEN HOLE / CEMENT DETAIL 17-1/2 1225 sx pumped on original KU 24-07D 12-1/4"1900 sx pumped on original KU 24-07D 8-1/2 291 sx Class G cement 12.5ppg lead, 15.3ppg tail, no losses. TOC 2,276 per CBL on 1/15/2026 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Ft Date Status Sterling Pool 3,Top of Pool -3,848MD/3,243 TVD A10 ±4,428 ±4,497 ±3,745 ±3,804 ±69TBD Proposed A11 ±4,522 ±4,560 ±3,825 ±3,858 ±38'TBD Proposed Sterling Pool 4,Top of Pool -4,594MD/3,887 TVD Sterling Pool 5,Top of Pool -4,710MD/3,986 TVD 1 Dewhurst, Andrew D (OGC) From:Stefan Reed <stefan.reed@hilcorp.com> Sent:Friday, 16 January, 2026 14:25 To:Dewhurst, Andrew D (OGC) Cc:McLellan, Bryan J (OGC); Wallace, Chris D (OGC) Subject:RE: [EXTERNAL] KU 24-07RD2 Perf Sundry (326-031): Question Attachments:KU 24-7RD2_Final Surveys.xlsx; KU 24-07RD2 FIELD FINAL TVD.pdf; KU 24-07RD2 FIELD FINAL MD.pdf; KU 24-07RD2 Recorded FE DATA.las; KU 24-07RD2 Proposed Schematic_ 2026_Updated.doc Andrew, Understood, there was some urgency getting this in to accommodate the EPAs schedule for witness. The well has now been TDd. Requested information attached. The schematic has been updated with all casing/tubing depths, perf intervals, and pool tops. Let me know if you need anything else. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Friday, January 16, 2026 1:34 PM To: Stefan Reed <stefan.reed@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: [EXTERNAL] KU 24-07RD2 Perf Sundry (326-031): Question Stefan, Im reviewing the perf sundry for the Kenau Unit 24-07RD2 well. Has this well been TDd yet? It looks like much of the information is estimated. You may not be aware, but since the beginning of Q4 2025, we have been requesting that perforation sundries be held until you have the following minimum information: TD/actual casing depths CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 Directional survey LWD logs Proposed perforated intervals Pool tops Shallowest perf calculation (if applicable) We will continue to approve perforation sundries before the CBL results have come in. That will continue to be a condition of approval that can be ful lled verbally/via email. Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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: Kenai Unit Field, Undefined WDSP, KU 24-07RD2 Hilcorp Alaska, LLC Permit to Drill Number: 225-126 Surface Location: 723' FNL, 749' FEL, Sec 18, T4N, R11W, SM, AK Bottomhole Location: 138' FNL, 2122' FWL, Sec 18, T4N, R11W, SM, AK Dear Mr. McLaughlin: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, . Commissioner DATED this 19 th day of December 2025. 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: 4,704' TVD: 4,013' 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): 86.6 15. Distance to Nearest Well Open Surface: x-275056 y- 2356014 Zone-4 68.1 to Same Pool: 380' to KU 24-07RD 16. Deviated wells: Kickoff depth: 2,300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 47 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 8-1/2" 7" 29# Multiple Multi 2,604' 2,100' 1,922' 4,704' 4,013' Tubing 4-1/2" 12.6# L-80 IBT 4,320' Surface Surface 4,320' 3,680 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): 4410' TVD 179' 1849' 3275' 4024' 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 12/24/2025 5143' to nearest unit boundary Zachary Browning zachary.browning@hilcorp.com 208-301-0767 4800' 2638 Cement Volume MD Driven 179' 2003'13-3/8" 1225 sx Drilling Manager Sean Mclaughlin 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): 2003' 1900 sx 200 sx To be plugged Conductor/Structural 20"179' Authorized Title: Authorized Signature: 7" Authorized Name: Production Liner 3814' 1323' Intermediate 4800'4023' LengthCasing N/A Size Plugs (measured): (including stage data) L - 367 ft3 T - 105 ft3 N/A 4415' 3728' Effect. Depth MD (ft): Effect. Depth TVD (ft): 18. Casing Program: Top - Setting Depth - BottomSpecifications 1766 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 1414 354' FNL, 2379' FWL, Sec 18, T4N, R11W, SM, AK 138' FNL, 2122' FWL, Sec 18, T4N, R11W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 723' FNL, 749' FEL, Sec 18, T4N, R11W, SM, AK ADL390821 KU 24-07RD2 Kenai Gas Field Undefined WDSP Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. To be plugged 3814'9-5/8" s N ype of W L l R L 1b S Class: os N s No s N o D s s s D 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.11.17 16:45:13 - 09'00' Sean McLaughlin (4311) 225-126 By Grace Christianson at 7:40 am, Nov 18, 2025 A.Dewhurst 18DEC25 DSR-11/19/25BJM 12/4/25 CDW 11/20/2025 50-133-20352-02-00 AOGCC DIO 11 Class II well. EPA permit AK-1I018-A Class I well. CDW BOP test to 2500 psi EPA approval is required before waste disposal may begin. Submit FIT/LOT data to AOGCC within 48 hrs of performing test. Monitor 10-3/4" x 7-5/8" Outer Annulus of well KBU 31-18 (PTD 215-024) for 12 months after injection begins in KU 24-07RD2. Submit quarterly pressure plot to AOGCC noting the date of any pressure bleed event, including beginning and final bleed pressures. KBU 31-18 is within the Area of Review and has questionable cement across and above the injection zone. JLC 12/19/2025 12/19/25 12/19/25 PTDAPIWell Name StatusSterling A10 Top (MD)Sterling A10 Top (TVD)TOC (MD)TOC(TVD)Zonal Isolation205-099 50-133-20352-01-00 KU 24-07RDClass II Injection Well (to be abandoned)4,377' 3,699' 3,486' 3,028'8-1/2" hole w/ 7" liner. 68bbls 12.5ppg class G cement. Cement to liner top packer at 3,486' from CBL 6/27/2005.206-127 50-133-20564-00-00 KBU 24-07XCurrent Producer in Beluga/Upper Tyonek Gas Pool4,367' 3,679'3500' 2952'Primary: 12-1/4" hole w/ 9-5/8" Casing. 105bbls 12.5ppg Class G lead cement and 84.5bbls 13.5 Class G tail cement. No cement returns. Remedial: Perforate at 4870' MD and circulate annulus with 105bbls 12.5ppg Class G lead cement and 25bbls 15.8 Class G tail cement. 100% returns during cement job. Perform CBL from 5982' to 3200'. Unable to determine TOC above 3500' due to eccentering. 215-024 50-133-20649-00-00 KBU 31-18Current Producer in Beluga/Upper Tyonek Gas Pool3,785' 3,736' 3,354 3,3259-7/8" hole w/ 7-5/8" casing. Pumped 142bbls of 13.5ppg Class G lead cement and 29.7bbls of 15.3ppg Class G tail. 45% losses during job. TOC @ 3,354' from "Volume calc vs Hole Depth." 3/25/2015182-016 50-133-20352-00-00 KU 24-07P&A'd4,381' 3,703' 2,100 1,923'12-1/4" hole w/ 9-5/8" casing. Cementedw/ 1900 sacks of class G cement. TOC @ 2,100' from CBL 5/25/1982Area of Review for KU 24-07RD2Monitoring of KBU31-18 OA pressureswill be required.-A.Dewhurst 18DEC25 Intermediate 7-5/8" csg appears to be cemented but with only 45% returns I estimate TOC at 4836' MD. -bjm Superseded KU 24-07RD2 Drilling Program Kenai Gas Field November 17, 2025 KU 24-07RD2 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 Current Schematic (Plugging Plan) .............................................................................................6 7.0 Planned Wellbore Schematic........................................................................................................7 8.0 Drilling / Completion Summary...................................................................................................8 9.0 Mandatory Regulatory Compliance / Notifications....................................................................9 10.0 R/U and Preparatory Work (Sundry ).....................................................................................11 11.0 BOP N/U and Test........................................................................................................................12 12.0 Decomplete...................................................................................................................................12 13.0 Set Whipstock / Mill Window.....................................................................................................13 14.0 Drill 8-1/2 Hole Section..............................................................................................................14 15.0 Run 7 Production Liner ............................................................................................................15 16.0 Cement 7 Production Liner ......................................................................................................19 17.0 Run 4-1/2 Production Tubing, ND/NU, RDMO......................................................................22 18.0 BOP Schematic.............................................................................................................................23 19.0 Wellhead Schematic.....................................................................................................................24 20.0 Anticipated Drilling Hazards......................................................................................................25 21.0 Hilcorp Rig 147 Layout...............................................................................................................26 22.0 Choke Manifold Schematic.........................................................................................................27 23.0 Casing Design Information.........................................................................................................28 24.0 8-1/2 Hole Section MASP..........................................................................................................29 25.0 Spider Plot (660).........................................................................................................................30 26.0 Surface Plat (As-Built NAD27 & NAD83).................................................................................31 Page 2 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 1.0 Well Summary Well KU 24-07RD2 Rig 147 Pad & Old Well Designation KGF 41-18 Pad / KU 24-07RD2 Planned Completion Type 7 Production Liner w/ 4-1/2 Production Tubing Target Reservoir(s) Lower Beluga A10 / A11 Sands Planned Well TD, MD / TVD 4704 MD / 4013 TVD PBTD, MD / TVD 4624 MD / 3944 TVD AFE Days 17 days API 50-133-20352-02-00 Maximum Anticipated Pressure (Surface) 1414 psi Maximum Anticipated Pressure (Downhole/Reservoir) 1766 psi (.44psi/ft gradient) Work String 4-1/2 16.6# S-135 DS-40 RKB 86.6 Ground Elevation 68.1 BOP Equipment 11 5M Annular BOP 11 5M Double Ram 11 5M Single Ram Page 3 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 2.0 Management of Change Information Page 4 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 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) 8-1/2 7 6.184 6.059 7.875 29 L-80 DWC/C 8160 7030 676 7 6.184 6.059 7.875 29 P110 DWC/C 11220 8530 929 7 6.184 6.059 7.75 29 P110 IC BTC TXP 11220 9580 929 7 6.184 6.059 7.875 29 L-80 CDC-HTQ 8160 7020 676 Cased hole 4-1/2 3.958 2.867 5.2012.6 L-80 IBT 8440 6680 288 *Ensure at least 100 of overlap between casing and liner 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 4-1/23.826 2.6875 5.2516.6 S-135 CDS40 17,693 16,773 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellview. Report covers operations from 6am to 6am Ensure time entry adds up to 24 hours total. Capture any out-of-scope work as NPT. 5.2 Afternoon Updates Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update Submit a short operations update each morning by 7am in NDE Drilling Comments 5.4 EHS Incident Reporting 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, dont 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: Notify Drlg Manager 1. Sean McLaughlin: C: 907-223-6784 Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally Send final As-Run Casing tally to Zachary.browning@hilcorp.com, and cdinger@hilcorp.com 5.6 Casing and Cmt report Send casing and cement report for each string of casing to Zachary.browning@hilcorp.com, and cdinger@hilcorp.com Page 6 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 6.0 Current Schematic Page 7 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 7.0 Planned Wellbore Schematic Page 8 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 8.0 Drilling / Completion Summary KU 24-07RDis a G&I disposal well for injecting Class I waste into the Sterling sands that is governed by EPA permit # AK-1I018-A. The well was reclassified from a Class II well to EPA Class I well in September of 2021. In September of 2024 a CTCO was attempted, but failed due to an obstruction encountered in the well, which resulted in part of a coil milling BHA being left in hole. In December of 2024 a rig workover was done to replace tubing/packer and attempted fish coil tools and clean out well. The rig was unable to retrieve coil fish or clean out the well and the new tubing and packer were run with fish/fill still in well. Due to the obstructions in well and inability to clean out the well the injection pressures have maintained near the regulatory limits. The base plan is to de-complete the well with rig 147 by pulling the 4 ½ tubing currently installed and abandoning the 7 Liner with a CIBP and dump bail cement. The 9-5/8 casing will be evaluated and a CIBP set with dump bail cement. A whipstock will be set at ~2300 MD / 2079 TVD and window milled. The sidetrack will be a single string slant wellbore with a TD at 4704 MD / 4013 TVD. Maximum hole angle will be ~47 deg. A 7 Production liner string will be run and cemented and the 4 ½ production tubing will be re-run with a packer set above the disposal zone. Drilling operations are expected to commence approximately December 2025. The Hilcorp Rig #147 will be used to drill the wellbore then run casing and cement. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. Rig 147 will MIRU over KU 24-07RD2 (Sundry ) 2. Load well with KWF (8.4ppg freshwater). 3. Install BPV. 4. ND tree, NU BOPE 5. Test BOPE against blanking sub to 2500 psi. (MASP 1414psi) 6. Pull BPV. 7. Engage hanger and overpull tubing 50klbs to release packer. 8. Circulate well with freshwater. 9. Pull and lay down 4-1/2 12.6# L-80 IBT-M tubing a.Inspect tubing and hanger to be rerun. 10. RU Eline a. Set 7 CIBP. Drift & tag top of plug. Pressure test to 1500psi. i.Provide AOGCC 24hrs notice to witness tag and PT. b. Dump bail a minimum of 35 of cement (~56gals) on plug. c. Run CBL log across 9-5/8 casing. d. Set 9-5/8 CIBP above 7 TOL. Drift and tag top of plug. Pressure test to 3165psi. i.Provide AOGCC 24hrs notice to witness tag and PT. Hilcorp to verify if Class II (DIO 11, DIO 11.001) is still applicable and request to cancel DIO 11. Hilcorp to change well status from Class II to Class I via a 10-403. Currently AOGCC has this well as dual Class I and Class II. CDW 12/02/2025 Steps 1-11 are not authorized under this permit to drill. See sundry #325-705 for KU 24-07RD (PTD 205-099) for approved plugging procedure. -bjm p Run CBL log across 9-5/8 casing. j g g g y The well was reclassified from a Class II well to EPA Class I well in Septemberp of 2021. Page 9 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX e. Dump bail a minimum of 35 of cement (~108gals) on plug. f. RD Eline 11. Set 9-5/8 42-47# whipstock at ~2300 and 30L TF. Swap well to 8.8 ppg 6% KCL mud. 12. Mill window with 20 of new formation.(Permit to Drill ) 13. Perform FIT to 12.0 ppg EMW. 14. MU 8-1/2 bit with 6-3/4 tools (Triple Combo) 15. Drill 8-1/2 Production hole to 4704 MD / 4013 TVD. 16. Run 7 Production Liner. TOC planned to TOL at 2100 MD 17. Rig up eline and run CBL. Perform liner and liner top packer test to 3165 psi. 18. Run 4-1/2 completion. Land hanger and test. 19. Set production packer. MIT-T to 3000 psi, MIT-IA to 3000 psi 20. ND BOPE, NU tree and test void. Reservoir Evaluation Plan: Production Hole: Triple Combo 9.0 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. BOPs shall be tested at (2) week intervals during the drilling of KU 24-07RD2. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. The initial test of BOP equipment will be 250/2500 psi & subsequent tests of the BOP equipment will be to 250/2500 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. If the BOP is used to shut in on the well in a well control situation 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. All AOGCC regulations within 20 AAC 25.033 Primary well control for drilling: drilling fluid program and drilling fluid system. All AOGCC regulations within 20 AAC 25.035 Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office. The scope approved under this PTD begins with step #12. -bjm Page 10 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 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. EPA will be notified of the expected spud of the well and per the agree completions checklist. Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2 11 x 5M Annular BOP 11 x 5M Double Ram o Blind ram in btm cavity Mud cross 11 x 5M Single Ram 3-1/8 5M Choke Line 2-1/16 x 5M Kill line 3-1/8 x 2-1/16 5M Choke manifold Standpipe, floor valves, etc Initial Test: 250/2500 (Annular 2500 psi) Subsequent Tests: 250/2500 (Annular 2500 psi) Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: Well control event (BOPs utilized to shut in the well to control influx of formation fluids). 24 hours notice prior to testing BOPs. 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) Page 11 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) 10.0 R/U and Preparatory Work (Sundry ) 1. Level pad and ensure enough room for layout of rig footprint and R/U. 2. Layout Herculite on pad to extend beyond footprint of rig. 3. R/U Hilcorp Rig #147, spot service company shacks, spot & R/U company man & toolpusher offices. 4. After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 5. 8-1/2 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 drillers console, Co Man office, and Toolpusher office. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:8.8 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 2300- 4704 8.8 9.5 40-53 15-25 15-25 8.5-9.5 11.0 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 8.8 9.5 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) Page 12 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 6. Install 5-1/2 liners in mud pumps. HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2 liners. 11.0 BOP N/U and Test 1. Load well with kill weight fluid (8.4ppg freshwater). 2. Install BPV. 3. N/D Tree and adapter. Install blanking sub. 4. N/U 11 x 5M BOP as follows: 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 Double ram should be dressed with 7 fixed bore rams in top cavity, blind ram in bottom cavity. Single ram should be dressed with 2-7/8 x 5 variable bore rams N/U bell nipple, install flowline. Install (2) manual valves & a check valve on kill side of mud cross. Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 5. Test BOPE. Test BOP to 250/2500 psi for 5/10 min. 7 test joint required for FBR Test VBRs with 4-1/2 test joint Test annular to 250/2500 psi for 5/10 min with a 4-1/2 test joint Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Pull blanking sub and BPV after successful test. 6. Rack back as much 4-1/2 DP in derrick as possible to be used while drilling the hole section. 12.0 Decomplete 1. PU short joint to engage hanger. 2. Overpull tubing 50klbs to release packer. 3. Pull and lay down 4-1/2 12.6# L-80 IBT-M Tubing a. Inspect tubing to be re-run. Note: previous workovers required 9.4 ppg brine to kill the well. Be prepared to weight up. -bjm Note: previous workovers required 9.4 ppg brine to kill the well. Be prepared to weight up and circulate kill weight fluid. -bjm Page 13 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 4. Set wear bushing in wellhead. Ensure ID of wear bushing > 8.5. 5. RU Eline and perform following: a. Drift and tag top of fill for correlation w/ ~5.7 GR/Junk Basket b. Set 7 CIBP @ ~4340 (Not more than 50 above top of fill/fish). c. Drift & tag top of plug. Pressure test to 1500psi. i.Provide AOGCC 24hrs notice to witness tag and PT. d. Dump bail a minimum of 35 of cement (~56gals) on plug. e. Drift 9-5/8 casing w/ ~7.71 GR/Junk Basket f. Log CBL in 9-5/8 casing. g. Set 9-5/8 CIBP @ ~ 3432 (25ft above the 7 TOL) h. Drift and tag top of plug. Pressure test to 3165psi. i.Provide AOGCC 24hrs notice to witness tag and PT. ii. AOGCC requirement is 50% of burst. 9 5/8 43.5# N-80 burst is 6330 psi / 2 = 3165 psi. i. Dump bail a minimum of 35 of cement (~108gals) on plug. j. RD Eline 13.0 Set Whipstock / Mill Window Operation Steps: 1. Make up the WIS hydraulic-set whipstock. 2. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock assembly Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly. Avoid sudden starts and stops while running the whipstock. Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly when releasing the work string to RIH. These precautions are required to avoid any weakening of the whipstock shear mechanisms and / or to avoid part / preset on the packer. 3. Orient whipstock as directed by the directional driller. The directional plan (WP2) specifies 30 deg LOHS. 4. Set the top of the whipstock at ~2300 MD Confirm exact set depth with 9-5/8 collar location from Eline logs to avoid milling a collar. (Permit to Drill ) Page 14 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 5. Mill window plus 20-50 of new hole (DO NOT EXCEED 50 OF NEW HOLE BEFORE RUNNING THE PLANNED FIT/LOT).(Permit to Drill ) Use ditch magnets to collect the metal shavings. Clean regularly. Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and Kevlar gloves. Work the upper mill through the window to confirm the window milling is complete and circulate well clean (circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface. 6. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a FIT to 12.0 ppg. **Assuming the kick zone is at TD, a FIT of 12.0 ppg EMW gives a Kick Tolerance volume of 49 bbls with 8.8ppg mud weight. Monitor OA during FIT and report and change in pressure. 7. POOH and LD milling assembly Once out of the hole, inspect mill gauge and record. Flow check well for 10 minutes to confirm no flow: Before pulling off bottom. Before pulling the BHA through the BOPE. 8. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP equipment is operable. 14.0 Drill 8-1/2 Hole Section 1. P/U 6-3/4 Sperry Sun motor drilling assy w/ triple combo tools (DEN, POR, RES) and 8-1/2 bit 2. Ensure BHA components have been inspected previously. 3. Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 4. Ensure TF offset is measured accurately and entered correctly into the MWD software. 5. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at ~400 gpm. 6. TIH to window. Shallow test MWD on trip in if required. Minimum FIT is 12.0 ppg EMW, which provides 17 bbls kick tolerance with 9.5 ppg mud. Contact AOGCC if well leaks off below 12.0 ppg EMW and obtain approval before drilling production hole section. -bjm Page 15 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 7. Circulate well with 8.8 ppg mud to warm up mud until good 8.8 ppg in and out. 8. Drill 8-1/2 hole to TD at 4704 MD / 4013 TVD using motor assembly. Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. Keep swab and surge pressures low when tripping. Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. Take MWD surveys every 100 drilled. Surveys can be taken more frequently if deemed necessary. Minimize backreaming when working tight hole. 9. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU 2X. 10. Clean out wellbore as necessary 11. TOH with drilling assembly, handle BHA as appropriate. 12. Confirm 7 FBR previously installed in BOP stack and tested with 7 test joint. 15.0 Run 7 Production Liner 1. R/U Parker 7 casing running equipment. NOTE:Wear bushing can be left installed. Max OD of liner assembly:8.255in OD (hanger OD) Min ID of wellbore:8.5in Wear bushing Ensure 7DWC/C, TXP BTC and CDC-HTQ x CDS40 XOs on rig floor and M/U to FOSV. Use proper thread compound. Dope pin end only w/ paint brush. Ensure all casing has been drifted to 6 on the location prior to running. Note that 29# drift is 6.059 Be sure to count the total joints on the location before beginning liner run. Keep hole covered while R/U casing tools. Record ODs, IDs, lengths, S/Ns of all components w/ vendor & model info. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking 80 shoe track assembly consisting of: Page 16 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 7 Float Shoe 1 joint 7 BTC, 1 Centralizer 10 from bottom w/ stop ring 7 Float Collar 1 joint 7 BTC, 1 Free floating centralizer 7 Landing collar 4. Continue running 7 intermediate casing Centralization: 1 centralizer every joint to the window Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 17 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX Page 18 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 5. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 6. Slow in and out of slips. 7. Lower string to planned depth and confirm a connection is not across wellhead profile. 8. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. 9. Stage up pump slowly and monitor losses closely while circulating. 10. After circulating, lower string and confirm connection is not across the wellhead. Cement to surface is not expected. However, in the event cement is circulated out ensure hose is in place to take returns to the cellar. Page 19 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 16.0 Cement 7 Production Liner 1. Hold a pre-job safety meeting over the upcoming cement 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 cementing unit at acceptable rates. Determine which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. Ensure adequate amount of water for mix fluid is heated and available in the water tanks. Confirm positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses Review test reports and ensure pump times are acceptable. Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 2. Document efficiency of all possible displacement pumps prior to cement job. 3. Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 4. R/U cement line (if not already done so). 5. Fill surface cement lines with water and pressure test to 4500psi. 6. Pump remaining tuned spacer. 7. Mix and pump cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 8. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to TOL. Page 20 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX Estimated Cement Volume: 9. Attempt to rotate and reciprocate liner during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights and Torque, if the hole gets sticky, cease pipe movement and place liner at set depth, and continue with the cement job. 10. Displace cement at max rate of 4 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. a. Place liner on depth when DP dart enters into the liner hanger and before bumping the plug. b. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, and cementers during the entire job. c. Use rig pumps to displace cement. Verified cement calcs. -bjm Page 21 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 11. 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. 12. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 13. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 3 bbls (shoe track volume) before consulting with Drilling Engineer. 14. Bump the plug and pressure up per YJOS rep to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 15. Slack off liner weight plus ~30k to confirm hanger is set. 16. Not expected but be prepared for cement returns to surface. Cement returns to be taken to cellar. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. 17. R/D cement equipment. Flush out wellhead with freshwater. 18. POOH with DP. Ensure to report the following on wellview: Pre flush type, volume (bbls) & weight (ppg) Cement slurry type, lead or tail, volume & weight Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Note if liner is reciprocated or rotated during the job Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note if pre flush or cement returns at surface & volume Note time cement in place Note calculated top of cement 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 Zachary.browning@hilcorp.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 19. RU Eline and run 7 CBL. (1000 psi compressive strength required prior to CBL) 20. Pressure test 7 liner and LTP to 3165psi. run 7 CBL Page 22 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX AOGCC requirement is 50% of burst. 9 5/8 43.5# N-80 burst is 6330 psi / 2 = 3165 psi. (Test to 9- 5/8 requirement since it is exposed) Ensure Tail Cement has reached 500psi compressive strength. 17.0 Run 4-1/2 Production Tubing, ND/NU, RDMO 1. Run 4-1/2 tubing completion assembly to above the liner top Tubing will be re-run 4-1/2 L-80 12.6# IBT Production packer set at ~4300, within 200 proposed top perf. 2. Swap the well over to CI Water 3. Space out and land seal bore in tie back sleeve. RILDs. 4. Set packer per rep. 5. Test IA to 3000 psi and tubing to 3000 psi. Charted 30 min. 6. Install BPV in wellhead. 7. ND BOPE, NU tree, test void 8. Rig Down. Page 23 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 18.0 BOP Schematic Page 25 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 20.0 Anticipated Drilling Hazards 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. 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. Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. Use asphalt-type additives to further stabilize coal seams. Increase fluid density as required to control running coals. Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal pressures are present in this hole section. Page 26 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 21.0 Hilcorp Rig 147 Layout Page 27 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 22.0 Choke Manifold Schematic Page 28 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 23.0 Casing Design Information 8-1/2"Mud Density:8.8-9.5 ppg Mud Density: Mud Density: 1414 psi (see attached MASP determination & calculation) 1414 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.45 psi/ft) and the casing evacuated for the internal stress 1 2 3 4 7 7 7 7 2,100 2,736 3,086 4,302 1,923 2,412 2,661 3,665 2,736 3,086 4,302 4,704 2,412 2,661 3,665 4,013 636 350 1,216 402 29 29 29 29 L80 P110 P110IC L80 DWC/C DWC/C BTC TXP CDC-HTQ 18,444 10,150 35,264 11,658 75,516 57,072 46,922 11,658 676 929 929 676 8.95 16.28 19.80 57.99 1,061 1,171 1,613 1,766 7,030 8,530 9,580 7,020 6.62 7.29 5.94 3.98 1,414 1,414 1,414 1,414 8,160 11,220 11,220 8,160 5.77 7.93 7.93 5.77 MASP: DATE: 11/12/25 WELL: KU 24-07RD2 FIELD: Kenai Gas Field DESIGN BY: Zach Browning Hole Size Hole Size Worst case safety factor (Burst) Minimum Yield (psi) Weight (ppf) Grade Connection Weight w/o Bouyancy Factor (lbs) Min strength Tension (1000 lbs) Collapse Resistance w/o tension (Psi) Calculation & Casing Design Factors Calculation/Specification Casing OD Worst Case Safety Factor (Collapse) MASP (psi) Worst Case Safety Factor (Tension) Collapse Pressure at bottom (Psi) Tension at Top of Section (lbs) Bottom (TVD) Length Bottom (MD) MASP: Top (MD) Drilling Mode Design Criteria: Casing Section Top (TVD) Hole Size MASP: Production Mode 18,444 10,150 35,264 11,658 Page 29 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 24.0 8-1/2 Hole Section MASP MD TVD Planned Top: 2,300 2,079 Planned TD: 4,704 4,013 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad KOP 2982 Depleted gas 0.0 0.00 Top Pool 3_A6 3432 1450 Depleted gas 8.1 0.42 Top Pool 4 3847 350 Depleted gas 1.7 0.09 TD: Top Pool 5 4012 1766 Depleted gas 8.5 0.44 Offset Well Pressure (RFT) Well Year PSI TVD KU 42-12 2020 461 3748' (A11) KU 24-32 2020 507 3,808' (A11) Assumptions: 1. Field test data suggests the Fracture Gradient at the casing shoe is btwn 12.0 and 15.0 ppg EMW. 15.0ppg (.78psi/ft) used. 2. HSPP of 1950psi at well TD used. Expected pressure is 1650-1950psi. 3. Calculations assume 0.1 ppg gas to surface Fracture Pressure at the KOP considering a full column of gas from shoe to surface: 2079 (ft) x 0.78(psi/ft)= 1622 psi 1622 (psi) - [0.1(psi/ft)*2079(ft)]= 1414 psi MASP from pore pressure during production mode (Complete evacuation to gas) 4013 (ft) x 0.44(psi/ft)= 1766 psi 1766(psi) - 0.1(psi/ft)*4013(ft) 1365 psi Summary: 1. MASP while drilling production hole is governed by frac at shoe with gas to surface Maximum Anticipated Surface Pressure Calculation 8-1/2" Hole Section WELL: KU 24-07RD2 FIELD: Kenai Gas Field HSPP of 1950 psi @ TD 4012' TVD = 9.35 ppg EMW. -bjm Page 30 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 25.0 Spider Plot (660) Page 31 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 26.0 Surface Plat (As-Built NAD27 & NAD83) Page 32 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX Page 33 Rev 0 November 17, 2025 KU 24-07RD2 Drilling Procedure PTD# XXX-XXX 1 Dewhurst, Andrew D (OGC) From:Zachary Browning - (C) <zachary.browning@hilcorp.com> Sent:Thursday, 18 December, 2025 14:46 To:Dewhurst, Andrew D (OGC) Cc:McLellan, Bryan J (OGC); Davies, Stephen F (OGC); Stefan Reed Subject:RE: [EXTERNAL] KU 24-07RD2 PTD (225-126): Question Attachments:501332056400_KBU24-7X_CBL.pdf; KU 24-07RD2 AOR Rev2.xlsx Andy, You are correct, the disposal zone is behind the 9-5/8 casing in KBU 24-7X, apologies for the error. I have updated the AOR table with changes in blue (Rev2) and attached. On KBU 24-7X the 9-5/8 cement job did not go to plan and a remedial cement job was performed, after which a CBL log was obtained (attached). The log shows the TOC from the primary cement job at ~5380 MD and then cement above the squeeze perforations starting at 4870 MD. High quality cement is seen from 4850-4090 with additional cement up to 3500 where TOC is called because data becomes unreliable above that point (see log notes). Please let me know any other questions. Thanks, Zach From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, December 18, 2025 11:56 AM To: Zachary Browning - (C) <zachary.browning@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: [EXTERNAL] KU 24-07RD2 PTD (225-126): Question Zachary, Im closing out the review of KU 24-07RD2 while Steve is away from the o ice today and have a question. For the KBU 24-07X o set well, the AOR provides the TOC for the 3-1/2 production hole section, but the disposal zone is isolated by the 9-5/8 intermediate section. Would you please con rm this and then provided a revised version of the AOR table with the TOC and basis for the intermediate casing cement for KCU 24-07X? Thanks, You don't often get email from zachary.browning@hilcorp.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 McLellan, Bryan J (OGC) From:Zachary Browning - (C) <zachary.browning@hilcorp.com> Sent:Tuesday, December 2, 2025 1:37 PM To:McLellan, Bryan J (OGC) Cc:Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC); Starns, Ted C (OGC); Cody Dinger; Stefan Reed Subject:RE: [EXTERNAL] KU 24-07RD2 Area of review Attachments:KBU 31-18 Intermediate Plot Report Configuration.pdf Bryan, After a little more digging I also found the SLB cement report for the job on KBU 31-18 (attached). The report shows decent lift pressure increasing through the end of the job until bump. SLB o icially recorded 800psi lift pressure (1056psi FCP). Using 800psi lift pressure suggests a TOC between ~3000-3400ft MD depending on your assumptions (using 10ppg spacer/13.5ppg litecrete/15.3ppg tail/9.3ppg displacement mud). Thanks, Zach From: Zachary Browning - (C) <zachary.browning@hilcorp.com> Sent: Tuesday, December 2, 2025 10:10 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Cody Dinger <cdinger@hilcorp.com>; Stefan Reed <Stefan.Reed@hilcorp.com> Subject: RE: [EXTERNAL] KU 24-07RD2 Area of review Bryan, Ive attached an updated AOR with the correct hole section TOC listed for KBU 31-18. Also attached is the wellhead pressure plot showing the KBU 31-18 Tubing/IA/OA pressures. Note: The recent tubing pressure spike on the graph is from a well shut-in. Regarding the estimated TOC, the report just says that it was based on Volume Calc vs Hole Depth. I tried to back-calculate and got the same result as you did using a 25% OH excess. There were indications from the report that the hole was in gauge (2 notes of sweeps coming back on time approaching and at TD, see snip below). However, using gauge hole still does not give a 3354 TOC. The explanations I can come up with are 1) There was a known loss zone, which combined with the loss rate gave them the estimated TOC. 2). They used a more accurate lost circulation volume for once cement turned the corner vs the overall 45% lost returns or 3) The original estimated TOC was incorrect. However, there does not appear to be pressure communication up the OA as shown on the wellhead pressure graph from the last two years. 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 Thanks, Zach From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, December 1, 2025 10:40 AM To: Zachary Browning - (C) <zachary.browning@hilcorp.com>; Stefan Reed <stefan.reed@hilcorp.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov> Subject: [EXTERNAL] KU 24-07RD2 Area of review Zach, The TOC listed in the Area of review of 6340 MD in well KBU 31-18 is below the injection interval in KU 24- 07RD2. I see that youve reported the production casing TOC, but should be looking at intermediate 7- 5/8 casing TOC. I looked at that 7-5/8 cement job in KBU 31-18 (PTD 215-024) and see that there were 45% losses during the job. Assuming the 25% OH excess volume (same assumption as used in the PTD for the well), that puts TOC at ~4836 MD by my calculation, however the cement report lists an estimated TOC of 3354. How was that top of cement estimated? Stefan, Does KBU 31-18 have any signs of sustained casing pressure on the 7-5/8 x 10-3/4 annulus? Can you send a wellhead pressure plot over the past 2 years? Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 3 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. Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. KU 24-07RD2 Undefined Waste Disposal 225-126 Kenai Gas WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:KENAI UNIT 24-07RD2Initial Class/TypeSER / 2-GASGeoArea820Unit51120On/Off ShoreOnProgram SERWell bore segAnnular DisposalPTD#:2251260Field & Pool:KENAI, UNDEFINED WDSP - 448036NA1 Permit fee attachedYes Entire Well lies within ADL0390821.2 Lease number appropriateYes3 Unique well name and numberNo KENAI, UNDEFINED WDSP - 448036 - governed by Statewide Regs4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes DIO 1114 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes AOR finalized by Andy on 18DEC15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes Re-drill18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 1414 psi, BOP rated to 5000 psi (BOP test to 2500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableYes Class 1 disposal well. Some question about TOC in well KBU 31-18, addressed in CoA.34 Mechanical condition of wells within AOR verified (For service well only)NA35 Permit can be issued w/o hydrogen sulfide measuresYes36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate18-Dec-25ApprBJMDate02-Dec-25ApprSFDDate12-Dec-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 12/19/2025