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Home My WebLink About225-131From:Rixse, Melvin G (OGC) To:Brad Gorham Cc:Keith Lopez; Cody Dinger; McLellan, Bryan J (OGC); Dewhurst, Andrew D (OGC); Wallace, Chris D (OGC) Subject:RE: [EXTERNAL] 20260121 1438 APPROVAL Production Packer Set Depth NIK O-233 (PTD# 225-131) Completion Change Date:Thursday, January 22, 2026 9:35:35 AM Brad, Hilcorp is approved to run upper completion as described below. 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). From: Brad Gorham <brad.gorham@hilcorp.com> Sent: Thursday, January 22, 2026 9:16 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Keith Lopez <Keith.Lopez@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: RE: [EXTERNAL] 20260121 1438 APPROVAL Production Packer Set Depth NIK O-233 (PTD# 225-131) Completion Change Mel, Yesterday we ran our production liner but unfortunately were unable to get it on our planned set depth. We were able to run our liner shoe to 34’ from our planned set depth. That being the case, our injection packer will now be 34’ higher, resulting in it being ~285’ MD of our surface casing shoe. This still places the packer well below the confining layer as previously outlined. Let me know if you have any questions or concerns. Thanks, CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Brad From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, January 21, 2026 2:39 PM To: Brad Gorham <brad.gorham@hilcorp.com> Cc: Keith Lopez <Keith.Lopez@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: [EXTERNAL] 20260121 1438 APPROVAL Production Packer Set Depth NIK O-233 (PTD# 225- 131) Completion Change Brad, Hilcorp approved to set packer at approximately 251’ above the surface casing shoe. 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). From: Brad Gorham <brad.gorham@hilcorp.com> Sent: Wednesday, January 21, 2026 10:33 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Keith Lopez <Keith.Lopez@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: RE: [EXTERNAL] RE: NIK O-233 (PTD# 225-131) Completion Change Mel, Has there been any further review on this from the geologist or UIC engineer? If our liner gets to the planned set depth, our injection packer will be ~251’ MD above our surface casing shoe. This would place our packer at ~5,484’ MD with our surface casing shoe being at 5,735’ MD. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. The base of the confining zone of the Schrader Bluff Pool is at 4,977’ MD. Please let us know if you need any additional information prior to us submitting for approval. Thanks, Brad From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, January 14, 2026 2:28 PM To: Brad Gorham <brad.gorham@hilcorp.com> Cc: Keith Lopez <Keith.Lopez@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: [EXTERNAL] RE: NIK O-233 (PTD# 225-131) Completion Change Brad, I will forward to AOGCC geologist and UIC engineer for their review to assure the injection packer is set well below the base of the SB Oil Pool confining zone. You may be getting a request for additional information. 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). From: Brad Gorham <brad.gorham@hilcorp.com> Sent: Wednesday, January 14, 2026 12:27 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Keith Lopez <Keith.Lopez@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: NIK O-233 (PTD# 225-131) Completion Change 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. Mel, We wanted to give you notice regarding the O‑233 upper completion. Our standard N‑sand injector design uses 3‑1/2” 13Cr tubing with a chrome bullet seal assembly stung into the SLZXP liner hanger/packer. For O‑233, we were unable to manufacture and deliver the chrome seal assembly within the required timeline. To mitigate galvanic corrosion concerns, we plan to run a chrome injection packer above the liner hanger for this well. With an estimated 150 ft liner lap (standard practice) and approximately 65 ft of tools below the packer, the packer may be set more than 200 ft MD above the 9‑5/8” surface casing shoe. This would place the installation out of compliance with 20 AAC 25.412, requiring commission approval. Once the liner is run and actual depths are confirmed, we can submit a formal request for approval. A schematic of the proposed upper completion modification is attached. Let us know if you have any questions or concerns. Thanks, Brad Gorham Drilling Engineer Hilcorp Alaska, LLC Office: 907-263-3917 Cell: 907-250-3209 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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, 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 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. 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 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 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. From:Rixse, Melvin G (OGC) To:Brad Gorham Cc:Keith Lopez; Cody Dinger Subject:20260121 1438 APPROVAL Production Packer Set Depth NIK O-233 (PTD# 225-131) Completion Change Date:Wednesday, January 21, 2026 2:39:04 PM Brad, Hilcorp approved to set packer at approximately 251’ above the surface casing shoe. 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). From: Brad Gorham <brad.gorham@hilcorp.com> Sent: Wednesday, January 21, 2026 10:33 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Keith Lopez <Keith.Lopez@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: RE: [EXTERNAL] RE: NIK O-233 (PTD# 225-131) Completion Change Mel, Has there been any further review on this from the geologist or UIC engineer? If our liner gets to the planned set depth, our injection packer will be ~251’ MD above our surface casing shoe. This would place our packer at ~5,484’ MD with our surface casing shoe being at 5,735’ MD. The base of the confining zone of the Schrader Bluff Pool is at 4,977’ MD. Please let us know if you need any additional information prior to us submitting for approval. Thanks, Brad 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. From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, January 14, 2026 2:28 PM To: Brad Gorham <brad.gorham@hilcorp.com> Cc: Keith Lopez <Keith.Lopez@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: [EXTERNAL] RE: NIK O-233 (PTD# 225-131) Completion Change Brad, I will forward to AOGCC geologist and UIC engineer for their review to assure the injection packer is set well below the base of the SB Oil Pool confining zone. You may be getting a request for additional information. 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). From: Brad Gorham <brad.gorham@hilcorp.com> Sent: Wednesday, January 14, 2026 12:27 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Keith Lopez <Keith.Lopez@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: NIK O-233 (PTD# 225-131) Completion Change Mel, We wanted to give you notice regarding the O‑233 upper completion. Our standard ‑‑ N sand injector design uses 3 1/2” 13Cr tubing with a chrome bullet seal assembly stung into the SLZXP liner hanger/packer. For O‑233, we were unable to manufacture and deliver the chrome seal assembly within the required timeline. To mitigate galvanic corrosion concerns, we plan to run a chrome injection packer above the liner hanger for this well. With an estimated 150 ft liner lap (standard practice) and approximately 65 ft of tools below the packer, the packer may be set more than 200 ft MD above the 9‑5/8” surface casing shoe. This would place the installation out of compliance with 20 AAC 25.412, requiring commission approval. Once the liner is run and actual depths are confirmed, we can submit a formal request for approval. A schematic of the proposed upper completion modification is attached. Let us know if you have any questions or concerns. Thanks, Brad Gorham Drilling Engineer Hilcorp Alaska, LLC Office: 907-263-3917 Cell: 907-250-3209 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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:20260120 0920 APPROVAL Connections NIK O-233 (PTD# 225-131) Production Liner Change Date:Tuesday, January 20, 2026 9:23:23 AM Brad, Noted and approved. 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). From: Brad Gorham <brad.gorham@hilcorp.com> Sent: Friday, January 16, 2026 6:59 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Cody Dinger <cdinger@hilcorp.com> Subject: NIK O-233 (PTD# 225-131) Production Liner Change Mel, On the NIK O-233 production liner, the 4-1/2” will be 12.6# C-110 HYD521 as opposed to the 12.6# L-80 HYD625 that was outlined in the approved PTD. The 5-1/2” tubular is unchanged. Let me know if you have any questions or concerns. Thanks, Brad Gorham Drilling Engineer Hilcorp Alaska, LLC Office: 907-263-3917 Cell: 907-250-3209 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. 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:20260112 0957 NIK O-233 (PTD# 225-131) Surface Casing CBL Date:Monday, January 12, 2026 10:00:02 AM From: Rixse, Melvin G (OGC) Sent: Monday, January 12, 2026 9:18 AM To: 'Brad Gorham' <brad.gorham@hilcorp.com> Cc: Cody Dinger <cdinger@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: NIK O-233 (PTD# 225-131) Surface Casing CBL Brad, CBL and SLB interpretation received at AOGCC. Thank you. Hilcorp is approved to run production screens. 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. Dinger, Dewhurst, Davies, Wallace From: Brad Gorham <brad.gorham@hilcorp.com> Sent: Friday, January 9, 2026 4:43 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Cody Dinger <cdinger@hilcorp.com> Subject: NIK O-233 (PTD# 225-131) Surface Casing CBL Mel, As previously discussed, see attached for the log and SLB’s interpretation for O-233 surface casing log. It is important to note that the “transition zone” and “free pipe” intervals were fully cemented. However, the log was run prior to either slurry reaching optimal compressive strength for logging. This is due to the colder temperatures and slurry design on the second stage lead. Regardless the log shows that zonal isolation requirements have been met. We are currently drilling ahead in our production hole. Let us know if we have approval to run our production liner as outlined in the COA’s. Thanks, Brad Gorham Drilling Engineer Hilcorp Alaska, LLC Office: 907-263-3917 Cell: 907-250-3209 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 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 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. 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:Cody Dinger To:Rixse, Melvin G (OGC); Dewhurst, Andrew D (OGC); Guhl, Meredith D (OGC) Cc:Brad Gorham; Sean McLaughlin Subject:NIK O-233 As Built Date:Friday, January 2, 2026 8:18:44 AM Attachments:O-233 Slot 37 As-Built-AS-BUILT OP 37_Signed.pdf Hello All, Attached is the as built surface plat for NIK O-233 (slot 37) for your records, no change to the permitted SHL. Cody Dinger Hilcorp Alaska, LLC Drilling Tech 907-777-8389 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. Hilcorp Alaska Dec. 31, 2025 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Nikaitchuq Field, Schrader Bluff Oil Pool, NIK O-233 Hilcorp Alaska, LLC Permit to Drill Number: 225-131 Surface Location: 3058' FSL, 1832' FEL, Sec 5, T13N, R9E, UM, AK Bottomhole Location: 1312' FNL, 1206' FWL, Sec 20, T14N, R9E, UM, 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 18th 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: 19,585' TVD: 3,903' 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): 46.8' 15. Distance to Nearest Well Open Surface: x-516444 y- 6036410 Zone-4 13.1' to Same Pool: 33' to OP-19 16. Deviated wells: Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 91 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20" 129.5# X-52 Weld 80' Surface Surface 80' 80' 9-5/8" 47# L-80 TXP BTC 2,500' Surface Surface 2,500' 2,041' 9-5/8" 40# L-80 Wdg 521 2,935' 2,500' 2,041 5,435' 3,469' 5-1/2" 17# L-80 JFE BEAR 5,000' 5,235' 3,427' 10,235' 3,604' 4-1/2" 12.6# L-80 Wdg 625 9,350' 10,235' 3,604' 19,585 3,903' Tbg 3-1/2" 9.2# CR 13-80 JFE BEAR 5,235' Surface Surface 5,235' 3,427' 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 4974 Cement Volume MD Brad Gorham brad.gorham@hilcorp.com Effect. Depth MD (ft): 907-263-3917 Slotted Injection Liner Tubing Effect. Depth TVD (ft): Drilling Manager Sean Mclaughlin 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate LengthCasing Size Specifications 1725 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) 16 yds concrete Total Depth TVD (ft): 1335 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 18. Casing Program: Top - Setting Depth - Bottom O-233 Nikaitchuq Unit Schrader Bluff Oil Pool (N Sands) Cement Quantity, c.f. or sacks 12/22/2025 559' to nearest unit boundary 559' FSL, 1077' FWL, Sec 32, T14N, R9E, UM, AK 1312' FNL, 1206' FWL, Sec 20, T14N, R9E, UM, AK LONS 05-007 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 3058' FSL, 1832' FEL, Sec 5, T13N, R9E, UM, AK ADL355024, ADL 390616, ADL 388583 12-1/4" 8-1/2"Slotted Injection Liner Stg 1 L - 787 ft3 / T - 458 ft3 Stg 2 L - 1615 ft3 / T - 313 ft3 Commission Use Only See cover letter for other requirements. Total Depth MD (ft): s N ype of W L l R L 1b S Class: os N s No s N o Dr s s sDr 84 o : well is p G S S 2 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: 2025.12.04 14:50:41 - 09'00' Sean McLaughlin (4311) 225-131 By Grace Christianson at 3:27 pm, Dec 04, 2025 50-029-23831-00-00 * See following 2 pages for conditions of approval. A.Dewhurst 11DEC25MGR16DEC2025 DSR-12/8/25 CDW 12/10/2025 Nikaitchuq JLC 12/17/2025 12/18/25 12/18/25 Conditions f Approval PTD 225-131 Nikaitchuq O-233 1. AOGCC inspection of diverter layout and diverter function test. 24-hour notice to AOGCC. Not approved for 45° bends in diverter line. 2. AOGCC to witness BOPE test to 3000 psi. Annular to 2500 psi. 24-hour notice to AOGCC. 3. CBL from 9-5/8 surface/production casing shoe to minimum of 250 TVD feet above top of the Schrader Blu oil pool to identify cement isolation to overburden. CBL and vendor evaluation report to AOGCC for review before running production liner. 4. Changes to casing described on form 10-401, including: weight, diameters, drifts or connections to be communicated and approved by AOGCC. 5. All planned casings strings to be utilized in well construction to include engineering modeling for worst case tension, worst case collapse, worst case burst. 6. A 10-407 initial well completion report to be returned to AOGCC 30 days from rig release. 7. MIT-IA to 1500 psi per 20 AAC 25.412 (c) which states: Before injection begins, a well must be pressure-tested to demonstrate the mechanical integrity of the tubing and packer and of the casing immediately surrounding the injection tubing string. The casing must be tested at a surface pressure of 1,500 psig or at a surface pressure of 0.25 psi/ft multiplied by the true vertical depth of the casing shoe, whichever is greater, but the casing may not be subjected to a hoop stress that will exceed 70 percent of the minimum yield strength of the casing. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes 8. MIT-IA to 1500 psi within 10 days of stabilized injection. 24-hour notice to AOGCC for opportunity to witness. 9. Noted in section 15 of PTD: Hilcorp provided no variance requests. Surface/production casing to be tested per 20 AAC 25.030 (e): A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1). 10. Stage collar to be no shallower than ~100 TVD feet below the base of the permafrost. 11. 9-5/8 47# L-80 casing from minimum of base of permafrost to surface. 12. 9-5/8 surface/production casing to be drifted to casing speci cations drift ID. 13. Tuned spacers for cement to be of su icient density to always assure well bore pressure to remain above pore pressure. 14. Safety joint with FOSV to be on the rig oor with crossover to casing and slotted liner while performing casing running operations. 15. Email casing test and FIT digital data to AOGCC. If questionable uid volume returned from formation upon bleed back, do not proceed until noti cation AOGCC for intervention plans. 16. Not approved for pre-production. 17. Shoe track length is de ned as: length of casing from casing shoe to landing collar that will be left lled with cement after primary surface/production casing cementing operations. For shoe track length calculations identi ed in this permit: ~120, or 3 full joints of casing. PTD API WELLSTATUSTop of SBNb (MD)Top of SBNb (TVD)Top ofCement(MD)Top ofCement(TVD)Schrader Nb statusZonal Isolation206-144 50-029-23326-00-00OPI-02SB OA Horiz Injector - Active 5883 3433 4220 2760 N/A9-7/8" hole with 7-5/8" casing: Pumped 90bbls 15.8ppg class G cement.USIT run 10/22/11 for conversion to injector noted ToC at 4220' MD.213-068 50-029-23491-00-00OP19-T1NSB N Sand Producer - Shut In /Working reservoir P&A sundry6456 3479 4010 3196 will be P&A'd12-1/4" hole with 9-5/8" casing: Pumped 115bbls 12.5ppg cement. No lossesduring job. Assuming 10% washout, Volumetric TOC = 4010' MD.210-069 50-029-23426-00-00OP12-01SB OA Horiz Producer- Active 4662 3445 3770 2989 N/A12-1/4" hole with 9-5/8" casing: Pumped 110bbls 12.5ppg Deepcrete.Volumetric ToC assuming 10% washout = 3770' MD210-106 50-029-23430-00-00OI11-01SB OA Horiz Injector - Active 5404 3467 3725 2860 N/A12-1/4" hole with 9-5/8" casing: Pumped 211 bbls 12.5 ppg LiteCrete. ToC at3,725' MD from USIT Log 10/14/10210-041 50-029-23424-00-00OP08-04SB OA Horiz Producer- Active 4189 3458 3320 2970 N/A12-1/4" hole with 9-5/8" casing: Pumped 103bbls 12.5ppg Litecrete.Volumetric ToC assuming 10% washout = 3320' MD. 6/12/13 USIT confirmscement present from 3980' - 4730' MD (didn't log higher)211-141 50-029-23460-00-00OI15-S04SB OA Horiz Injector - Active (res P&Ain progress, likely to be suspended in2026)9282 3565 7000 3230 N/A12-1/4" hole with 9-5/8" casing: Pumped 196bbls of 12.5 ppg LiteCrete.2/23/2012 log shows TOC at 7,000' MD211-052 50-029-23447-00-00OP14-S03SB OA Horiz Producer- Active 7918 3596 4900 3170 N/A12-1/4" hole with 9-5/8" casing: Pumped 338bbls 12.5ppg Deepcrete.9/26/13 USIT confirms ToC at 4900' MD212-006 50-629-23464-00-00SI29-S2SB OA Horiz Injector - Active 8148 3544 6650 3021 N/A12-1/4" hole with 9-5/8" casing: Pumped 155 bbls of 12.5 ppg LiteCrete.2/29/2012 log shows TOC at 6,650' MD211-058 50-029-23448-00-00OP09-S01SB OA Horiz Producer- Active 11588 3752 10618 3623 N/A12-1/4" hole with 9-5/8" casing: Pumped 356 bbls of 12.5 ppg LiteCrete.Calculated TOC at 10,618' MD214-011 50-629-23510-00-00SP24-SE1SB OA Horiz Producer- Active 4756 3777 3760 3204 N/A12-1/4" hole with 9-5/8" casing: Pumped 85 bbls of 12.5 ppg DeepCrete and50 bbls of 15.8 ppg Class G. 3/10/2014 Log shows TOC at 3,760' MD214-041 50-629-23512-00-00SI17-SE2SB OA Horiz Injector - Active 4495 3821 3497 3156 N/A12-1/4" hole with 9-5/8" casing: Pumped 128 bbls of 12.5 ppg LiteCrete.5/24/2014 Log shows TOC at 3,497' MDArea of Review Nikaitchuq O-233 SBF-Nb 214-067 50-629-23513-00-00SP12-SE3SB OA Horiz Producer- Active 4711 3844 3746 3256 N/A12-1/4" hole with 9-5/8" casing: Pumped 80 bbls of 12.5 ppg DeepCrete and50 bbls of 15.8 ppg Class G. 6/20/2014 Log shows TOC at 3,746' MD214-100 50-629-23519-00-00SI07-SE4SB OA Horiz Injector - Active 5721 3914 4202 3133 N/A12-1/4" hole with 9-5/8" casing: Pumped 135 bbls of 12.5 ppg LiteCrete.5/31/2015 Log shows TOC at 4,202' MDSee attached emails with ammended AOR table for KRU 3R-101/L1 evaluation. -A.Dewhurst 11DEC25 Western North Slope (OPP) O-233 Version 2 12/3/2025 Oliktok Point O-233 SB NB Injector Table of Contents 1. Well Name......................................................................................................................................3 2. Location Summary..........................................................................................................................3 3. Blowout Prevention Equipment Information.................................................................................4 4. Drilling Hazards Information...........................................................................................................5 5. Procedure for Conducting Formation Integrity Tests.....................................................................6 6. Casing and Cementing Program.....................................................................................................6 7. Diverter System Information..........................................................................................................7 8. Drilling Fluid Program.....................................................................................................................7 9. Abnormally Pressured Formation Information ..............................................................................8 10. Seismic Analysis............................................................................................................................8 11. Seabed Condition Analysis............................................................................................................8 12. Evidence of Bonding........................................................................................................ .............8 13. Proposed Drilling Program ...........................................................................................................9 14. Discussion of Mud and Cuttings Disposal and Annular Disposal................................................11 15. Proposed Variance Request........................................................................................................11 Attachment 1: Location & GIS Maps................................................................................................12 Attachment 2: BOPE Equipment ......................................................................................................14 Attachment 3: Hole Section Hazards................................................................................................19 Attachment 4: LOT / FIT Test Procedure..........................................................................................22 Attachment 5: Cement Summary.....................................................................................................23 Attachment 6: Prognosed Formation Tops......................................................................................24 Attachment 7: Wellbore Schematic .................................................................................................25 Attachment 8: Formation Evaluation Program................................................................................26 Attachment 9: Wellhead Diagram....................................................................................................27 Attachment 10: Management of Change.........................................................................................28 Attachment 11: Drill Pipe Specs.......................................................................................................29 Attachment 12: Kick Tolerance Calculations....................................................................................30 Attachment 13: Directional Plan......................................................................................................31 Addendum 1: Miscellaneous Questions.........................................................................................312 Oliktok Point O-233 SB NB Injector As per 20 AAC 25.005 (c), an application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application. 1. Well Name 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this application for a Permit to Drill is submitted is designated as O-233. This will be a development injection well. 2. Location Summary 20 AAC 25.005 (c) (2) A plat identifying the property and the property's owners and showing: (A) the coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at total depth, referenced to governmental section lines; (B) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth Location at Surface Reference to Government Section Lines 3058' FSL, 1832' FEL, Sec 5, T13N, R9E, UM, AK NAD 27 Coordinate System X: 516444 Y: 6036410 Doyon 14 Rig KB Elevation 33.7 above GL Ground Level 13.1 above MSL Location at Top of Productive Interval Reference to Government Section Lines 559' FSL, 1077' FWL, Sec 32, T14N, R9E, UM, AK NAD 27 Coordinate System X: 514062 Y: 6039185 Measured Depth, Rig KB (MD)5,600 Total Vertical Depth, Rig KB (TVD)3490 Total vertical Depth, Subsea (TVDSS)3,43 Location at Bottom of Productive Interval Reference to Government Section Lines 1312' FNL, 1206' FWL, Sec 20, T14N, R9E, UM, AK NAD 27 Coordinate System X: 514118 Y: 6053152 Measured Depth, Rig KB (MD)19,585 Total Vertical Depth, Rig KB (TVD)3,903 Total Vertical Depth, Subsea (TVDSS)3,856 Oliktok Point O-233 SB NB Injector (D) other information required by 20 AAC 25.050(b); 20 AAC 25.050 (b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form 10-401) must: (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed well; and Please refer to Attachment 1: Location Maps, Attachment 6: Formation Tops and Attachment 13: Directional Plan for further details. (2) for all wells within 200 feet of the proposed wellbore: (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) state that the applicant is the only affected owner. The applicant is the only affected owner. 3. Blowout Prevention Equipment Information 20 AAC 25.005 (c) (3) A diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable; BOP test frequency for O-233 will be 14-days. Except in the event of a significant operational issue that may affect well integrity or pose safety concerns, an extension to the 14-day BOP test period should not be requested. Summary of Doyon 14 BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2 13-5/8 x 5M Shaffer Annular BOP 13-5/8 x 5M Hydril Double Gate Blind ram in bottom cavity Mud cross w/ 3 x 5M side outlets 13-5/8 x 5M Hydril Single ram 3-1/8 x 5M Choke Line 3-1/8 x 5M Kill line 3-1/8 x 5M Choke manifold Standpipe, floor valves, etc. Initial Test: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) Primary closing unit: NL Shaffer 6 station, 3,000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are in the doghouse and on accumulator unit. Oliktok Point O-233 SB NB Injector Please refer to Attachment 2: BOPE Equipment for further details. 4. Drilling Hazards Information 20 AAC 25.005 (c) (4) Information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a pressure gradient to surface of 0.1 psi per foot of true vertical depth, unless the commission approves a different pressure gradient that provides a more accurate means of determining the maximum potential surface pressure; 8.5 Production Hole Pressure Data Maximum anticipated BHP 1,533 psi in the Schrader NB Sand at 3,468 TVD Maximum surface pressure 1,335 psi from the Schrader NB Sand (0.10 psi/ft gas gradient to surface) Planned BOP test pressure Rams test to 3,000 psi / 250 psi Annular test to 2,500 psi / 250 psi Formation Integrity Test 8.5 hole 12.0 ppg EMW FIT after drilling 20 of new hole outside of 9- 5/8 10.2 ppg FIT provides greater than 25 bbl based on 9.5 ppg MW, 8.5 ppg pore pressure 10.2 ppg minimum to drill ahead, 12.0 EMW for drilling ECDs 9.625 Casing Test 2,500 psi, chart for 30 min (Test pressure driven by 50% of Casing Burst) (B) data on potential gas zones; and (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please refer to Attachment 3: Hole Section Hazards Oliktok Point O-233 SB NB Injector 5. Procedure for Conducting Formation Integrity Tests 20 AAC 25.005 (c) (5) A description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f); Please refer to Attachment 4: LOT / FIT Test Procedure 6. Casing and Cementing Program 20 AAC 25.005 (c) (6) A complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre-perforated liner, or screen to be installed; Casing/Tubing Program Hole Size Tubular O.D. Tubular ID (in)Wt/Ft Grade Conn Length Top MD Bottom MD 12.25 9.625 8.52547 L-80 TXP 2,500Surface 2,500 9.625 8.83540 L-80 W521 2,9352,500 5,435 8.5 5.5 Slotted 4.892 17.0 L-80 JFE Bear 5,0005,235 10,235 4.5 Slotted 3.920 13.5 L-80 W625 9,35010,235 19,585 Tubing 3.52.9929.2 13Cr80 JFE Bear 5,235Surface 5,235 Please refer to Attachment 5: Cement Summary for further details. Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20 19.25- - - X-52 12-1/49-5/8 8.681 8.525 10.62547 L-80 6,870 4,750 1,086 9-5/88.8358.67910.62540 L-80 5,750 3,090 916 8-1/25-1/2 4.892 4.767 6.05017 L-80 7,740 6,290 397 4-1/2 3.960 3.795 4.71413.5 L-80 9020 8540 279 Tubing 3-1/2 2.992 2.867 4.5009.3 L-80 9289 7399 163 Oliktok Point O-233 SB NB Injector 7. Diverter System Information 20 AAC 25.005 (c) (7) A diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Hole Section Equipment Test Pressure (psi) 12.2521.25 2M Hydril w/ 16 knife gate & diverter line Function Test Only Please refer to Attachment 2: BOPE Equipment for further details. 8. Drilling Fluid Program 20 AAC 25.005 (c) (8) A drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling Fluid Program Summary Surface Hole Production Hole Mud Type Spud Mud / LSND 3% KCl / Polymer Mud Properties: Mud Weight PV YP Fluid Loss pH MBT Temp 8.8 9.8 20 40 25 - 45 < 10 8.5 9.0 Visc: 75 175 < 70* 9.0 10.0 ppg 15-25 15-30 < 10 HPHT 8.5-9.0 <8 A diagram of drilling fluid system on Doyon 14 is on file with AOGCC. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033 Oliktok Point O-233 SB NB Injector 9. Abnormally Pressured Formation Information 20 AAC 25.005 (c) (9) For an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); N/A Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis 20 AAC 25.005 (c) (10) For an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a); N/A Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis 20 AAC 25.005 (c) (11) For a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b); O-233 is to be drilled from an onshore location. 12. Evidence of Bonding 20 AAC 25.005 (c) (12) Evidence showing that the requirements of 20 AAC 25.025 have been met; Evidence of bonding for Hilcorp North Slope, LLC is on file with the Commission. Oliktok Point O-233 SB NB Injector 13. Proposed Drilling Program 20 AAC 25.005 (c) (13) A copy of the proposed drilling program; the drilling program must indicate if a well is proposed for hydraulic fracturing as defined in 20 AAC 25.283(m); to seek approval to perform hydraulic fracturing, a person must make a separate request by submitting an Application for Sundry Approvals (Form 10-403) with the information required under 20 AAC 25.280 and 20 AAC 25.283; The proposed drilling program to O-233 is listed below. Please refer to Attachments for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed Drilling Program O-233 1. MIRU Doyon 14 2. Install riser connection & test void to 1,000 psi for 15 minutes 3. NU Diverter & function test 4. MU 12-1/4 Motor BHA and Drill Surface Hole to section TD, into Schrader Bluff NB Sand 5. CBU, BROOH 6. LD BHA 7. RU and RIH with 9-5/8 Surface Casing to TD, land hanger into landing ring 8. Perform 2-stage 9-5/8 Casing cement job per program while picked up off landing ring & oscillating 9. LD Landing joint, jet stack & install packoff per Vault spec, test to 3,800 psi for 15 minutes 10. ND Diverter, install wellhead and drilling adapter 11. NU BOPE & Test 12. Pull test plug & install wear bushing 13. MU 8-1/2 cleanout assembly, TIH to top of 9-5/8 shoe track 14. PT 9-5/8 casing to 2500 psi, chart test 15. Drill out 9-5/8 shoe track & 20 of new hole, circulate & condition mud 16. Pull back into 9-5/8 shoe, perform FIT t/ 12.0 ppg EMW 17. POOH, LD cleanout BHA 18. MU 8-1/2 RSS BHA, RIH to bottom a. Install MPD RCD to be used to monitor wellbore conditions during connections 19. Drill 8-1/2 intermediate hole to section TD, in the SB NB 20. Perform clean up cycles w/SAPP sweeps, displace w/viscosifed brine, and BROOH 21. LD BHA, RU Casing equipment 22. Run 5.5x4.5 slotted liner on 5 DP to TD 23. Set liner packer/hanger & perform release sequence 24. Test liner top to 1,500 psi for 10 minutes 25. POOH & LD running tool 26. Pull wear bushing 27. Run 3.5 upper completion as per tally 28. Reverse circulate corrosion inhibited brine & freeze protect See COA for shallow limit on stage collar. - mgr 50% of burst per regulation. - mgr See COA #14 for safety joint requirements. - mgr see COA for safety joint. - mgr 24 hour notice to AOGCC to witness diverter layout and function test. - mgr All fluids to be statically overbalanced to pore pressure. mgr See conditions of approval. - mgr 24 hour notice to AOGCC for opportunity to witness and review MPD system. - mgr Oliktok Point O-233 SB NB Injector 29. Land hanger. Land hanger. RILDs and test hanger. 30. MIT-IA to 1500 psi and test for 30 charted minutes. a. Note this test must be witnessed by an AOGCC representative. AOGCC will be notified prior to conducting the test 31. Install BPV, ND BOPE. NU adapter flange. 32. Install TH adapter & test connection to 5,000 psi 33. Install TH, pull BPV & set TWC 34. Test tree to 5,000 psi 35. Pull TWC & set BPV, bullhead freeze protect 36. Secure tree, cellar, wellhouse 37. RDMO Post Rig Work 1. Tie into facility Note: This well will not be fracture stimulated * See conditions of approval for requirements for POI. - mgr Oliktok Point O-233 SB NB Injector 14. Discussion of Mud and Cuttings Disposal and Annular Disposal 20 AAC 25.005 (c) (14) A general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well. All cuttings and mud generated during drilling operations will be disposed of onsite at Oliktok Point. There is no intention to request authorization under 20 AAC 25.080 for any annular disposal operation in the well. 15. Proposed Variance Request There are no variance requests for O-233. * Operations to comply with regulation as no variance requests for O-233: 1. Casing test to 50% of burst of weakest casing. A variance is required to 20 AAC 25.030 for casing pressure tests when BOPE is installed. Minimum required test pressure is 50% of casing internal yield, stable with no more than 10% decline within 30 minutes. Test results must be documented in accordance with 20 AAC 25.070(1). 2. Cement bond log required on 9-5/8" surface casing/production casing for water injector. Oliktok Point O-233 SB NB Injector Attachment 1: Location & GIS Maps Oliktok Point O-233 SB NB Injector Oliktok Point O-233 SB NB Injector Attachment 2: BOPE Equipment Doyon 14 Diverter Schematic: Oliktok Point O-233 SB NB Injector 0-233 Diverter Line Layout: Oliktok Point O-233 SB NB Injector Doyon 14 BOPE Schematic: 2-7/8 x 5 VBR 4-1/2 x 7 VBR Blind Rams Oliktok Point O-233 SB NB Injector Per 20 AAC 25.035(e)1.A For an operation with a maximum potential surface pressure of 3,000 psi or less, BOPE must have at least three preventers, including (i) one equipped with pipe rams that fit the size of drill pipe, tubing, or casing being used, except that pipe rams need not be sized to bottom-hole assemblies (BHAs) and drill collars; (ii) (ii) one with blind rams, except that a subsea BOPE assembly must have blind/shear rams in place of blind rams; and (iii) (iii) one annular type BOPE Configuration for each operation: Drill Production / Run 5.5x4.5 Liner & Completion: 13-5/8 Annular UPR: 4-1/2 x 7 VBR Blind Rams LPR: 2-7/8 x 5 VBR Oliktok PointO-233 SB NB InjectorDoyon 14 Choke Manifold Schematic Oliktok Point O-233 SB NB Injector Attachment 3: Hole Section Hazards 12.25 Hole Section Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates/Free Gas Gas hydrates have been seen on Oliktok Point. Be prepared for them. They have been reported near the base of the permafrost. MW has been chosen based upon successful trouble-free penetrations of offset wells. Be prepared for gas hydrates. Keep mud temperature as cool as possible, Target 60-70°F, use lake water Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as cold premade mud on trucks ready Drill through hydrate sands and quickly as possible, do not backream. Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Cretaceous Over Pressure: Oliktok Point does not have a history of over-pressure to the SB NB sand. However, as a precaution to ensure MW is above 9.0. Be prepared while drilling this interval. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill ability to clean the hole. Anti-Collison: Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Oliktok Point O-233 SB NB Injector Wellbore stability (Permafrost, running sands and gravel) Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Maintain mud parameters and increase MW to combat running sands and gravel formations. Stuck pipe, wood chunks over shakers and other hole stability issues. 8.5 Hole Section Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps and test effect of weighted high vis sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time or slower ROP is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. Planned Crossings: Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Casing Running Casing running issues have been noted on OPP, gravels, stability wood chunks, etc. Watch casing run, and ensure to condition hole prior to running casing, ex: backream trouble intervals. Gas Cut Mud Gas cut mud has been seen at OPP, ensure sufficient MW is used during hole section. Ensure gas detectors are always functioning. Watch swab effect. Oliktok Point O-233 SB NB Injector H2S: Oliktok has no history of H2S. Ensure detectors are tested and functioning. AOGCC to be notified withing 24 hours if H2S is encountered more than 20 ppm during drilling operations Rig will have fully functional automatic H2S detection equipment meeting the requirements of 20 AAC 25.066 In the event H2S is detected, well work will be suspended and personnel evacuated until a detailed mitigation procured can be developed. Wells with over 100ppm H2S readings on Oliktok Point: There are no wells at OPP with H2S 100ppm or greater. Date Facility Sample Location Temp, F H2S ppm Note 5/3/2024 OPP OPP Well 74.6 0.1 OP12-01 5/4/2024 OPP OPP Well 74.1 0.1 OP16-03 5/4/2024 OPP OPP Well 69.0 0.1 OP17-02 5/4/2024 OPP OPP Well 73.3 0.3 OP14-S3 5/4/2024 OPP OPP Well 74.2 0.1 OP03-05 5/4/2024 OPP OPP Well 79.9 0.3 OP04-07 5/4/2024 OPP OPP Well 80.1 0.1 OP08-04 5/5/2024 OPP OPP Well 68.5 0.0 OP05-06 5/6/2024 OPP OPP Well 69.5 0.1 OP10-09 Oliktok Point O-233 SB NB Injector Attachment 4: LOT / FIT Test Procedure * If no fluid returned or questionable returns notify AOGCC before drilling ahead. - mgr Oliktok Point O-233 SB NB Injector Attachment 5: Cement Summary Cement will be displaced with surface hole spud mud with a density ranging from 8.8-9.8 ppg. Cement will be displaced with surface hole spud mud with a density ranging from 8.8-9.8 ppg. Oliktok Point O-233 SB NB Injector Attachment 6: Prognosed Formation Tops All formations expected to be normally pressured. ANTICIPATED FORMATION TOPS & GEOHAZARDS O-233 wp-04 TOP NAME LITHOLOGY EXPECTED FLUID MD (FT) TVDSS (FT) TVD (FT)Est. ML PP (psi)ML PP (ppg) SV4 (Sand)Water 1352 -1264 1311 579 SV1 (Sand)Water 1883 -1652 1699 751 BPRF (Sand)Water 1994 -1715 1762 779 UG4A Ugnu (Sand)Water 2315 -1892 1939 857 UG COAL2 COAL Water 3239 -2402 2449 1082 UG LA3 Ugnu(Sand)Water 3793 -2708 2755 1218 UG MB Ugnu (Sand)Water 4445 -3066 3113 1376 UG MF Ugnu (Sand)Water 4936 -3289 3336 1475 SB NA Schrader (Sand)Water 5217 -3377 3424 1513 SB NB Schrader (Sand)Oil 5410 -3418 3465 1532 8.50 9 5/8" shoe Schrader (Sand)Oil 5432 -3422 3469 1533 8.50 Oliktok Point O-233 SB NB Injector Attachment 7: Wellbore Schematic Oliktok Point O-233 SB NB Injector Attachment 8: Formation Evaluation Program 12.25 Surface Hole LWD Gamma Ray Resistivity 8.5 Production Hole LWD Gamma Ray Resistivity Azimuthal Resistivity Mudlogging No mudlogging is planned. Oliktok Point O-233 SB NB Injector Attachment 9: Wellhead Diagram Oliktok Point O-233 SB NB Injector Attachment 10: Management of Change Oliktok Point O-233 SB NB Injector Attachment 11: Drill Pipe Specs Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Production 54.2763.256.62519.5 S-135 GPDS50 36,100 43,100 560 54.2763.256.62519.5 S-135 NC50 31,032 34,136 560 Oliktok Point O-233 SB NB Injector Attachment 12: Kick Tolerance Calculations Oliktok Point O-233 SB NB Injector Attachment 13: Directional Plan Oliktok Point O-233 SB NB Injector Addendum 1: Miscellaneous Questions * No variance request to regulation. MANUAL GATE VALVEACTUATED BALL VALVEGLOBE VALVEBUTTERFLY VALVECHECK VALVENEEDLE VALVEBALL VALVEPRESSURE RELIEF VALVEMANUAL CHOKE VALVEACTUATED CHOKE VALVEPLUG VALVEPRESSURE TRANSDUCERMANUAL GAUGEVALVE & FITTINGS LEGENDCREATED BY: Will Hemmen DATE: 11/08/2025APPROVED BY:DATE:CLIENT: HILCORP ALASKAWELL: GENERIC P&IDDOYON 142025NOVEMBER8_D14 MPD PFDRIG:FILENAME:DIAGRAM INFORMATIONNOTES / OBSERVATIONSTHIS IS A STANDARD GENERIC PFD FOR ILLUSTRATIONS PURPOSES ONLY.PIPE SPECIFICATIONS, INCLUDING CONNECTION TYPE AND SCHEDULES SHALL BE INCLUDED IN A JOB SPECIFIC PFDALL VALVES SHALL BE TAGGED IN A JOB SPECIFIC PFDMUD PUMPKNIFE VALVEPPPneumatic ValveBOPSTACKBOPSTACKRig FloorWELL HEADPAVPAVBEYOND ARESSSVPPCellarLT3LT5Cement unitOutsidewallMud OutletVent LineRIG MGSPP TRIP TANKSHAKERSFL1M5PTPTPTMGFL3FL2MPD MANIFOLD BUILDINGPRV-011PRV-011CORIOLIS FLOW METERCK1CK1CK2CK2FL1LT9LT7PT2PT1N2SKIDLT2MCKMCKMCK325468ACKACKACKACKACK711310111214PT19RIG MANIFOLD BUILDINGCHOKE LINEDIVERTERLINEDIVERTERLINEBV1BV3RIG HOLE FILLSTANDPIPE MANIFOLDNV1NV1MUD PUMP 2MUD PUMP 1TDSPPFromMud PitsTDSRIG PUMPSBlow Down LineLT4LT2PT3 Rig: Doyon 14 Operation: MPD Program Equipment Specifications Advantages of the Beyond System Smaller footprint: This allows for a faster rig in time and reduced intrusion on the lease. This design also allows the package to be mobilized faster using less trucks to get the equipment to the client (only 2-3 loads to move). The cost reductions seen in this efficient design allow Beyond to offer MPD at an extremely cost-effective rate. Picker-less Package: All existing MPD solutions require a picker truck on location for a duration of 8-12 hours. This can cost tens of thousands of dollars. Simple Nitrogen Injection Connection Trapping Pressure (with Nitro MPD Packages): Other MPD providers rely solely on trapping pressure during pumps off events. This is an imperfect solution and often results in not trapping enough pressure. With pumps down this means you are now at the mercy of Pore Pressure. To help with this many have added large and expensive diverter units or auxiliary pumps. This adds to footprint, rig in time and service time, all costing money. Beyond offers the first Nitrogen Injection MPD Solution. By injecting Nitrogen at the MPD Manifold, wellbore pressure can be increased whenever desired. This design is fast, safe and extremely cost effective. Combined with state of the art PRV technology this allows for very fine control of wellbore pressure. Rig: Doyon 14 Operation: MPD Program 6.1.1 RCD Titan Series Brochure Two RCD heads will be supplied by Beyond for the project. Both will be of the Ares design. Rig: Doyon 14 Operation: MPD Program 6.1.2 Choke Manifold Winterized unit, contains manifold, control unit, Coriolis and tools 5000Psi manifold with two SCB2 Chokes Self resetting pop off valve for redundancy Rig: Doyon 14 Operation: MPD Program Contained inside of manifold building o 2hr battery UPS if power sources fail o Maintains defined values in the event the system is shut down or rebooted o Communicates with WITs All Beyond equipment can directly transfer data to the BEST Panel/PLC and that data can then transmit to WITs on a single data line Remote tablet for command center or doghouse o Tablet presents more data to user Presents logic and flexibility in defining pressures at specific flow rates More independence from rig monitor screens Communicates with BEST Panel via WIFI Calgary can connect remotely to diagnose/monitor/update Ability to control Nitrogen addition during pump off events for improved EMW targeting (Not included with this package) Dynamically controls chokes with pressure that changes from pumps on to pumps off automatically o Choke set point positioning is improved with a new logic system Second choke can be set as a relief valve for redundancy HPU is powered via air and electricity for additional redundancy to improve function 6.1.3 Pressure Relief Valve Nitro PRV o Nitrogen powered PRV that automatically resets to 75% of set off pressure o Independent of electrical power Rig: Doyon 14 Operation: MPD Program 6.1.4 Coriolis Flow Meter Very accurate (+/- 0.05%) measure of: o Mass flow rate o Volumetric flow rate o Density o Temperature Effectively replaces rigs flow show during MPD operations Displays values on the rigs data acquisition system (e.g. PASON) CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 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:Brad Gorham To:Rixse, Melvin G (OGC) Cc:Cody Dinger Subject:FW: [EXTERNAL] RE: Nikaitchuq 0-233 PTD (225-131) Worst Case Safety Factors for casing design Date:Friday, December 12, 2025 11:47:15 AM Attachments:image002.png Mel, See the snapshot below. Let me know if you need anything else or have any other questions. Thanks, Brad From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Thursday, December 11, 2025 6:52 PM To: Brad Gorham <brad.gorham@hilcorp.com> Subject: [EXTERNAL] RE: Nikaitchuq 0-233 PTD (225-131) Worst Case Safety Factors for casing design Brad, Please provide the worst case safety factors (tension, collapse, burst) for Hilcorps casing design on this well. 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). From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, December 11, 2025 2:34 PM To: brad.gorham@hilcorp.com Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: Nikaitchuq 0-233 PTD (225-131) AOR Brad, The AOR for this second submission of the Nikaitchuq O-233 PTD is missing the KRU 3R- 101/L1 evaluation. You had previously sent me (on 14 NOV) an updated AOR table that included it. I can attach that table to this PTD and make a reference; just wanted to confirm that works for you. 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 Dewhurst, Andrew D (OGC) From:Brad Gorham <brad.gorham@hilcorp.com> Sent:Thursday, 11 December, 2025 14:39 To:Dewhurst, Andrew D (OGC) Cc:Rixse, Melvin G (OGC); Cody Dinger Subject:RE: [EXTERNAL] Nikaitchuq 0-233 PTD (225-131) AOR Andy, Yes, that plan of a ack works for me. Thanks for the heads up. Thanks, Brad From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, December 11, 2025 2:34 PM To: Brad Gorham <brad.gorham@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: [EXTERNAL] Nikaitchuq 0-233 PTD (225-131) AOR Brad, The AOR for this second submission of the Nikaitchuq O-233 PTD is missing the KRU 3R-101/L1 evaluation. You had previously sent me (on 14 NOV) an updated AOR table that included it. I can attach that table to this PTD and make a reference; just wanted to con rm that works for you. 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. 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. 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. NIKAITCHUQ Nikaitchuq O-233 225-131 SCHRADER BLUFF OIL WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:NIKAITCHUQ O-233Initial Class/TypeSER / PENDGeoArea890Unit11400On/Off ShoreOnProgram SERWell bore segAnnular DisposalPTD#:2251310Field & Pool:NIKAITCHUQ, SCHRADER BLUFF OIL - 561100NA1 Permit fee attachedYesADL3885832 Lease number appropriateYes3 Unique well name and numberYes NIKAITCHUQ, SCHRADER BLUFF OIL - 561100 - governed by CO 477B4 Well located in a defined poolYes Includes easement through KRU: ADL 4193885 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 Area Injection Order 10D14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15 All wells within 1/4 mile area of review identified (For service well only)Yes16 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 20" 129.5# X-52 Grouted to 80'18 Conductor string providedYes SC/PC 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir19 Surface casing protects all known USDWsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21 CMT vol adequate to tie-in long string to surf csgYes SC/PC 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir22 CMT will cover all known productive horizonsYes SC/PC 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir23 Casing designs adequate for C, T, B & permafrostYes Doyon 14 has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows no close approaches with HSE risk.26 Adequate wellbore separation proposedYes 16" Diverter below BOPE - Inspectors should inspect for bends and distance27 If diverter required, does it meet regulationsYes All fluids planned to be statically overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Doyon 14 has 3-1/16" Remote Choke, 3-1/8" Manual Choke, 14 3-1/8" 5M manual gate valves.31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo Nikaitchuq has no identified H2S conditions. Monitoring required.33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)Yes35 Permit can be issued w/o hydrogen sulfide measuresYes Expected reservoir pressure is 8.5 ppg EMW36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate16-Dec-25ApprMGRDate16-Dec-25ApprADDDate16-Dec-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 12/17/2025