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O 222
Other Order 222 Docket Number: OTH-25-037 Granite Point Field Granite Pt St 17586 011 (PTD 2250570) 1. July 8, 2025 225-057 PTD and 325-406 Sundry 2. July 8, 2025 Background emails 3. July 31, 2025 AOGCC notice of proposed enforcement 4. August 13, 2025 Hilcorp request for informal review 5. August 14, 2024 Informal review scheduling 6. October 14, 2025 Hilcorp Request for hearing 7. October 14, 2025 AOGCC notice of public hearing 8. November 24, 2025 Hilcorp hearing scheduling and questions emails 9. November 28, 2025 Steve McKeever comments 10. December 2, 2025 Hearing transcripts and presentations 11. December 2, 2025 Hilcorp hearing follow up clarifications 12. December 22, 2025 Hilcorp civil penalty payment STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage Alaska 99501 Re: Failure to Notify of Changes to Approved Permit ) ) ) ) ) ) ) Docket Number: OTH-25-037 Other Order 222 Final Granite Point Field Granite Pt St 17586 011 (PTD 2250570) December 22, 2025 FINAL DECISION AND ORDER On July 31, 2025, the Alaska Oil and Gas Conservation Commission (AOGCC) issued a Notice of Proposed Enforcement Action (Notice) to Hilcorp Alaska, LLC (Hilcorp). The Notice proposed a civil penalty of $100,000 under AS 31.05.150(a) for failure to notify the AOGCC of changes to an approved permit in violation of 20 AAC 25.507. Hilcorp requested an informal review that was held at the AOGCC office on August 21, 2025. Following the informal review, the AOGCC issued Other Order 222 (OO 222) on October 3, 2025, assessing a reduced civil penalty of $30,000. Pursuant to 20 AAC 25.535(d), OO 222 would become a final order unless Hilcorp filed a request for a hearing within 10 days, in which case OO 222 would take no effect. Hilcorp, by letter dated October 10, 2025, timely filed a request for hearing. A public hearing on the matter was held on December 2, 2025. The record closed at 5:00 p.m. on that day. This final decision and order follow. FINDINGS AND CONCLUSIONS: 1. Development well Granite Pt St 17586 011 was drilled in July 2025. The Permit to Drill (PTD 225-057), approved by the AOGCC on June 25, 2025, authorized installation of 9- 5/8” 47# L-80 surface casing with an associated pressure test of 3,500 psi. 2. PTD 225-057 provided engineering information and calculations specific to 9-5/8” 47# L- 80 surface casing that was listed on the 10-401 form. Information and calculations included, but were not limited to, the wellbore schematic, casing connection and performance data, cement volumes, cement displacement volumes, casing pressure test, and casing design factors. 3. As confirmed by the 10-407 form received November 25, 2025, and testimony during the December 2, 2025, hearing, Hilcorp ran and installed 9-5/8” 40# L-80 surface casing on July 7 and 8, 2025. Other Order 222 Final December 22, 2025 Page 2 of 4 4. Hilcorp notified the AOGCC via email on July 8, 2025, that a well identified as BR 11-86 had been run with 9-5/8” 40# L-80 casing and requested authorization to pressure test the casing to a reduced pressure of 3,000 psi. At the time, AOGCC could not locate a well identified as BR 11-86 in its records. After requesting Hilcorp clarify the well name, it was determined that Hilcorp was referring to well Granite Pt St 17586 011 (PTD 225-057) on Bruce Platform. 5. Hilcorp ran 9-5/8” 40# L-80 surface casing without prior approval from the AOGCC. 6. Casing selection is an important part of oil and gas well design because it affects well integrity, safety, and long-term performance. Regulatory agencies like the AOGCC require casing programs that protect fresh groundwaters, contain formation pressures, meet safety margins for burst, collapse, and tension, and support cementing requirements. 7. When the casing changes, mechanical properties of the casing also change such as internal diameter (ID), outer diameter (OD), connections, rated burst pressure, rated collapse pressure, rated body yield strength, and joint make-up torque. Changes to ID and OD affect the required cement volume and cement displacement volume. The chemical makeup and resistance to corrosion may also change. 8. In the specific instance described in this order, all physical properties of the casing outlined above changed except the OD and the chemical makeup. 9. Hilcorp stated in the informal review that because “47/40” #/ft was written in the ‘Tubular Program’ section of its permit application it believed it was authorized to run 40# casing in the well even though no engineering calculations were submitted for the thinner walled casing. 10. 20 AAC 25.507(a) states in relevant part: “Except as otherwise provided by 20 AAC 25.015, if an operator desires to make a substantive change in a program or activity for which commission approval is required and has been obtained under AS 31.05 or this chapter, complete details of the well's current condition and the proposed change must be submitted to the commission with an Application for Sundry Approvals (Form 10-403). A change to an approved program or activity may not be undertaken without commission approval. The commission will condition its approval as the commission considers necessary or appropriate to ensure compliance with the standards on which the original approval was based.” 11. Hilcorp stated that the AOGCC has not defined “substantive change” in statute or regulation. 12. Hilcorp stated that the casing change outlined in this order is not a “substantive change” in the Cook Inlet region of Alaska, but it would be a “substantive change” on the North Slope of Alaska. 13. Statutory or regulatory definitions of words are unnecessary when they have a commonly understood ordinary meaning. A commonly understood, dictionary definition of substantive is “important, real, or meaningful; supported by facts or logic.”1 1 Substantive, The Britannica Dictionary, https://www.britannica.com/dictionary/substantive (last visited December 18, 2025). Other Order 222 Final December 22, 2025 Page 3 of 4 14. Moreover, if Hilcorp had confusion on whether changing the approved well casing would be considered a “substantive change” by the AOGCC, it could have contacted the AOGCC for clarification. Hilcorp chose not to. Instead, Hilcorp unilaterally made the change without seeking AOGCC approval even though 20 AAC 25.507(b) allows for oral approval of changes when operational necessity requires prompt action. 15. Changing the casing is a substantive change. This is a consistent interpretation of the regulation by the AOGCC. 16. John A. Howard of Altus Well Experts testified as an expert witness on behalf of Hilcorp and presented a design change stress assessment for the 9-5/8” 40# L-80 surface casing. 17. Mr. Howard testified that his analysis was performed several weeks before the hearing. 18. Hilcorp did not provide evidence that it had performed a safety analysis of the 40# casing before running it in the well. 19. Hilcorp provided two example wells on the Bruce Platform from 1984 and 1989 that had 40# casing. 20. The initial proposed penalty for this violation was $100,0002, an increase from past fines for similar unauthorized changes to approved programs. 21. The factors in AS 31.05.150(g)3 were considered in determining the appropriate penalty. After the informal review, the AOGCC reduced the penalty to $30,000 due to no injury to the public or the environment. 22. The AOGCC received one public written comment on the matter. NOW THEREFORE IT IS ORDERED THAT: OO 222 took no effect by Hilcorp’s timely request for a hearing. Based on the findings outlined above, the AOGCC finds that Hilcorp committed the violation as initially alleged in OO 222 and restated in the Findings and Conclusions above. Hilcorp is assessed a civil penalty in the amount of $30,000 for the violations detailed within this final order. If this order is not appealed, the fine must be paid within 30 days of issuance. If appealed, the fine will be held in abeyance until the appeal process is complete. In assessing the civil penalty, the AOGCC considered the factors set forth in AS 31.05.150(g), including the seriousness of the violation, Hilcorp’s compliance history, the need to deter future violations, and the economic benefit resulting from noncompliance. The violation involved an unauthorized change to surface casing design, a well-integrity barrier intended to protect freshwater resources and ensure operational safety. Hilcorp acted with full control over the activity and installed the casing without prior commission approval or supporting engineering analysis. 2 AS 31.05.150(a) provides for not more than $100,000 for the initial violation and not more than $10,000 for each day thereafter on which the violation continues. 3 AS 31.05.150(g) requires AOGCC to consider nine criteria in setting the amount of a civil penalty. Other Order 222 Final December 22, 2025 Page 4 of 4 Hilcorp’s compliance history demonstrates a recurring pattern of unauthorized changes to approved programs. The AOGCC has issued ten4 violations to Hilcorp for changes to approved programs, five of which were issued in 2025 alone. This pattern calls into question the effectiveness of corrective actions implemented in responses to past enforcement actions and weighs heavily in favor of a meaningful penalty to deter continued noncompliance and reinforce the necessity of prior regulatory approval. Although no injury to the public or the environment was demonstrated in this instance, the absence of harm does not mitigate the seriousness of bypassing regulatory review for a fundamental well- design element. The reduced penalty of $30,000 reflects consideration of the lack of demonstrated harm while still addressing the need for deterrence and regulatory accountability. DONE at Anchorage, Alaska and Dated December 22, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner cc: Mel Rixse Jim Regg Phoebe Brooks AOGCC Inspectors RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. 4 Other Order 80, Other Order 116, Other Order 117, Other Order 118, Other Order 199, Other Order 220, Other Order 222, Other Order 225, Docket OTH-25-011, Docket OTH-25-051. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.12.22 09:21:15 -09'00' Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.12.22 13:36:05 -09'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Other Order 222 Final (Hilcorp) Date:Monday, December 22, 2025 2:40:36 PM Attachments:OTHER222 Final.pdf Failure to Notify of Changes to Approved Permit Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage Alaska 99501 Re: Failure to Notify of Changes to Approved Permit ) ) ) ) ) ) Docket Number: OTH-25-037 Other Order 222 Granite Point Field Granite Pt St 17586 011 (PTD 2250570) October 3, 2025 DECISION AND ORDER On July 31, 2025, the Alaska Oil and Gas Conservation Commission (AOGCC) issued a Notice of Proposed Enforcement Action (Notice) to Hilcorp Alaska, LLC (Hilcorp). The Notice proposed a $100,000 civil penalty under AS 31.05.150(a). SUMMARY OF PROPOSED ENFORCEMENT ACTION: Hilcorp violated the provisions of 20 AAC 25.507 (“Change of an approved program”) while performing well construction at Granite Point Field, Granite Pt St 17586 011. Development well Granite Pt St 17586 011 was drilled in July 2025. The Permit to Drill (PTD 225-057) approved by AOGCC on June 25, 2025, included installation of 9-5/8” 47# L-80 secondary surface casing. Hilcorp notified AOGCC on July 8, 2025, that a well identified as BR 11-86 had been run with 9- 5/8” 40# casing and was requesting to pressure test the casing to a reduced pressure of 3000 psi. At the time, AOGCC could not locate a well identified as BR 11-86 in its records. After requesting Hilcorp clarify the well name, it was determined that Hilcorp was referring to well Granite Pt St 17586 011 (PTD 225-057). After review of the permitted well referenced, AOGCC determined that Hilcorp had unilaterally chosen to run 9-5/8” 40# L-80 secondary surface casing, a lighter casing with a larger internal diameter and lower burst resistance, than what was permitted. For this violation, the AOGCC proposed to impose a civil penalty on Hilcorp under AS 31.05.150 in the amount of $100,000 (an increase from past fines for similar unauthorized changes to approved programs). FINDINGS AND CONCLUSIONS: On August 13, 2025, Hilcorp responded to the Notice and requested an informal review. The informal review was held at the AOGCC office on August 21, 2025. During the review Hilcorp acknowledged that the approved PTD 225-057 identified 9-5/8” 47# casing was to be run in the well on the 10-401 form and in multiple engineering calculations later in the approved permit application. Hilcorp pointed out that they had identified in the ‘Tubular Program’ section of their permit application that they had “47/40” #/ft casing written so that Hilcorp believed they could be justified in running 40# casing even though they submitted no engineering calculations for the thinner walled casing. Other Order 222 October 3, 2025 Page 2 of 2 AOGCC’s determination is that if a thinner walled casing is run in a well that isn’t clearly identified on the 10-401 application form and in their engineering calculations, Hilcorp must request approval from the AOGCC for this change. The AOGCC finds that Hilcorp committed the violation as initially alleged in the Notice but that the proposed $100,000 penalty should be reduced to $30,000 under AS 31.05.150(g).1 NOW THEREFORE IT IS ORDERED THAT: Hilcorp is assessed a civil penalty in the amount of $30,000 for the violation detailed within this Order. If this Order is not appealed, the fine must be paid within 30 days of issuance. If appealed, the fine will be held in abeyance until the appeal process is complete. As an Operator involved in an enforcement action, Hilcorp Alaska, LLC is required to preserve documents concerning the above action until after resolution of the proceeding. DONE at Anchorage, Alaska and Dated October 3, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE Pursuant to 20 AAC 25.535(d), this order becomes final 11 days after it is issued unless within 10 days after it is issued the person files a written request for a hearing, in which case the proposed decision or order is of no effect. If the person requests a hearing, the commission will schedule a hearing under 20 AAC 25.540. As provided in AS 31.05.080(a), within 20 days after this order becomes final as discussed above, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. 1 AS 31.05.150(g) requires the AOGCC to consider nine criteria in setting the amount of a civil penalty. Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.10.03 14:22:25 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.10.03 14:25:52 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Other Order 222 (Hilcorp) Date:Friday, October 3, 2025 2:41:39 PM Attachments:OTHER222.pdf Please see attached. Regards, Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v 12 Lfl Hilcorp Cook Inlet, LLC P.O.Box 61229 Houston TX 77208-1229 Owner: 40012563 Check Date: 1 01/30/20261 Check Number: 4730000051 SAP .Dp NO: jm Date ERYOTCe No Discount Met Amtwnt. 1900000046 12/22/2025 OTHERORDER222 $0.00 $30,000.00 THIS CHECK IS PRINTED ON CHEMICALLY REACTIVE PAPER THAT HAS VISIBLE FIBERS AND A WATERMARK -HOLD TO LIGHT TO VIEW /JP MORGAN r• Hilcorp Cook Inlet, LLC P.O.Box 61229 Houston TX 77208-1229 Thirty Thousand Dollars And Zero Cents PAY STATE OF ALASKA TO THE AOGCC ORDER OF 333 WEST 7TH AVE ANCHORAGE AK 99501-3539 Void After tA0 na.,c Check No Check Date Check Amount 4730000051 101 /30/2026 I * * * * * $ 30,000.00 A 6L t2C Authorized Signature 1104 7 300000 5 ill• 1: L 1 L 3008801: 290 50 1086 511' 11 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:Sean McLaughlin To:Coldiron, Samantha J (OGC) Cc:Denali Kemppel; Wyatt Rivard; Hobie Temple Subject:RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Date:Tuesday, December 2, 2025 6:11:05 PM Attachments:9.625_GBCD_40#-L80.pdf 9.625 47 L80 DWC C ; 10-16-23.pdf Hi Samantha, Thank you for your support in getting a computer set up for me to present from. If possible, I’d like to add a follow up fact pertaining to the final question about casing rotation. Casing rotation was an important design factor for this well. It is the reason we chose to run 40# GBCD rather than the non-torque rated 47# BTC. The yield torque of the 40# GBCD is significantly higher than the 47# DWC/C (75,840 ft-lbs vs 59,400 ft-lbs) It is also good to note that the compression efficiency for the 40# is 100% while the compression efficiency of the 47# DWC/C is only 50%. This is because the coupling OD is the same. The same safety joint crossover is used for 47# DWC/C and 40# GBCD. No change was required. While all minor operational changes, in some areas the 40# casing is more favorable (hook load, drift, ECD, and torque). Regards, Sean 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. Connection Data Sheet OD (in.)WEIGHT (lbs./ft.)WALL (in.)GRADE DRIFT (in.)RBW%CONNECTION 9.625 Nominal: 47.00 Plain End: 46.18 0.472 L-80 8.525 87.5 DWC/C PIPE PROPERTIES Nominal OD 9.625 in. Nominal ID 8.681 in. Nominal Area 13.572 sq.in. Grade Type API 5CT Min. Yield Strength 80 ksi Max. Yield Strength 95 ksi Min. Tensile Strength 95 ksi Yield Strength 1,086 klb Ultimate Strength 1,289 klb Min. Internal Yield 6,870 psi Collapse 4,760 psi CONNECTION PROPERTIES Connection Type Semi-Premium T&C Connection OD (nom) 10.625 in. Connection ID (nom) 8.681 in. Make-Up Loss 4.813 in. Coupling Length 9.625 in. Critical Cross Section 13.572 sq.in. Tension Efficiency 100.0%of pipe Compression Efficiency 50.0%of pipe Internal Pressure Efficiency 100.0%of pipe External Pressure Efficiency 100.0%of pipe CONNECTION PERFORMANCES Yield Strength 1,086 klb Parting Load 1,289 klb Compression Rating 543 klb Min. Internal Yield 6,870 psi External Pressure Resistance 4,760 psi Maximum Uniaxial Bend Rating 19.0 °/100 ft Ref String Length w 1.4 Design Factor 16,500 ft FIELD TORQUE VALUES Min. Make-up Torque 40,000 ft.lbs Opti. Make-up Torque 45,000 ft.lbs Max. Make-up Torque 50,000 ft.lbs Min. Shoulder Torque 4,000 ft.lbs Max. Shoulder Torque 32,000 ft.lbs Max. Delta Turn 0.200 Turns Connection Yield Torque 59,400 ft.lbs For detailed information on performance properties, refer to DWC Connection Data Notes on following page(s). Connection specifications within the control of VAM USA were correct as of the date printed. Specifications are subject to change without notice. Certain connection specifications are dependent on the mechanical properties of the pipe. Mechanical properties of mill proprietary pipe grades were obtained from mill publications and are subject to change. Properties of mill proprietary grades should be confirmed with the mill. Users areadvised to obtain current connection specifications and verify pipe mechanical properties for each application. All information is provided by VAM USA or its affiliates at user's sole risk, without liability for loss, damage or injury resulting from the use thereof;and on an "AS IS" basis without warranty or representation of any kind, whether express or implied, including without limitation any warranty of merchantability, fitness for purpose or completeness. This document and its contents are subject to change without notice. In no event shall VAM USA or its affiliates be responsible for any indirect, special, incidental, punitive, exemplary or consequential loss or damage (including withoutlimitation, loss of use, loss of bargain, loss of revenue, profit or anticipated profit) however caused or arising, and whether such losses or damages were foreseeable or VAM USA or its affiliates was advised of the possibility of such damages. 10/16/2023 3:02 PM VAM USA 2107 CityWest Boulevard Suite 1300 Houston, TX 77042 Phone: 713-479-3200 Fax: 713-479-3234 VAM USA Sales E-mail: VAMUSAsales@vam-usa.com Tech Support E-mail: tech.support@vam-usa.com DWC Connection Data Notes: 1.DWC connections are available with a seal ring (SR) option. 2.All standard DWC/C connections are interchangeable for a given pipe OD. DWC connections are interchangeable with DWC/C-SR connections of the same OD and wall. 3.Connection performance properties are based on nominal pipe body and connection dimensions. 4.DWC connection internal and external pressure resistance is calculated using the API rating for buttress connections. API Internal pressure resistance is calculated from formulas 31, 32, and 35 in the API Bulletin 5C3. 5.DWC joint strength is the minimum pipe body yield strength multiplied by the connection critical area. 6.API joint strength is for reference only. It is calculated from formulas 42 and 43 in the API Bulletin 5C3. 7.Bending efficiency is equal to the compression efficiency. 8.The torque values listed are recommended. The actual torque required may be affected by field conditions such as temperature, thread compound, speed of make-up, weather conditions, etc. 9.Connection yield torque is not to be exceeded. 10.Reference string length is calculated by dividing the joint strength by both the nominal weight in air and a design factor (DF) of 1.4. These values are offered for reference only and do not include load factors such as bending, buoyancy, temperature, load dynamics, etc. 11.DWC connections will accommodate API standard drift diameters. 12.DWC/C family of connections are compatible with API Buttress BTC connections. Please contact tech.support@vam-usa.com for details on connection ratings and make-up. Connection specifications within the control of VAM USA were correct as of the date printed. Specifications are subject to change without notice. Certain connection specifications are dependent on the mechanical properties of the pipe. Mechanical properties of mill proprietary pipe grades were obtained from mill publications and are subject to change. Properties of mill proprietary grades should be confirmed withthe mill. Users are advised to obtain current connection specifications and verify pipe mechanical properties for each application. All information is provided by VAM USA or its affiliates at user's sole risk, without liability for loss, damage or injury resulting from the usethereof; and on an "AS IS" basis without warranty or representation of any kind, whether express or implied, including without limitation any warranty of merchantability, fitness for purpose or completeness. This document and its contents are subject to change without notice. In no event shall VAM USA or its affiliates be responsible for any indirect, special, incidental, punitive, exemplary or consequential loss ordamage (including without limitation, loss of use, loss of bargain, loss of revenue, profit or anticipated profit) however caused or arising, and whether such losses or damages were foreseeable or VAM USA or its affiliates was advised of the possibility of such damages. 10/16/2023 3:02 PM Rev. 3 (07/11/2017)Casing: 9.625 OD, 40 ppfConnection:Casing Grade: L‐80 Coupling Grade: API L‐809 5/80.3958.67940.008.8358.75038.9711.454L‐8080,000 95,000 3,0909165,750 4,230195,460 38.110.6255.000010.00018.501 Material SpecificationAPI L‐8080,00095,000 947 100%34.51,406 External Pressure (%)100%1,670100%75,840 947100%1.6210,00020,000 Running Tq. (ft‐lbs)See GBT RP Max. Operating Tq. (ft‐lbs)*72,050MAKEUP TORQUE Min. MU Tq. (ft‐lbs) Max. MU Tq. (ft‐lbs) Joint Str. (kips) Compression (%) Ratio of Areas (Cplg/Pipe) Min. Tension Yield (kips) Yield Torque Min. Tension Ult. (kips) Tension (%) Yield Torque (ft‐lbs) Thread Str. (kips) Internal Pressure (%) Build Rate to Yield (ft)Tension EfficiencyBendingGB CD Butt 10.625 CONNECTION PERFORMANCE RATINGS/EFFICIENCIES Min. Yield Str. (psi) Min. Ultimate Str. (psi) Coupling Length (in.) Critical Cross‐Sect. (in.2) Coupling OD (in.) Makeup Loss (in.) Yield Torque (ft‐lbs) Build Rate to Yield (ft)GB CD Butt 10.625 COUPLING GEOMETRY High Collapse (psi)TorqueBending API (psi) Pl. End Yield Str. (kips) Min. Int. Yield Press. (psi)CollapseTensionPressure Material Specification Min. Yield Str. (psi) Min. Ultimate Str. (psi) Plain End Weight (ppf) Plain End Area (in.2)PIPE BODY PERFORMANCE Nominal Weight (ppf) Nominal ID (in.) API Alternate Drift Dia. (in.)GB CD Butt 10.625PIPE BODY GEOMETRY Nominal OD (in.) Wall Thickness (in.) Drift Diameter (in.)GB Connection Performance Properties SheetE N G I N E E R I N G T H E R I G H T C O N N E C T I O N S TMUnits:USCustomary(lbm,in.,°F,lbf)1kip=1,000lbs*SeeRunningProcedurefordescriptionandlimitations.Seeattached:NotesforGBConnectionPerformanceProperties.GBTRunningProcedure(GBTRP):www.gbconnections.com/resources/running-procedures/ BlankingDimensions:www.gbconnections.com/resources/documentation/#blanking-dimensionsConnectionyieldtorqueratingbasedonphysicaltestingorextrapolationtherefrom GB Connections LLC - Notes for Connection Performance Properties Rev. 3 (Feb. 2024) E N G I N E E R I N G T H E R I G H T C O N N E C T I O N S TM 1. The data provided in GB Connections LLC (“GBC”) - Notes for Connection Performance Properties (“Notes”), and in GBC - Running Procedures for Casing ("Running Procedures”), are for general informational purposes only and do not constitute professional advice. The GBC Notes and Running Procedures and are intended to be, and should be, supplemented with the professional judgment of qualified personnel selected by the Buyer and/or User (“Customer”) for specific applications. These Notes should not be relied upon for any specific application, including those applications in which the Customer requires modifications to GBC’s standard product specifications. 2. The professional judgment of qualified personnel selected by the Customer should be utilized for all aspects of a specific application, including but not limited to, the well design, selection of suitable materials for site-specific well conditions, field handling, deployment, and all other well operations, including any casing and/or connection related issues that may occur during and after rotating operations. 3. GBC Terms and Conditions of Sale are incorporated herein by reference and may be accessed at: www.gbconnections.com/pdf/Terms-and-Conditions.pdf. These Notes do not negate or otherwise modify GBC Terms and Conditions of Sale, including those Warranties found in Paragraph 10 (“Warranty; Disclaimer”). 4. All dimensions shown are nominal. Plain end weight is calculated in accordance with API TR 5C3. Performance properties are empirical, based on nominal dimensions, minimum material yield and ultimate strengths, and calculated in general accordance with industry standard formula(s) assuming uniaxial loading. All properties are calculated with material strengths at room temperature. NOTE: Material properties change with temperature. 5. Joint strength is the lesser of pipe thread strength and minimum coupling tension as calculated in accordance with API TR 5C3. Tensile efficiency is calculated using coupling strength based on ultimate material strength per API TR 5C3 divided by plain end yield strength of the casing. Minimum Coupling Tension based on material yield strength is provided for information only. Performance values presented for tension do not account for failure by pull-out (which can occur unexpectedly under certain circumstances), effects of internal and external pressure, thermally induced axial loads, casing curvature (bending), and/or other static and dynamic loads that may occur singularly or in combination during downhole deployment and with subsequent well operations. 6. Drift diameters are based on Standard and Alternate drift sizes per API 5CT. Drift diameters are not specified for API 5L pipe. Drift diameters shown on the Performance Property Sheets for GBC connection products represent the diameter of the drift mandrel used for end-drifting after coupling buck on. When shown, the alternate drift diameter is used for end drifting. Drift testing is performed in accordance with currently applicable API Specifications. 7. Minimum Internal Yield Pressure Performance values for Casing (API 5CT), Line Pipe (API 5L), and mill casing proprietary grades are based on API TR 5C3 formulas and assume 87.5% minimum wall thicknesses unless otherwise noted. Minimum Internal Yield Pressure efficiency for GBC is the lesser of the Minimum Internal Yield Pressure of the coupling and Leak Resistance divided by pipe body Minimum Internal Yield Pressure (all based on API TR 5C3 formulas). GBC products typically demonstrate pressure resistance exceeding the mating pipe body with a pressure efficiency > 100%. Certain casing size, weight, grade, and connection combinations may have gas pressure efficiency < 100% and will be so noted. Pressure efficiency can only be achieved when connections are properly assembled in strict accordance with GBC Running Procedures, which may be accessed at: www.gbconnections.com/pdf/RP-GB-DWC-Connections.pdf. 8. Compression efficiency of the Casing/Connection combinations does not consider the axial load that causes pipe body buckling. The compressive load that causes buckling is usually less than the pipe body compressive yield strength and is dependent on many factors including, but not limited to, string length (or slenderness ratio; L/D), thermally induced axial loads, and annular clearance that may (or may not) lend side support to the casing string. 9. Bending values assume a constant radius of curvature where the casing is in uniformly intimate contact with the wall of the wellbore (i.e. when the upset at the coupling OD is small compared with wellbore wall irregularities). When the radius of curvature is not constant due to large wellbore wall irregularities or where there is not uniformly intimate contact with the wellbore wall, varying trajectory, micro doglegs, wash-outs, rock ledges, and other downhole conditions, unpredictable and unquantifiable excessive bending stresses can occur that may be detrimental to casing and connection performance. 10. Fatigue failures are a function of material properties, stress range, and number of stress reversal cycles. API 5CT, API 5L, and mill proprietary casing/coupling materials have a finite fatigue life. Higher stress ranges yield lower fatigue life. So, as a general rule of thumb, casing should never be rotated at higher RPMs than needed for task accomplishment. For the same stress range, casing rotated at 25 RPMs will generally last 4 times longer (more rotating hours) than casing rotated at 100 RPMs. However, with fatigue, there are opportunities for unexpected higher stress reversal levels (cycles) associated with vibration, thermally induced axial loads, and bending (see above) in addition to all other stress reversals imparted during running, rotating, reciprocating, pressure testing, pumping, etc. The extent and quality of the cement job is also a factor. Under aggressive, high-volume, multi-stage hydraulic fracturing operations, the casing string (including the connections) is severely taxed such that local stress range(s) and actual number of applied cycles cannot be precisely determined without full string instrumentation. 11. External pressure efficiency (expressed in percent) is the ratio of the lesser of Minimum Internal Yield Pressure and Leak Resistance for coupling (calculated per API TR 5C3) divided by the API collapse rating of the casing. External pressure efficiency has not been verified by testing and does not consider other applied loads. External pressure efficiency does not account for any high collapse rating that may be shown on GBC Performance Property Sheets. 12. Maximum Makeup Torque is provided for guidance only. Customer assumes all risks associated with casing and connection related issues that occur during and after rotating operations and should rely upon the professional judgment of qualified personnel to address casing and connection related issues that occur during and after rotating operations for specific applications. This value is not the same as the Connection Yield Torque shown. Connection Yield Torque is the lowest yield torque rating for the critical cross-section of pipe body, connector body, pin nose, and the threadform load flank bearing area. Connection Yield Torque does not consider radial buckling of the pipe or connection due to excessive jaw pressure during torque application. Torque in connections can increase or decrease over that applied at makeup (connection tightening/loosening) with rotating and stimulation operations due to slip-stick, shock loads, bending, tight spots, vibration(s), temperature, and other downhole factors that may occur individually or in combination. 13. Every GBC connection requires the proper amount and distribution of thread compound to all pin and coupling threads and careful field make up in strict accordance with GBC Running Procedures to provide expected levels of performance in service. GBC Running Procedures may be accessed at: www.gbconnections.com/pdf/RP-GB-DWC-Connections.pdf. 14. Reactions among water, drilling muds and other fluids, and chemicals introduced by Customer with downhole formation fluids may result in an environment detrimental to casing and connection performance. Customer should carefully consider all aspects of the string design including material compatibility with respect to possible corrosion, sour conditions, possible reaction(s) among user introduced water and chemicals (liquids and solids) with in situ geochemistry and other factors that may result in unexpected casing and/or connection failure at or below published ratings. 15. These Notes and the Performance Properties described herein, as well as the Running Procedures and the information contained therein, are subject to change without notice. The Notes and the Running Procedures are not controlled documents. These Notes are provided on an “as is” basis, no warranty, express or implied, is given, and GBC does not assume any liability or responsibility for the information contained herein. Anyone making use of the information contained in the Notes or Running Procedures does so at their own risk and assumes any and all liability from such use. 16. Customer is advised to obtain the current GBC Performance Property Sheet for each GBC connection product purchased, which are available on a product-by-product basis, at GBC’s website: www.gbconnections.com. Limitations: All sales made by GBC are subject to its Terms and Conditions of Sale, which are incorporated herein by reference, and may be accessed at: www.gbconnections.com/pdf/Terms-and-Conditions.pdf. By using the GBC Notes and/or the GBC Running Procedures, or upon the purchase of any GBC product(s), Customer warrants, represents and agrees that it has utilized its own knowledge, skill, and judgment, and determined that the GBC product(s) purchased is fit for its intended service, purpose, and use. Customer warrants, represents and agrees that it has read and understands the GBC Terms and Conditions of Sale and agrees to be bound thereby. Running Procedure for Casing with GB Drilling with Casing Connections February 13, 2024 Rev. 15 Page 1 of 9 OVERVIEW This field running procedure applies to makeup of GB Drilling with Casing (GB DwC) Connections which include GB CD, GB CDE, GB CD RDB, GB CD RDB WS, GB CD EHTQ and GB CD Slim Hole Connections with GB Butt (Buttress), GB 4P, and GB 3P thread forms. All GBC Connections are suitable for Running (standard casing applications), Rotating (to aid string advancement), Drilling (Drilling with Casing/Drilling with Liners), and with a special mandrel, Driving. This procedure also applies to the legacy GB Connections known as GB Butt and GB 3P. Numerous factors impact the makeup torque of Buttress (GB Butt) and Modified Buttress Threads (such as GB 4P and GB 3P). Some of these factors include but are not limited to: allowable threading tolerances, joint characteristics (OD, straightness, hooked ends, and weight), vertical alignment (derrick, top drive, and elevator alignment relative to rotary table), thread compound (type, amount, and distribution), snub line (location and orientation), distance between tongs and backups, temperature/weather, equipment type, efficiencies (electrical, hydraulic, and mechanical), grips/dies (type, condition, orientation, location, contact area, and grip distribution), measurement equipment, gauge calibration, personnel, etc. The nature of these types of connections makes it impossible to provide makeup torque values that will yield proper power tight makeup on every rig under all circumstances with the wide variety of existing connection makeup equipment. This procedure has been designed to determine the Running Torque required for proper power tight makeup of GB Connections under the circumstances and with the actual equipment, set up conditions, weather, etc. that exist at the time of running. With proper execution of this procedure, GB Connections will be properly and consistently assembled. LIMITATIONS GB Connections LLC (“GBC”) provides the data and information in this Running Procedure for general informational purposes only in order to provide the User with basic recommended practices. This GBC Running Procedure does not constitute professional advice. This GBC Running Procedure is intended to be, and should be, supplemented with the professional judgment of qualified personnel selected by the Buyer and/or User for specific applications, including the observation of actual makeups throughout the casing run. Every GBC Connection requires the proper amount and distribution of thread compound to all pin and coupling threads and careful field make up in strict accordance with this Running Procedure to provide expected levels of performance in service No structural component can perform satisfactorily if not properly prepared and assembled prior to placing it in service in a downhole environment. In the field, the USER has complete control over proper application of thread compound and field makeup. Therefore, the USER is ultimately responsible for the resulting performance downhole if the User does not follow the professional judgment of qualified personnel, the designer/manufacturer procedures, and/or basic industry best-practices on the rig floor. The GBC Terms and Conditions of Sale are incorporated herein by reference and may be accessed at: www.gbconnections.com/pdf/Terms-and-Conditions.pdf. This Running Procedure does not negate or otherwise modify GBC Terms and Conditions of Sale. All sales made by GBC are subject to its Terms and Conditions of Sale, which are incorporated herein by reference, and may be accessed at: www.gbconnections.com/pdf/Terms-and- Conditions.pdf. By using this GBC Running Procedure, Buyer and/or User warrants, represents and agrees that it has utilized its own knowledge, skill, and judgment and determined that the GBC product(s) is fit for its intended service, purpose, and use. Buyer and/or User warrants, represents and agrees that it has read and understands the GBC Terms and Conditions of Sale and agrees to be bound thereby. Running Procedure for Casing with GB Drilling with Casing Connections February 13, 2024 Rev. 15 Page 2 of 9 DEFINITIONS 1. Minimum Makeup (MU) Torque: Connections must have at least this amount of torque applied and clearly exhibit shoulder engagement with a delta torque spike. 2. Shoulder Torque: MU torque required to achieve shoulder engagement. 3. Running Torque: Developed at start of casing run per GBC Running Procedure and once established, used for the rest of the joints in the string, using data established with progression of the casing run. The Running Torque may be adjusted during the casing run as needed to stay within parameters defined here. The Running Torque will likely vary with each job due to the factors listed in the Overview section. 4. Delta Torque: Difference between Shoulder Torque and final makeup (or dump) torque. 5. Maximum Makeup (MU) Torque: Maximum Makeup Torque provided herein is for guidance only. Customer should rely upon the professional judgment of its qualified personnel to address casing and connection related issues that occur during and after rotating operations for specific applications. This value is not the same as the Connection Yield Torque shown. Connection Yield Torque is the lower yield torque rating for the critical cross-section of pipe body, connector body, pin nose, and the threadform load flank bearing area. Connection Yield Torque does not consider radial buckling of the pipe or connection due to excessive jaw pressure during torque application. Torque in connections can increase or decrease over that applied at makeup (connection tightening/loosening) with rotating and stimulation operations due to slip-stick, shock loads, bending, tight spots, vibration(s), temperature, and other downhole factors that may occur individually or in combination. Final assembly torque including shoulder engagement shall not exceed the Maximum MU Torque shown on size, weight, and grade-specific GB Performance Property Sheets at the beginning of a casing run when establishing the Running Torque. In the unlikely event that Running Torque determined by the procedure meets or exceeds the Maximum MU Torque, call GB Connections for assistance. 6. Yield Torque: Torque that causes yielding in the connection (usually yielding of the pin nose). Yield Torque rating does NOT consider the torque that may radially buckle the pipe body at the grip points. Yield Torque values for the pipe body and connection are based on nominal dimensions and minimum material yield strength. 7. Maximum Operating Torque: The Maximum Operating Torque shown on the GB Connections Performance Property Sheets includes a 5% safety factor on Yield Torque. As such, it represents the limiting torque spike that can be applied to the connection during rotating operations. The Maximum Operating Torque is NOT the Maximum MU Torque and MAY NOT BE a sustainable rotating torque. Operating at the Maximum Operating Torque for any length of time may damage connections due to likely random, unexpected torque spikes that occur during rotating operations. USER should carefully consider this value to determine if a higher Safety Factor on Yield Torque is more suitable for the project-specific application. As a general rule of thumb, rotating RPMs and Torque should be “walked up” to determine the minimum needed for task accomplishment. Additional information on best practices for rotating casing can be found at http://www.gbconnections.com/pdf/White-Paper-Rotating-Casing.pdf. KEY INFORMATION Thread Compound: Best-O-Life 2000, Best-O-Life 2000 Arctic Grade (AG), API Modified, API Modified Hi- Pressure, or any industry recognized equivalent to these products. Thread compound may also be referred to as “dope”. User should avoid products that include Metal Free (MF) in the product name. Tool joint compounds are expressly forbidden for makeup of any GBC Connections. Thread compound shall be applied to all pin and box threads as described here. Running Procedure for Casing with GB Drilling with Casing Connections February 13, 2024 Rev. 15 Page 3 of 9 Torque Values: Minimum and Maximum MU Torque values are provided on individual GB Connections Performance Property Sheets available at the following link: http://www.gbconnections.com Continuous Makeup: Makeup of GB Connections SHALL START AND CONTINUE WITHOUT STOPPING until full power tight makeup is achieved. Makeup Speed: Use of high gear at no more than 40 RPMs is permissible once proper starting thread engagement has occurred. THE FINAL TWO (2) FULL TURNS, AT A MINIMUM, SHALL BE COMPLETED IN LOW GEAR AT LESS THAN 10 RPMS. Pin Nose Engagement: Pin nose engagement is indicated by a spike on an analog torque gauge or a sharp vertical spike on a torque vs. turn plot. As a secondary check, proper power tight makeup is achieved when the coupling covers approximately the middle third of the API Triangle Stamp on the pin (see graphic). The triangle will be stamped on the pin member and indicated by a white locator stripe. Acceptance Criteria: All GB Connections must exhibit shoulder engagement (achieve pin-to-pin or pin-to-shoulder engagement) with a: (1) Delta Torque ranging between 10% and 50% of majority of the previously recorded Shoulder Torques and (2) final torque not exceeding the Running Torque as established in this procedure. Outlier joints that require additional attention would be an exception to Maximum MU Torque limit as discussed under Comments, Troubleshooting. It is imperative that the following procedure be executed carefully at the beginning of every casing run to determine the Running Torque (torque to be used for the rest of the string). Torque values established on an individual casing run are never transferrable to other runs. The Running Torque is determined while running the first 10 joints after joints assembled with threadlocking compounds are made up. Sometimes more than the first 10 joints will be needed to establish the Running Torque due to erratic results and/or other run-specific conditions. The Running Torque may have to be re-established or adjusted during the casing run under certain conditions1 and observations. Use the size- specific GBC Connections Performance Property Sheets (http://www.gbconnections.com) for the Minimum and Maximum MU Torque values. Connections shall be made up until shoulder engagement with Delta Torque between 10% and 50% of the Shoulder Torque (not to exceed the Maximum MU Torque, see procedure below) using the Running Torque value established in this procedure. The Maximum MU Torque at the beginning of the casing run for establishing the Running Torque shall be limited to the value shown on the applicable GBC Connections Performance Property Sheet. The Running Torque shall be used thereafter and throughout the run as the limiting makeup torque value. The Maximum MU Torque on the GBC Performance Property Sheet value is given as a practical limit for avoidance of thread galling, connection damage, and possible tube damage due to excessive jaw pressure that can occur with application of extreme makeup torque. Contact GB 1 Examples include but are not limited to more than an occasional low or high Delta Torque, string of mixed mills, equipment change, large temperature change, and wobbling or noticeable vibration when joint is turning. COUPLING STOPS WITHIN THE MIDDLE 1/3 OF THE API TRIANGLE STAMP PIPE COUPLING COUPLING COVERS APPROX. THE MIDDLE 1/3 OF API TRIANGLE STAMP Running Procedure for Casing with GB Drilling with Casing Connections February 13, 2024 Rev. 15 Page 4 of 9 Connections if more than the Maximum MU Torque value is required for shoulder engagement and/or final makeup, or if torque exceeding the Maximum Operating Torque value is required for the intended service. PROCEDURE FOR ESTABLISHING AND USING THE RUNNING TORQUE 1. Remove coupling thread protectors only after casing is set in V-Door. 2. Always apply fresh thread compound to coupling threads and internal shoulder (where applicable). See Comment No. 1 (below) for discussion on proper amount of thread compound. 3. Remove pin thread protectors only after joint is raised in the derrick. Visually inspect pin threads for sufficient thread compound as described in Comment No. 1; add fresh compound to pin threads and pin nose. 4. Fresh thread compound should NEVER be added on top of dope contaminated with dust, dirt, and/or debris. Threads observed to have contaminated thread compound shall be thoroughly cleaned and dried before applying fresh thread compound. 5. Stab the pin carefully into the coupling of the joint hanging in the rotary table. A stabbing guide is recommended to protect the pin nose and leading thread from physical damage that may contribute to thread galling. Make up each connection until shoulder engagement plus Delta Torque. Record the Shoulder Torque observed for the first 10 joints (excluding threadlocked accessory joints). The Running Torque is (a) the Minimum MU Torque shown on the GB Connections Performance Property Sheets or (b) the Maximum Shoulder Torque recorded from the first 10 makeups + 20%, whichever is higher (rounded to the next highest 500 ft-lbs.) Delta Torque should Primarily be between 10% and 50% of the Shoulder Torque. Running Torque shall not exceed the Maximum MU Torque. When making up the initial joints for establishing the Running Torque carefully watch the torque gauge for the Shoulder Torque and try to manually shut down the tongs before reaching Maximum MU Torque shown on the GB Connections Performance Property Sheets. Alternately, the dump valve should be set to 80% of the Maximum MU Torque during this initial process. 6. After the first 10 makeups (more if necessary due to conditions at the time of the run), use the “Running Torque" established in Step 5 for the remainder of the string. A dump valve is strongly recommended to stop makeup once the established Running Torque is achieved. 7. All connections made up with the established Running Torque should achieve shoulder engagement with the reasonable amount of Delta Torque. Carefully watch for the spike on the torque gauge during each make up to verify shoulder engagement. As a secondary verification, randomly check the makeup position relative to the API Triangle Stamp during the run. Proper power tight makeup position is achieved when the coupling covers the middle 1/3 of the API Triangle Stamp on the pin (see accompanying photo). 8. All connections should achieve shoulder engagement with at least 10% Delta Torque before the Maximum MU Torque is achieved. Running Procedure for Casing with GB Drilling with Casing Connections February 13, 2024 Rev. 15 Page 5 of 9 COMMENTS, TROUBLESHOOTING 1. GB Connections are thread compound friendly. Thread compounds shall be handled, mixed, and applied in strict accordance with the manufacturer’s instructions. THREAD COMPOUND SHALL BE APPLIED TO BOTH PIN AND COUPLING THREADS AND OPPOSING PIN NOSE OR SHOULDER AREA OF EVERY CONNECTION. Thread compound “transfer” between pin and coupling will not provide proper sealing mechanism for the connection to function properly. Sufficient thread compound has been applied when all threads (pin and coupling), pin nose, and coupling ID surfaces are completely covered WITH NO GAPS OR BARE SPOTS. The thread form should be discernible beneath the compound, i.e. when the thread valleys appear half full. Be generous with the thread compound; but avoid over-doping to the point where excessive amounts are squeezed out during assembly. Use of a mustache brush is the preferred method for applying and distributing thread compounds to GB Connections. 2. If threads are cleaned on racks, new dope shall be applied in a light, even coat to both pin and coupling threads. See Comment No. 1 above for description of sufficient thread compound. Clean thread protectors shall be re-applied to freshly doped pin and coupling threads unless the casing run is imminent (no more than a few hours) to avoid contaminating exposed thread compound. 3. All connections should achieve shoulder engagement before reaching the "Running Torque" value determined by this procedure. Any connection that does not achieve a clear spike/shoulder engagement at the established "Running Torque" value shall be visually inspected for position relative to the API Triangle Stamp. a) If the coupling is shy of the API Triangle Stamp Base, the connection shall be broken out, cleaned and inspected visually for thread damage, re-doped, and made-up again (or laid down if threads are damaged). Connections SHALL NEVER be backed up a couple of turns and remade. They shall be completely broken out, cleaned and inspected as described above. b) If the coupling is at or covers the API Triangle base but does not land in approximately the middle third of the API Triangle Stamp, add additional torque to achieve shouldering and finish the makeup. It is common to see high torque (possibly exceeding the Maximum MU Torque) to initiate connection turning. This is acceptable as long as the torque drops off once movement starts and then spikes with shoulder engagement. If acceptable makeup doesn’t occur with one additional torque application, the connection shall be broken out (as described in 3a above). c) Any connection not properly assembled (i.e. not meeting the acceptance criteria) in two (2) attempts (provided threads pass a visual inspection each time) is reject and shall be laid down. Properly doped pin. Properly doped GB Coupling. Running Procedure for Casing with GB Drilling with Casing Connections February 13, 2024 Rev. 15 Page 6 of 9 4. At the established Running Torque, the connections will generally shoulder with Delta Torque between 10% and 50%. High interference connections will tend to have a higher Shoulder Torque and less Delta Torque (at least 10% of the Shoulder Torque is required). Low interference connections will tend to have lower Shoulder Torque and more Delta Torque. In general, GB Connections makeup consistently but will vary due to any of the factors enumerated in the second paragraph of the Overview section of this procedure. However, wide variability on more than a few joints should be investigated for a root cause and, if necessary, a new Running Torque should be adjusted as described below. If a connection appears to have shouldered but doesn’t have at least 10% Delta Torque, the position relative to the API Triangle Stamp should be checked. In just about every instance, the position will have covered the triangle base, so additional torque can be added to complete the makeup as discussed in 3.b) above. Expect an instantaneous spike with showing more than 50% Delta Torque with application of additional torque. Under this condition, this makeup is acceptable. Similarly, random connections here and there with more than 50% Delta Torque is generally not cause for concern. However, if overshooting the 50% maximum Delta Torque target occurs frequently, then the established Running Torque value should be walked down in 500 ft-lbs. to 1,000 ft-lbs. increments until connection makeup routinely falls in line with the stated acceptance criteria. 5. Torque vs. Turn monitoring systems are recommended for field makeup of GB Connections. While Torque vs. Turn plots provide good information about makeup, they SHALL NOT BE SUBSTITUTED FOR DIRECT VISUAL OBSERVATION OF THE CONNECTION DURING ASSEMBLY. There is no second chance to watch field assembly of a connection. Torque vs. Turn plots can always be viewed for verification purposes once a makeup is finished. When available, torque vs. turn plots shall finish with a clearly defined spike as shown in the graphic above. The general character of torque vs. turn plots for good makeups will become evident after the first ten (10) makeups (again, more may be necessary due to rig and/or equipment-specific conditions). Any makeup that results in a plot that is “out-of-character”2 when compared with most plots from previous good makeups should be checked carefully. Torque vs. Time is not recommended unless it supplements the Torque vs. Turn Data. When using Torque vs. Turn monitoring equipment, GB recommends setting a reference torque value of 500 ft- lbs. or 10% of the minimum makeup torque (whichever is lower) to help normalize the turns-to-power-tight variability in the Tq-Tn graphs. Setting a reference torque normalizes field stab variability resulting in more consistency in the Tq-Tn data. Plot scales should be set so data spans at least 2/3 of the turns scale on each plot (15 turns will usually be sufficient at the start and can be reduced based on data from the first few joints). UNDER NO CIRCUMSTANCE SHOULD MAKEUP BE STARTED UNTIL THE MONITORING SYSTEM IS READY TO RECORD DATA. 6. Occasionally the mill side of a GB Connection may turn during field makeup. When observed, the makeup should continue without stopping per this procedure. It may be helpful to scribe a vertical line across the coupling-pipe 2 An “out-of-character” plot may initiate with a high torque, show significantly steeper slope from the start of makeup, wide torque undulations as makeup progresses, no clearly defined spike, insufficient/inconsistent turns, etc. DELTA TORQUE (TQ): 10% ≤ SHOULDER TQ ≤ 50% SHOULDER TQ SPIKE Running Procedure for Casing with GB Drilling with Casing Connections February 13, 2024 Rev. 15 Page 7 of 9 interface to aid estimation of mill side turning if it is observed with some frequency. The amount of mill side turn should be carefully observed and estimated. If the mill side turns less than ½ turn and all other aspects of the makeup are good, the connection is acceptable. If the mill side turns more than ½ turn, troubleshooting should be initiated. Pay particular attention to amount and distribution of thread compound, vertical alignment, weight of joint, hooked end on pipe, and other possible factors that may contribute to possible high torque during field makeup. Counting turns can help to estimate if coupling will need to be stopped to avoid over rotation. It should be noted that mill side turning during field makeup occurs occasionally and should not be concerning. Frequent or persistent mill side turning is a symptom that needs troubleshooting and appropriate corrective action. 7. A double wrap of the pick-up sling should be used when raising casing into the derrick when lifting subs, single joint, side-door, or slip elevators are not being used. 8. Higher torque may be needed to achieve proper connection position when threadlock compounds are applied. User is advised to carefully follow the manufacturer’s instructions with respect to mixing, application, temperature, and time. Torque ranges with threadlock compounds cannot be estimated due to many variables including but not limited to temperature, time, connection tolerances, and surface finish. In these cases, carefully monitor makeup to be sure shouldering occurs. The only exception to proper positioning is with float equipment (float shoe and float collar) that will be assembled with a threadlocking compound. In this case, makeup close to the base of API Triangle Stamp is considered satisfactory. 9. Manual and automated dump valves can overshoot the established Running Torque due to several factors. Slightly overshooting the Running Torque is not cause for concern as long as the final “dump” torque is not excessive, and the equipment used is generally consistent joint-to-joint. Overshooting the Running Torque with a final makeup speed greater than 10 RPMs is risky and potentially harmful to the connection as discussed below. 10. Attached is a “Worksheet for determining GB Connections Running Torque at the beginning of a Casing Run” for use at the start of any casing run using GB Connections. GB recommends that this worksheet be filled out and maintained with the casing run records. MAKEUP SPEED To reiterate: Use of high gear at no more than 40 RPMs is permissible once proper starting thread engagement has occurred. THE FINAL TWO (2) FULL TURNS, AT A MINIMUM, SHALL BE COMPLETED IN LOW GEAR AT LESS THAN 10 RPMS. Be sure that the final 2 turns occur after the tong speed has slowed completely to less than 10 RPMs. Making up connections at RPM exceeding those listed above may result in unsatisfactory connection performance downhole. Risks associated with excessive makeup RPMs are common for any connection with internal pin nose engagement. High speed makeup can: 1. Impart an unnecessary impulse load at nose contact. Certain materials are more susceptible to cracking under sudden or instantaneously applied loads. 2. Inhibit efficient movement of and trap thread compound under high pressure causing additional and unquantifiable high hoop stresses in the connection. 3. Result in significant overshoot of established dump torque value due to equipment latency between signal and equipment shut down resulting in higher but unknown actual final torque value. Excessive overshoot can result in pin nose yielding. PROCEDURE SUMMARY 1. Remove coupling protectors after casing is set in V-Door and apply fresh thread compound to coupling threads. Running Procedure for Casing with GB Drilling with Casing Connections February 13, 2024 Rev. 15 Page 8 of 9 2. Raise joint in derrick, remove pin protectors, and apply fresh thread compound to pin threads and pin nose. 3. Carefully stab pin into coupling and makeup to pin nose engagement. Try to stop makeup without exceeding the Maximum MU Torque (shown on GB Connections Performance Property Sheets). Carefully watch for and note the Shoulder Torque. 4. Record Shoulder Torque and Final Torque values, and position relative to API Triangle Stamp for first ten (10) connections, more if necessary due to run/rig-specific conditions. 5. The Running Torque is (a) the Minimum MU Torque shown on the GB Connections Performance Property Sheet or (b) the maximum torque required for shoulder engagement + 20% Delta Torque determined from the first 10 makeups, whichever is higher. Use the attached Worksheet to record this data and determine the Running Torque. 6. Make up the rest of the string at the Running Torque determined in the previous step verifying each connection has shouldered with between 10% and 50% Delta Torque. Small incremental adjustments to the established Running Torque (500 to 1,000 ft-lbs) are advised if delta torques routinely fall short of the 10% requirement or routinely exceed the 50% requirement. NOTES: • This procedure summary is not a substitute for the comprehensive procedure provided above and does not apply to threadlock connections. DO’s and DONT’s 1. DO check vertical alignment. 2. DO apply thread compound to all pin and coupling threads, pin nose and coupling shoulder area. 3. DO establish the Running Torque in accordance with GB Procedures. 4. DO make adjustments to Running Torque if indicated by inconsistent makeups during the casing run. 5. DO check every makeup for a clear indication of shouldering with a minimum Delta Torque ≥ 10% of the Shoulder Torque. 6. DO reject any coupling that is not properly made up after two (2) attempts. 7. DO carefully stab pins into coupling (use a stabbing guide for casing smaller than 9 5/8” OD). 8. DO finish the makeup with at least two (2) full turns in low gear at 10 RPMs or less. 9. DO make up every connection continuously to pin nose engagement without stopping. 10. DO make note of anything that occurs with any connection makeup such as backup grips slipped, connection inspected and remade, etc. 11. Do check out every connection that appears out of character relative to the population. An example would be a connection that is completed with significantly fewer turns than most others. Check the triangle stamp and record position and take corrective action if needed. 12. DO add torque to any connection that appears to achieve pin nose engagement but not 10% delta torque. Running Procedure for Casing with GB Drilling with Casing Connections February 13, 2024 Rev. 15 Page 9 of 9 13. DO adjust the Running Torque up or down in increments to achieve consistent Delta Torque between 10% and 50%. 14. Do make note of any anomaly during any connection makeup, such as backups slipped, mill side turned, etc. 15. DO minimize the weight on the connection, i.e. weight neutral, during break out as much as possible to minimize thread galling. 16. Do Reduce RPM’s on any join racking around in the derrick during make up. Erratic joint movement wile rotating may contribute or cause thread galling during make-up. 17. DO NOT over dope. 18. DO NOT exceed the Maximum MU Torque as shown on the GB Connections Performance Property Sheets during assembly. 19. DO NOT make up any misaligned connection. 20. DO NOT exceed 40 RPMs in high gear and 10 RPMs in low gear for the final two (2) full turns. 21. DO NOT remove pin thread protectors until pipe is hanging in the derrick. 22. DO NOT ever back a connection up a couple of turns and remake. Any connection requiring this type of attention SHALL be broken out completely, cleaned, visually inspected, and if OK, re-doped and remade. 23. DO NOT hesitate to contact GB Connections with questions before and during any casing run. RECOMMENDED EQUIPMENT • Stabbing Guide • Mustache Brush • Torque vs. Turn Monitoring Equipment or Dump Valve OD (in) Weight (ppf) Grade Min MU Torque (ft-lbs) Max MU Torque (ft-lbs) Max Operating Torque (ft-lbs) Notes Joint No. Shoulder Torque (ft-lbs) Final Torque (ft-lbs) Triangle Stamp Position Sketch ( ) Required 1 Required 2 Required 3 Required 4 Required 5 Required 6 Required 7 Required 8 Required 9 Required 10 Optional 11 Optional 12 Optional 13 Optional 14 Optional 15 - GB Connections For Techincal Information, contact: 950 Threadneedle, Suite 130 Gene Mannella Qing Lu Houston TX 77079 gmannella@gbconnections.com qlu@gbconnections.com Toll Free: 1-888-245-3848 Main: 713-465-3585 Jordan Kies Fax: 713-984-1529 jkies@gbconnections.com Cell 713-562-0050 Worksheet for determining GB Connection Running Torque at the beginning of a Casing Run Ignore joints that are assembled with threadlock compounds. See "Addendum Procedure for GB Connections Assembled with Threadlocking Compounds" available at www.gbconnections.com. 5. Stab the pin carefully into the coupling of the joint hanging in the rotary table. A stabbing guide is recommended to protect the pin nose and leading thread from physical damage that may contribute to thread galling. Make up each connection until shoulder engagement plus Delta Torque. Record the Shoulder Torque observed for the first 10 joints (excluding threadlocked accessory joints). The Running Torque is (a) the Minimum MU Torque shown on the GB Connections Performance Property Sheets or (b) the Maximum Shoulder Torque recorded from the first 10 makeups + 20%, whichever is higher (rounded to the next highest 500 ft-lbs.) Delta Torque should be between 10% and 50% of the Shoulder Torque. Running Torque shall not exceed the Maximum MU Torque. When making up the initial joints for establishing the Running Torque carefully watch the torque gauge for the Shoulder Torque and try to manually shut down the tongs before reaching Maximum MU Torque shown on the GB Connections Performance Property Sheets. Alternately, the dump valve should be set to 80% of the Maximum MU Torque during this initial process. 6. After the first 10 makeups (more if necessary due to conditions at the time of the run), use the “Running Torque" established in Step 5 for the remainder of the string. A dump valve is strongly recommended to stop makeup once the established Running Torque is achieved. Pertinent Excerpt from GB Running Procedure Wide variations in Shoulder Torque during the first ten (10) joints suggest other issues requiring attention such as poor alignment, improper amount and distribution of thread compound, etc. Refer to 2nd paragraph of GB Running Procedure for possible contributing factors to aid troubleshooting. The Maximum Operating Torque is NOT the Maximum Makeup Torque and is NOT a sustainable rotating torque. Operating at the Maximum Operating Torque for any length of time will likely damage the connection. Comment See GBC Performance Property Sheet See GBC Performance Property Sheet See GBC Performance Property Sheet See GBC Performance Property Sheet Casing Data See GBC Performance Property Sheet Max. Shoulder Torque A Max. Shoulder Torque + 20% Optional joints should be added if there is wide variability in shoulder torques recorded during the initial 10 joints. Judgement should be used to determine if more than 10 joints are needed for the purpose of establishing the Running Torque and, if so, how many more should be added. B Min. Makeup Torque (from GB Conn. Data Sheet) Running Torque (ft-lbs)A or B, whichever is greater. Rev. 15 (02/13/2024) 10 AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of Hilcorp Alaska, LLC's ) request for hearing with the Alaska Oil and ) Gas Conservation Commission regarding Other ) Order 222, Granite Pointe Field, Failure to ) Notify of Changes to Approved Permit, ) Granite Pointe State 17586 011. ) ) Docket number: OTH-25-037 PUBLIC HEARING Anchorage, Alaska December 2, 2025 10:00 o'clock a.m. BEFORE: Jessie Chmielowski, Commissioner Greg Wilson, Commissioner AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Commissioner Wilson 03 3 Testimony by Mr. Rixse 08 4 Testimony by Mr. McLaughlin 27 5 Testimony by Mr. Howard 34 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 3 1 P R O C E E D I N G S 2 (On record - 10:00 a.m.) 3 COMMISSIONER WILSON: Good morning. I will 4 call this hearing to order. This is a public hearing 5 on docket number OTH-25-037. By letter received 6 October 14th, 2025, Hilcorp Alaska, LLC, filed a 7 request for hearing with the Alaska Oil and Gas 8 Conservation Commission regarding other order 222, 9 Granite Pointe field, failure to notify of changes to 10 approved permit, Granite Pointe state 17586 011. This 11 hearing is being held on the morning of December 2nd, 12 2025, at 10:00 a.m. The location is the Alaska Oil and 13 Gas Conservation Commission office at 333 West 7th 14 Avenue, Anchorage, Alaska. I am Commissioner Greg 15 Wilson. 16 If any persons here need special accommodations 17 to participate in these proceedings please contact 18 Samantha Coldiron and she will do her best to 19 accommodate you. 20 We are convened today to reschedule this 21 hearing because Commissioner Chmielowski is serving 22 jury duty and a quorum is not present. Accordingly the 23 AOGCC will continue this hearing at 2:30 p.m. today, 24 December 2nd. 25 The time is 10:01 a.m. and this hearing is now AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 4 1 recessed until 2:30 p.m. today. 2 (Off record - 10:01 a.m.) 3 (On record - 2:30 p.m.) 4 COMMISSIONER WILSON: Well, good afternoon. I 5 will now reconvene this continued hearing. It is 6 approximately 2:30 p.m. on Tuesday, December 2nd, 2025. 7 This is public hearing on docket number OTH-25-037. By 8 letter received October 14th, 2025, Hilcorp Alaska, LLC 9 filed a request for hearing with the Alaska Oil and Gas 10 Conservation Commission regarding other order 222, 11 Granite Pointe field, failure to notify of changes to 12 approved permit, Granite Pointe state 17586 011. I am 13 Commissioner Greg Wilson and with me is Commissioner 14 Jessie Chmielowski. Today's hearing is being held in 15 person and via Microsoft Teams. The in person location 16 is the Alaska Oil and Gas Conservation Commission 17 office at 333 West 7th Avenue, Anchorage, Alaska. 18 For those on Teams please be mindful of any 19 background noise and make sure you're muted when you're 20 not testifying or addressing the AOGCC. 21 If you require any special accommodation please 22 contact Samantha Coldiron. She can be reached at 907- 23 793-1223 or send her a message through the Microsoft 24 Teams chat icon and she will do her best to accommodate 25 you. AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 5 1 Samantha Coldiron will be recording the 2 hearing. Computer Matrix will be preparing the 3 transcript. Upon completion and preparation of the 4 transcript anyone desiring a copy will be able to 5 obtain it by contacting Computer Matrix. 6 This hearing is being held in accordance with 7 Alaska statute 44.62 and 20 AAC 25.540 of the Alaska 8 Administrative Code. 9 The notice of hearing was published on the 10 state of Alaska online notices website as well as the 11 AOGCC's website and was sent through the AOGCC email 12 listserv on October 14th, 2025. The AOGCC also 13 published the notice in the Anchorage Daily News on 14 October 19th, 2025. To date the AOGCC has received one 15 public comment on this matter from Steve McKeever. 16 This comment has been added to the docket file and sent 17 to Hilcorp for review. 18 Background. On October 14th, 2025, Hilcorp 19 Alaska, LLC filed a request for public hearing with the 20 AOGCC regarding other order 222, Granite Pointe field, 21 failure to notify of changes to approved permit, 22 Granite Pointe state 17586 011. Other order 222 was 23 issued to Hilcorp Alaska, LLC on October 3rd, 2025 24 following both a notice of proposed enforcement action 25 issued July 31st, 2025 and an informal review held AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 6 1 between AOGCC and Hilcorp Alaska, LLC on August 21st, 2 2025. Other order 222 was issued for failure to notify 3 of changes to an approved permit, Granite Pointe field, 4 Granite Pointe state 17586 011, permit to drill 225- 5 057. 6 The Commissioners will ask questions during 7 testimony. We may also take a recess to consult with 8 Staff to determine whether additional information or 9 clarifying questions are necessary. 10 Before we get to the presentation from Hilcorp 11 we think it would be helpful to describe the iterative 12 process and timeline that this issue has followed to 13 date. To do so we would like to invite Mel Rixse, 14 Senior Petroleum Engineer for the AOGCC to provide that 15 recap. Mr. Rixse is lead engineer regarding this 16 matter. 17 Mr. Rixse, you'll let us know when you're set 18 to go. 19 A (Witness complies) 20 COMMISSIONER WILSON: Okay. I'll swear you 21 in. Please raise your right hand and respond. 22 (Oath administered) 23 MR. RIXSE: (No audible response) 24 COMMISSIONER WILSON: Let the record reflect 25 the witness responded in the affirmative. AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 7 1 Do you wish to be recognized as an expert 2 witness? 3 MR. RIXSE: I do. 4 COMMISSIONER WILSON: Please identify your 5 field of expertise and credentials. 6 MR. RIXSE: I'm a Senior Petroleum Engineer at 7 the Oil and Gas Conservation Commission, I've worked 8 here for six and a half years. I'm a licensed 9 petroleum engineer in the state of Alaska. I hold a 10 bachelor of science degree in mechanical engineering 11 from Colorado State University and I've worked in the 12 upstream oil and gas industry for 42 years. 13 COMMISSIONER WILSON: Commissioner Chmielowski, 14 are you satisfied with the expertise and credentials as 15 presented? 16 COMMISSIONER CHMIELOWSKI: Yes, I have no 17 objections. 18 COMMISSIONER WILSON: You'll be recognized as 19 an expert in the field you identified. 20 Please remember to speak into the microphone. 21 Also reference your slides by number of title so that 22 somebody reading the public record can follow along. 23 You may begin your presentation. 24 MEL RIXSE 25 previously sworn, called as a witness on behalf of the AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 8 1 AOGCC, testified as follows on: 2 DIRECT EXAMINATION 3 MR. RIXSE: To slide number 1 and then number 4 2. My testimony addresses a violation of AOGCC 5 regulations related to construction of the Hilcorp 6 development well..... 7 COMMISSIONER WILSON: Just a moment, Mel. 8 MR. RIXSE: Okay. I'll start again. My 9 testimony addresses a violation of AOGCC regulations 10 related to the construction of the Hilcorp development 11 well permitted under the well name and number, Granite 12 Pointe State, 17586 space 011, drilled in July of 2025. 13 The sequence of events leading to the violation is as 14 follows. 15 The well was permitted by AOGCC on June 25th, 16 2025 with an approved permit to drill to install nine 17 and five-eights, 47 pound L80 surface casing. On July 18 7th, 2025, nine and five-eights, 40 pound L80 casing 19 was run and cemented in place according to the 10-407 20 submitted to AOGCC on November 25th, 2025. On July 21 8th, 2025, Hilcorp notified AOGCC that nine and five- 22 eights, 40 pound, L80 surface casing was run on well 23 BR11-86. Hilcorp was requesting a reduced casing 24 pressure test from 3,500 PSI to 3,000 PSI. After 25 clarifying emails between AOGCC and Hilcorp it was AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 9 1 determined that the referenced well, BR11-86 was the 2 permitted well, Granite Point State 17586 011. After 3 reviewing the permitted program AOGCC determined that 4 Hilcorp had unilaterally substituted the approved nine 5 and five-eights, 47 pound -- just a second, casing with 6 nine and five-eights, 40 pound L80 casing, a lighter 7 casing with a larger internal diameter and lower burst 8 and collapse resistance than what had been authorized. 9 Under 20 AAC 25.507 an operator may not make a 10 substantive change to an approved program or activity 11 without prior AOGCC approval. 20 AAC 25.507(a) 12 additionally specifies the information that must be 13 submitted when requesting such a change. Any 14 modification requires the operator to document the 15 well's current condition and provide the provide the 16 proposed change for AOGCC review and approval. 17 Slide 3. 18 COMMISSIONER WILSON: Just a moment, we seem to 19 have lost the feed. 20 (Pause) 21 MR. RIXSE: I'm on slide 3 in my presentation. 22 I'll continue. Under article 1, the drilling 23 regulations of AOGCC, a provision that applied change 24 -- to changes made to an approved program is 20 AAC 25 25.015(e)(2). This regulation states submit and obtain AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 10 1 the Commission's approval of an application for sundry 2 approvals, form 10-403, if the change is not covered by 3 (1) of this subsection. The application for sundry 4 approvals must set out the approved program, the 5 current condition of the well and the proposed changes. 6 Slide 4. AOGCC form 10-401 is required to be 7 submitted with every drilling permit application. It 8 provides AOGCC with substantive technical information 9 needed to evaluate the proposed construction of the 10 well. In section 18 which details the casing program 11 Hilcorp reported the following for the planned surface 12 casing. Nine and five-eights, 47 pound, L80 with DW/C 13 connections. DW/C is a proprietary connection owned by 14 Bam USA Corporation and stands for drilling with casing 15 coupled. This section of the form is one of the 16 primary sources AOGCC relies on to determine what 17 casing the operator intends to install in the well. 18 Slide 5. On August 21st Hilcorp attended an 19 informal review with AOGCC to discuss AOGCC's notice of 20 planned enforcement. During that meeting Hilcorp 21 asserted that they notified AOGCC of their option to 22 run a different surface casing weight by including 23 47/40 on page 6 of their drilling program. Hilcorp's 24 position was that this notation constituted approval to 25 run nine and five-eights, 40 pound per foot casing AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 11 1 instead of the 47 pound per foot casing specified on 2 form 10-401 of their drilling permit application. It 3 is important to note however that all other information 4 provided by Hilcorp for the nine and five-eights 5 surface casing included engineering properties, grade 6 and connection type was based on exclusively on 47 7 pound casing. No engineering data or evaluation for 40 8 pound casing was provided anywhere in the application 9 materials. 10 Slide 6. Continuing through the approved 11 permit to drill AOGCC requires operators to submit a 12 planned wellbore schematic as part of the drilling 13 permit. In the schematic submitted for this well 14 Hilcorp stated that surface casing would be nine and 15 five-eights, 47 pound, L80 with DWC/C connection and 16 the nominal internal diameter shown corresponding to 47 17 pound per foot casing. For the record when a well 18 experiences problems the wellbore schematic is one of 19 the first documents engineers consult to understand the 20 overall planned wellbore construction. 21 Slide 7. Further in the approved permit to 22 drill Hilcorp notes that they will have available on 23 the rig floor a casing running safety joint with a 24 crossover from their drill pipe to the DWC/C connection 25 that will be on the nine and five-eights inch casing. AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 12 1 Although the well was on diverter while running surface 2 casing having the correct safety joint on the rig floor 3 for circulating and moving casing could be very 4 beneficial if operations incur problems. The permit 5 also highlights in bold the required drift diameter 6 which is essential to ensuring that the casing will 7 pass all equipment used during well construction and 8 any further maintenance activities. A drift too small 9 may easily drift the idea of the casing, but may mask 10 that the casing is too large for anchoring equipment in 11 the casing. For reference the drift diameter for nine 12 and five-eights, 40 pound per foot casing is 8.679. 13 The drift diameter for nine and five-eights, 47 pound 14 per foot casing is 8.525. Given these differences it 15 is reasonable to expect that Hilcorp would run the 16 correct drift for the casing we'd actually install. 17 Proper drift assurance is critical to confirm 18 that the wellbore tools are dimensionally compatible 19 including liner hangers, casing integrity test tools, 20 cement retainers and bridge plugs should remedial work 21 ever be required. Running a drift appropriate for the 22 approved casing weight is a fundamental step in 23 ensuring that all equipment can safely and reliably 24 pass through the casing and that slips in 25 (indiscernible) sized for the actual internal diameter AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 13 1 will pass and anchor. 2 Slide 8. This section pertain -- this slide 3 pertains to the nine and five-eights cementing program 4 included in the approved permit to drill. Larger 5 internal diameter casing than planned and different 6 shoe track lengths than described in the procedure 7 creates confusion. This discrepancy represents the 8 type of inconsistency that would prevent me, a licensed 9 professional engineer, from signing off on the permit 10 to drill until it is corrected. While shoe track 11 length can be modified without explicit AOGCC approval, 12 the drilling program should provided consistency in the 13 calculation methodology so personnel know how the 14 volumes were calculated. 15 Slide 9. AOGCC regulations require that casing 16 integrity tests be conducted to 50 percent of the 17 casing's rated burst pressure. For nine and five- 18 eights, 47 pound per foot, L80 casing the burst rating 19 is 6,870 PSI which results in required test pressure of 20 3,435 PSI. For nine and five-eights, 40 pound per 21 foot, L80 casing the burst rating 5,750 PSI resulting 22 in a required test pressure of 2,875 PSI. I first 23 became aware that the nine and five-eights, 40 pound 24 casing had been installed in this well when I received 25 a call requesting approval to use the lower test AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 14 1 pressure associated with the 40 pound per foot burst 2 rating. 3 Slide 10. The Hilcorp permit to drill 4 application also includes casing design factors. All 5 of the design factors submitted by Hilcorp covering 6 worst case tension, worst case collapse and worst case 7 burst were prepared on nine and five-eights, 47 pound 8 per foot, L80 surface casing. No information was 9 provided to AOGCC indicating that Hilcorp intended to 10 use, consider or model nine and five-eights, 40 pound, 11 L80 casing. In other words all engineering evaluations 12 supporting the permit were based solely on 47 pound per 13 foot casing that was approved and no casing design 14 performance information was ever submitted for the 40 15 pound casing actually run in the well. 16 Slide 11. Recently AOGCC received the as-built 17 information for this well in the 10-407 form required. 18 And it was submitted from Hilcorp. In that document 19 Hilcorp listed the nominal internal diameter of the 20 installed surface casing as 8.681 inches. Based on 21 standard dimensional specifications I believe this 22 value is incorrect. Notable for this well record for 23 posterity, the nominal internal diameter for nine and 24 five-eights, 40 pound per foot casing is 8.835 not 25 8.681 inches. 8.681 ID is a nominal ID amount for 47 AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 15 1 pound casing. 2 Slide 12. In summary all dimensions and 3 engineering data in the approved permit to drill 4 reflected a plan to install nine and five-eights, 47 5 pound, L80 surface casing. Substituting a different 6 casing weight with a larger internal diameter created 7 multiple points of potential misunderstanding and 8 operational risk including driftability and tool 9 compatibility, plugs, test packers, RTTS tools, liner 10 top packers and other equipment rely on casing ID and 11 wall thickness to ensure proper slip placement and 12 avoid casing damage. Notably on this well an RTTS was 13 required on this well following a failed casing 14 pressure test. 15 Incorrect displacement and cementing volumes. 16 Displacement volumes for cement to shoe track and 17 spacer volumes change with internal diameter and shoe 18 track length. Although wellbore lengths are always 19 incurring minor changes during drilling operations, 20 methodology for calculating volumes should remain 21 consistent. Incorrect calculation methodology can have 22 substantive negative outcomes. 23 Incorrect mechanical modeling. Pick up and 24 slack off weights, joint strength, tensile strength, 25 compression strength as well as casing test pressures AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 16 1 differ between 47 pound and 40 pound casing. 2 While nine and five-eights, 40 pound, L80 3 casing may well be an acceptable surface casing for the 4 conditions of this well, Hilcorp provided no technical 5 justification, operational parameters and procedures 6 for running a different casing than approved. Had 7 Hilcorp requested the substantive change to run 40 8 pound casing versus 47 pound casing to AOGCC through 9 the 10-403 sundry process and provided the relevant 10 parameters and procedures, those changes would be 11 properly reviewed, recorded and likely approved. 12 That's the end of my testimony. 13 COMMISSIONER WILSON: Thank you, Mr. Rixse. 14 Before asking Hilcorp to begin their 15 presentation, Commissioner Chmielowski, do you have any 16 questions? 17 COMMISSIONER CHMIELOWSKI: No, not at this 18 time. Thanks. 19 COMMISSIONER WILSON: So representatives from 20 Hilcorp are you ready to make your presentation? 21 UNIDENTIFIED VOICE: (Indiscernible - away from 22 microphone). 23 COMMISSIONER WILSON: Okay. Yeah. That -- 24 that's fine, right? 25 UNIDENTIFIED VOICE: Yeah. AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 17 1 COMMISSIONER WILSON: Like I said if you'll 2 state your name for the record. 3 MR. McLAUGHLIN: Sean McLaughlin, drilling 4 manager for Hilcorp Alaska. The NOV issued to Hilcorp 5 cites only a violation of 20 AAC 25.507, correct? 6 MR. RIXSE: I don't have that information in 7 front of me. I'd have to review the violation. 8 COMMISSIONER WILSON: There was discussion on 9 whether or not you needed to be sworn in for questions. 10 Probably not, but we will swear you in shortly so why 11 don't we go ahead and do that. Yeah. If you would 12 raise your right hand and respond. 13 (Oath administered) 14 MR. McLAUGHLIN: I do. 15 COMMISSIONER WILSON: So let the record reflect 16 that the witness responded in the affirmative. 17 Do you wish to be recognized as an expert 18 witness? 19 MR. McLAUGHLIN: I do. 20 COMMISSIONER WILSON: Please identify your 21 field of expertise and credentials. 22 MR. McLAUGHLIN: I request to be recognized as 23 an expert in the subject of drilling engineering and 24 operations. I have a BS in mechanical engineering from 25 the University of Alaska Fairbanks. That classwork AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 18 1 included courses such as mechanics of materials. I 2 have been planning, executing or managing drilling 3 operations in Alaska for the last 20 years. During 4 that time I was trained in casing design through the 5 Chevron Training Alliance. This training included both 6 theory and modeling. Other training classes included 7 tubing designs, completions and managing hole problems. 8 I was an engineering team lead at BP Alaska and I'm 9 currently the drilling manager for Hilcorp Alaska. 10 COMMISSIONER WILSON: Commissioner Chmielowski, 11 are you satisfied with the expertise and credentials as 12 presented? 13 COMMISSIONER CHMIELOWSKI: Yes, I have no 14 objections. 15 COMMISSIONER WILSON: Okay. Then you may 16 proceed. 17 MR. McLAUGHLIN: So in Mel's presentation he 18 referenced 25.015. So the question was the NOV issued 19 to Hilcorp cites only violation to 20 AAC 25.507, is 20 that correct? 21 I have the NOV here if you'd like to review it. 22 MR. RIXSE: I'd have to -- this is Mel Rixse. 23 I'd have to refer to the exact order, I don't have it 24 right in front of me. 25 MR. McLAUGHLIN: I can ask the question another AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 19 1 way. The NOV does not allege a violation to 20 AAC 2 25.015, correct? I'm referring to slide 3 in your 3 presentation. 4 MR. RIXSE: It may not be ref -- this is Mel 5 Rixse. It may not be referenced in exact order, but it 6 is my opinion that it's clear that there was a 7 substantive change to the drilling portion of this well 8 and a 10-403 should have been submitted for change to 9 approved program. 10 MR. McLAUGHLIN: The first time reference to 11 25.015 appears is in your presentation slides, correct? 12 MR. RIXSE: On slide 2 I referenced 25.507 and 13 on slide 3 I referenced 25.015 and there were 14 violations to both regulations. 15 MR. McLAUGHLIN: Hilcorp was never notified 16 that AOGCC was alleging violation to 25.015, correct, 17 it is not in the NOV or in order 222? 18 So the reliance today on 25.015 is outside of 19 the scope of the NOV, correct? 20 MR. RIXSE: I don't know the answer to that. 21 It -- well, in my opinion they're both -- there were 22 clear violations to both parts of our regulations. 23 That -- that's clear to me. 24 MR. McLAUGHLIN: You're not alleging the L -- 25 the 40 pound, L80, GBCD casing is unsafe, correct? AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 20 1 (No comments) 2 MR. McLAUGHLIN: The AOGCC did no engineering 3 analysis of the as-built casing, correct? 4 MR. RIXSE: No, I have not. 5 MR. McLAUGHLIN: The presentation contains no 6 triaxial, axial, burst or collapse calculations, 7 correct? 8 (No comments) 9 MR. McLAUGHLIN: There was no minimum design 10 limits listed in the drilling permit, correct? 11 MR. RIXSE: Would you rephrase that or repeat 12 it. 13 MR. McLAUGHLIN: There were no minimum drilling 14 design limits listed in the permit, correct? 15 (No comments) 16 MR. McLAUGHLIN: You have not reviewed any 17 analysis showing the 40 pound casing fails any safety 18 factor, correct? 19 MR. RIXSE: This is Mel Rixse again. No, I 20 have not. I only reviewed what was presented to me in 21 Hilcorp's permit to drill. 22 MR. McLAUGHLIN: And you are not alleging any 23 threat to public health, the environment or well 24 integrity, correct? 25 (No comments) AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 21 1 MR. McLAUGHLIN: And you're not alleging any 2 cement failure, lack of returns or integrity problems, 3 correct? 4 MR. RIXSE: I haven't -- the 407 just came in 5 recently. I've -- I think I saw a CBL which presented 6 that cement did return, yes. And we allowed for 7 perforations. 8 MR. McLAUGHLIN: Well, we're talking surface 9 casing so we did get cement to surface. So your cement 10 concerns are theoretical, not based on observed well 11 performance? 12 MR. RIXSE: No, I don't understand that 13 question. 14 MR. McLAUGHLIN: There was highlighted cement 15 concerns I believe on page -- slide 8. Those are 16 theoretical, there weren't any cement issues with the 17 well? 18 (No comments) 19 MR. McLAUGHLIN: The plug did bump, correct? 20 MR. RIXSE: I have -- I'd have to read the 21 record. I don't know. 22 MR. McLAUGHLIN: On slide 8 you stated the shoe 23 track volume calculation was incorrect due to an 24 incorrect shoe track length, correct? 25 (No comments) AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 22 1 MR. McLAUGHLIN: So you would be surprised to 2 learn that the shoe track assembly was 120 feet and the 3 shoe track was in fact 80 feet and the AOGCC 4 calculations that overwrote the Hilcorp calculations 5 were incorrect? 6 MR. RIXSE: Those calculations were for an 80 7 foot shoe track in the approved permit to drill. 8 MR. McLAUGHLIN: So you would be surprised to 9 learn that the shoe track assembly was 120 feet and the 10 shoe track length for calculations was 80 feet and the 11 program was correct? 12 MR. RIXSE: I don't see how the program -- 13 you're telling me the shoe track was 80 feet? 14 MR. McLAUGHLIN: Yes. It's in the tally. We 15 pick up 120..... 16 MR. RIXSE: Why did you reference 120 feet? 17 MR. McLAUGHLIN: Fair question. It says 120 18 foot shoe track assembly so the guys on the rig know 19 that they're going to pick up three joints at 120 feet. 20 The landing collar is at the bottom of the first full 21 joint leaving two full joints below the landing collar. 22 So the volumetric calculation for 80 feet in the shoe 23 track is correct. The blue verbiage in the program and 24 the Hilcorp calculations that were crossed out that was 25 wrong. AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 23 1 You can move on. Always..... 2 COMMISSIONER WILSON: If I can interject. 3 Just to make sure that you identify yourself for the 4 record as you switch back and forth so that it can be 5 sorted out for the transcript. 6 MR. RIXSE: This is Mel Rixse. Shoe track 7 lengths historically reference where the landing collar 8 lands and the volume of cement left in the shoe track. 9 If the landing collar is placed lower in the shoe track 10 that would be considered a 80 foot shoe track. 11 COMMISSIONER CHMIELOWSKI: Could -- can we move 12 on from this question. We're getting -- digressing 13 into cement volume, we're here to talk about change to 14 approved program. 15 MR. McLAUGHLIN: Thank you. Are you aware that 16 the cement volumes in the drilling permits are only 17 estimates and are subject to change? 18 MR. RIXSE: Of course. Yes. Mel Rixse and I 19 said that in my testimony that depths change. We're 20 well aware of that. 21 MR. McLAUGHLIN: AOGCC has previously approved 22 40 pound, L80 surface casing on other Cook Inlet wells, 23 correct? 24 MR. RIXSE: Yes, that -- Mel Rixse. Yes, we 25 have approved that provided the engineering AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 24 1 calculations are provided. 2 MR. McLAUGHLIN: Sean McLaughlin. Nothing in 3 the regulation prohibits 40 pound casing for this step, 4 correct? 5 MR. RIXSE: This is Mel Rixse. As long as the 6 engineering calculations are provided that support the 7 use of 40 pound casing as I said in the summary of my 8 testimony they will be approved. 9 MR. McLAUGHLIN: Sean McLaughlin. Do you agree 10 the casing test was performed for the original 11 permitted value? 12 MR. RIXSE: Mel Rixse. I think as I -- I think 13 there was a 10-403 if I remember right and but I do 14 believe yeah, you went to a higher value than what was 15 required for 40 pound casing. I think you took it up 16 to the value for a casing that wasn't run in the well 17 which was 47 pound casing. 18 COMMISSIONER CHMIELOWSKI: Mr. McLaughlin, you 19 have the information about what the pressure test was. 20 Are you going to state it and if it was the same? 21 MR. McLAUGHLIN: Sean McLaughlin. Do you agree 22 the larger drift casing is generally more desirable? 23 MR. RIXSE: Mel Rixse. No, I do not agree with 24 that. There are times when you need a stronger casing. 25 This was probably not that in -- it probably -- the AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 25 1 lighter pound casing might have been very adequate for 2 this well and would have been approved had proper 10- 3 403 and engineering calculations been submitted. 4 MR. McLAUGHLIN: On slide 12, the summary 5 slide, you listed several things that could mislead. 6 Were all plugs and packers rated for both 40 pound and 7 47 pound casing? 8 COMMISSIONER CHMIELOWSKI: Again this is an 9 answer I think you have the -- this is a question you 10 have the answer to, Mr. McLaughlin, I'm not sure of the 11 relevance of it. 12 MR. McLAUGHLIN: So in slide 12 the -- he 13 highlighted a whole lot of things that could mislead. 14 And I think the point was is that you have different 15 tools for 40 and 47 pound and that's not the case. 16 COMMISSIONER CHMIELOWSKI: Right. 17 MR. McLAUGHLIN: So for example the RTTS that 18 Mel highlighted, it's rates for both 47 and 40 pound. 19 COMMISSIONER CHMIELOWSKI: Right. But we're 20 getting into the details after the fact. The 21 enforcement action was for a change to approved 22 program. So how does -- how do the tools fit into that 23 argument? 24 MR. McLAUGHLIN: That the change was very 25 minor, that it was a nonsubstantive change, that 47 and AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 26 1 40 pound are very similar and that the tools are 2 similar. That spacer volume changes were not required, 3 that pick up and slack off weight changes were not 4 required. 5 COMMISSIONER CHMIELOWSKI: Would you like to 6 move into your..... 7 MR. McLAUGHLIN: I'll move on. 8 COMMISSIONER CHMIELOWSKI: .....and do that 9 part, if you're asking questions that you have the 10 answers to I'm not sure of the relevance. 11 MR. McLAUGHLIN: Two more questions, please. 12 Are you able to tell us the AOGCC definition for 13 substantive change? 14 MR. RIXSE: Mel Rixse. That's a complex 15 question. I've got 42 years of engineering experience, 16 I planned a number of wells. The industry I think 17 knows when a change is substantive. In this case I 18 think it was quite apparent on the 10-401 form where 19 very substantive information is included and described 20 that that would be considered substantive information. 21 That's a very broad, general question. I can't give a 22 specific answer, but I -- there could be instances 23 where failures would occur and it would become very 24 evident that the information we were requesting was 25 substantive although there were no sub -- there were no AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 27 1 failures on this well. 2 MR. McLAUGHLIN: Do you agree -- Sean 3 McLaughlin. Do you agree there are minor changes and 4 substantive changes? 5 MR. RIXSE: Mel Rixse. There's always minor 6 changes. There's always minor changes to wells. We 7 handle them on a daily basis. This was not a minor 8 change, this was substantive. 9 MR. McLAUGHLIN: No further questions. 10 (Pause - technical issues) 11 COMMISSIONER WILSON: We'll take a short 12 recess. 13 (Off record) 14 (On record) 15 COMMISSIONER WILSON: All right. Apologies for 16 the technical glitches. For the record the hearing 17 this morning for the continuance went off without a 18 glitch. 19 SEAN McLAUGHLIN 20 previously sworn, called as a witness on behalf of 21 Hilcorp Alaska, testified as follows on: 22 DIRECT EXAMINATION 23 MR. McLAUGHLIN: Sean McLaughlin. Sorry for 24 the issue on that, I misunderstood. 25 I'd like to start out with the timeline and the AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 28 1 position. I'll go over the timeline real briefly. Mel 2 covered it real well. The only thing to add is that 3 Hilcorp on July 8th requested a reduced pressure test 4 of 3,000 pounds which was the 50 percent of the 40 5 pound burst, however it was still substantially greater 6 than the 2,000 PSI required for well integrity. On 7 August 21st we held an informal review, Hilcorp and 8 AOGCC at the AOGCC office. I'll be speaking to that 9 meeting. And then on October 3rd AOGCC issued other 10 order 222, I'll be speaking to that as well. 11 Hilcorp's position is different than what was 12 stated..... 13 COMMISSIONER WILSON: Excuse me, Mr. 14 McLaughlin. Before you go on for the timeline could 15 you state for the record the date that you ran the 40 16 pound? 17 MR. McLAUGHLIN: The run was finished on July 18 8th, 2025. It was started on July 7th. 19 COMMISSIONER WILSON: Thank you. 20 MR. McLAUGHLIN: Hilcorp's position is 21 different than what was mentioned earlier. It's not 22 that there was a slash in the program. Hilcorp 23 respectfully disagrees that running nine and five- 24 eights, 40 pound, L80 casing in Bruce 11-86 constitute 25 a -- constituted a violation of 20 AAC 25.507. The AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 29 1 basis for disagreement is engineering equivalency and 2 that the substitution was not a substantive change. 3 The substitution did not materially alter the well 4 design, safety margins or barrier integrity. There is 5 no change to scope or risk. 6 Next slide. The change to 40 pound casing was 7 not a substantive change because it met the regulatory 8 standard. 20 AAC 25.507 prohibits substantive changes 9 without prior AOGCC approval. A substantive change is 10 not defined in statute or regulation. AOGCC has 11 historically applied it to modification that materially 12 affect wellbore integrity, barrier performance or 13 compliance with casing design requirements. Running 40 14 pound casing did not alter or infringe on casing design 15 requirements. In this presentation you'll hear that 16 engineering is used to explain why casing substitution 17 is -- this casing substitution is a nonsubstantive 18 change. 19 AOGCC has not issued clear guidance defining 20 substantive change for casing substitutions. Applying 21 it here represents a new interpretation rather than a 22 consistent practice. 23 Slide 4. The change to 40 pound casing was not 24 a substantive change because safety margins and well 25 integrity were unaffected. The maximum anticipated AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 30 1 surface pressure for this well was 1,839 PSI. The 40 2 pound casing was tested to the original permitted 3 pressure of 3,500 PSI. This is well above the 2,000 4 PSI required for well integrity. There was no change 5 to the well barrier verification. As such the 6 substitution was not a substantive change, 40 pound, 7 L80, burst, collapse, tensile ratings remain well above 8 design requirements. Engineering will be used to 9 demonstrate the substitution was a nonsubstantive 10 change. Testimony from Altus Well Experts will be 11 heard in the next few slides. The change did not alter 12 the well barrier envelope or cement program. The 13 cement volume was not altered due to the casing weight 14 change. The displacement volume was calculated after 15 the casing run as per SOP. The drilling program is not 16 used for final cement or displacement volumes per SOP. 17 A change from 47 to 40 pound casing would be a 18 substantive change where casing weight is a design 19 criteria for permafrost subsidence damage resistance on 20 the North Slope. 21 Hilcorp agrees with the AOGCC that long, 22 complicated casing runs may reach the threshold of a 23 substantive change. That is not the case for this 24 short, nontechnical casing run. 25 COMMISSIONER CHMIELOWSKI: Mr. McLaughlin, for AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 31 1 someone who's not as familiar with casing, there are 2 things that change when an operator switches between 3 casings, correct, there are physical attributes that 4 change so the -- just to list out some of them, that 5 the inner diameter changes. In this case the outer 6 diameter did not change, but it could change depending 7 on the circumstance. The rate of burst pressure, rate 8 of collapse pressure and the rated ideal strength all 9 change, right, with different types of casing, 10 generally make up torque, possibly the safety joint 11 connections might change if you have a different 12 connection type and the cement displacement volumes 13 change as you mentioned. Those are all items that 14 changed, correct? 15 MR. McLAUGHLIN: Yes. 16 COMMISSIONER CHMIELOWSKI: Thank you. 17 MR. McLAUGHLIN: At this time I'd like to turn 18 it over to John Howard, PE, president of Altus Well 19 Experts. He'll be sworn in as an expert witness if you 20 guys agree, he'll give you his credentials. He's going 21 to speak on the design validation and the design 22 limits. 23 And do we have John online. 24 MR. HOWARD: You do. My name is John Howard. 25 I'm requesting to be recognized as an expert in the AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 32 1 area of casing analysis. I have a petroleum 2 engineering degree from the University of Oklahoma. I 3 joined Tenneco as an offshore drilling engineer and 4 company man working jack-up, semis and platforms 5 starting in 1983. In 1988 I joined Intertech. 6 Intertech is the company that developed WellCat and 7 Stress Check. We sold to Halliburton in 1996, they own 8 it. And after the noncompetes had expired we created 9 Altus Well Experts with the former president, with the 10 BP guy that we hired, that created our Aberdeen office. 11 We provided Altus Well Experts primarily in the area of 12 training, mentoring, consulting, writing casing design 13 guides which we wrote the casing design guide for 14 ConocoPhillips. I've taught casing in over 30 15 countries and six continents. 16 I've been very active in the SPE, I've been a 17 45 year active member of the SPE. This last year I 18 served as the 2025 SPE ATCE technical vice chair and 19 also on the SPE executive committee. I am the 2026 SPE 20 ATCE technical program chair. I was also recently 21 selected as a distinguished lecturer in the area of 22 casing design for the SPE for the 206/2027 season. I 23 have coauthored and presented numerous papers in the 24 area of casing and tubing analysis including SPE paper 25 number 206183 which is the history, evolution and AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 33 1 future of casing design theory and practice. Also the 2 SPE 215126 with Bessie on casing design for shut-in 3 after worst case discharge. SPE 217732 in the area of 4 development of the fit for purpose CO2 injection model 5 for casing and tubing analysis for CCUS and SPE 227868 6 on well life cycle engineering which will be featured 7 on Thursday in the SPE webinar seminar which I'm one of 8 the panelists. 9 So I respectfully request that I be recognized 10 as an expert in the area of casing design analysis. 11 COMMISSIONER WILSON: Thank you, Mr. Howard. 12 Before we complete that process I'm going to back up 13 one step. You may have participated with Mr. 14 McLaughlin when we swore him in, but I would like to 15 swear you in before we recognize you as an expert 16 witness. 17 MR. HOWARD: Correct. Thank you. 18 COMMISSIONER WILSON: So will you please raise 19 your right hand and respond. 20 (Oath administered) 21 MR. HOWARD: I do so affirm. And my camera's 22 not on, but my right hand is raised. 23 COMMISSIONER WILSON: I believe you. Let the 24 record reflect the witness responded in the 25 affirmative. AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 34 1 And then with those credentials, Commissioner 2 Chmielowski, are you satisfied with the expertise and 3 credentials as presented? 4 COMMISSIONER CHMIELOWSKI: Yes, thank you. 5 COMMISSIONER WILSON: Okay. You may proceed, 6 Mr. Howard. Thank you. 7 JOHN HOWARD 8 having been first duly sworn under oath, called as a 9 witness on behalf of Hilcorp Alaska, testified as 10 follows on: 11 DIRECT EXAMINATION 12 MR. HOWARD: Slide 6. This is part of the 13 analysis. We were contacted by Hilcorp in particular 14 to take a look at the nine and five-eights casing 15 program that they used on the 47 and then compare that 16 back to a 40 pound. We first imported the data into 17 the WellCat package which is a little bit more robust 18 than the Stress Check analysis and I can go into a 19 very, very long analysis about both of those programs. 20 I was involved in the development and the rollout of 21 those before we sold to Halliburton and we wanted to 22 specifically take a look at if there are any 23 significant issues along with the reduction of the pipe 24 weight. I was assisted in that analysis with Ollie -- 25 from Ollie Coker. Ollie was heavily involved with AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 35 1 ConocoPhillips for many years and then when he retired 2 from ConocoPhillips he joined us as a principle advisor 3 and I was the supervisor on this particular project. 4 Slide 8. Our approach was to take the analysis 5 provided for the nine and five-eights, 47 pound, verify 6 first that that was done correctly through an analysis 7 of a QA of that particular file from Stress Check. We 8 verified that it was done and well within the design 9 limits of the criteria which they had established. We 10 then did the analysis again using a nine and five- 11 eights, 40 pound, L80 with the GBCD connectors and 12 found that the analysis even taking considerations, the 13 initial conditions and (indiscernible) was well within 14 the design guidelines. 15 The executive summary is that that the original 16 analysis of the nine and five-eights, 47, L80, was 17 consistent, the stresses fell well within the cline, 18 triaxial and uniaxial design which is the minimum 19 acceptable safety factors. And that our research also 20 went into the nine and five-eights, 40 pound, L80, and 21 as expected for this type of well which was not very 22 stringent on the nine and five-eights casing, it fell 23 well within the cline, triaxial and uniaxial safety 24 factor limits. 25 As I go to slide 11 you can see that this is AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 36 1 the combination of the uniaxial and the triaxial. In 2 the upper right-hand corner is what's called quadrant 3 1, the upper left-hand corner is quadrant 3, that is 4 the uniaxial, triaxial limit for burst. In the lower 5 section, lower left-hand section which would be 6 quadrant 3, that is the API collapse and in the right- 7 hand side of the lower section that is the biaxial 8 deration. So that is a uniaxial collapse that is a D 9 rated collapse for tension and you can see that all of 10 the nine and five-eights, 47 pound are well within 11 those limits. 12 Going to slide 12 you can see that the triaxial 13 safety factors are well above the criteria for that 14 particular scenario. 15 Slide 13. You can also see that the axial 16 safety factors -- is there a question, Robert? 17 COMMISSIONER WILSON: If I could interject for 18 just a moment? 19 MR. HOWARD: Yes. 20 COMMISSIONER WILSON: It's seems to me anyhow 21 that you're referencing slide numbers that are 22 consistent with what we have on the screen. 23 MR. HOWARD: Okay. It's referencing the slide 24 number from what I'm advancing on the screen which says 25 13 of 28. The title -- I'll refer back to the title to AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 37 1 make sure, it is slide 8 from the original Altus 2 presentation which on my screen here shows up as slide 3 13 of 28 with the title axial safety factors, nine and 4 five-eights, 47 pound, L80, which shows that for all of 5 the load cases they -- they calculated minimal 6 acceptable safety factors are well above the design 7 criteria. Going forward to..... 8 COMMISSIONER WILSON: Mr. Howard. 9 MR. HOWARD: Yes. 10 COMMISSIONER WILSON: I do see the issue so as 11 long as you give the title to each slide that you're 12 referencing, but yeah, there are two different slide 13 numbers on the presentation. I think you're only 14 seeing one, but we -- it's being presented as kind of a 15 double page. 16 MR. HOWARD: Very good. So the next slide that 17 I will advance to, in the lower right-hand corner of 18 the slide it should say it's slide number 9 which on my 19 screen is showing 14 of 28. The title is the API burst 20 safety factor, nine and five-eights, 47 pound and you 21 can see that it is a very robust design, no issues. 22 Advancing to the next slide, the API collapse 23 safety factor for the 47 pound. Again well above all 24 of the minimum criteria. 25 And as I advance through to the stress pots for AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 38 1 the as-built, we're now in what is shown as the Altus 2 slide 12 which is the triaxial stress analysis for the 3 nine and five-eights, 40 pound and you can see that is 4 well within the design criteria where there are really 5 no -- this is a very robust design, you could probably 6 even go to a lighter weight than the nine and five- 7 eights, 40 pound. We did not evaluate any of that, we 8 just ran the nine and five-eights, 40, L80 and that was 9 more than sufficient. 10 Advancing to the next slide which is shown on 11 the lower right-hand side as slide 13, the title the 12 triaxial safety factor, nine and five-eights, 40 pound. 13 You can see that those -- no issues whatsoever for this 14 particular scenario. Not that there wouldn't be on 15 other wells, but not for this particular well. 16 Advancing to the next slide, we're at the axial 17 safety factor, nine and five-eights, 40 pound, L80. 18 And again no issues. On the lower right-hand side that 19 says slide from Altus Well Experts. 20 Advancing to the next we're in the ax -- API 21 burst safety factor, nine and five-eights, 40 pound and 22 you can see the comment, loads not shown had safety 23 factors greater than 10. So no issues particular with 24 that one. 25 Advancing to the next, slide 16, the API AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 39 1 collapse safety factors, the nine and five-eights, 40 2 pound. Again no particular issues which we would not 3 expect on this type of well. 4 Advancing to the next slide, that's the 5 conclusions. And the summary results is that we looked 6 at just the nine and five-eights casing comparing the 7 47 pound to the 40 pound and found that they were all 8 very much robust without significant issue and all 9 well, within the design criteria for that well. 10 That concludes my summary of results. 11 COMMISSIONER WILSON: Thank you, Mr. Howard. 12 COMMISSIONER CHMIELOWSKI: Mr. Howard, when was 13 this analysis run by your firm? 14 MR. HOWARD: Within the last couple weeks. 15 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 16 MR. McLAUGHLIN: Sean McLaughlin. The change 17 to 40 pound casing was not a substantive change because 18 of operational interchangeability. 47 pound and 40 19 pound casings were both nine and five-eights OD, L80, 20 with semi-premium couplings. These couplings are 21 interchangeable. All packers and plugs used are 22 suitable for both 40 pound and 47 pound casing weights. 23 There's very little -- no operational change between 24 the two. There were no change to casing running tools 25 or well control barriers. There was no change to AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 40 1 handling equipment, slips or elevators. Hilcorp had 2 the option to utilize nine and five-eights, 47 pound 3 with buttress connection those this would have more 4 materially deviated from the approved design intent. 5 The 40 pound casing was the closest engineering 6 equivalent. We had a choice to because of an inventory 7 problem run a nine and five-eights, 47 pound, buttress 8 connection or nine and five-eights, 40 pound, semi- 9 premium connection. If we ran the 47 pound buttress 10 connection we'd likely not be sitting here today. 11 COMMISSIONER CHMIELOWSKI: Mr. McLaughlin, 12 excuse me. When did Hilcorp become aware of the 13 inventory shortage and decide to change the casing? 14 MR. McLAUGHLIN: At the start of the well. 15 COMMISSIONER CHMIELOWSKI: At spud? 16 MR. McLAUGHLIN: Yes. 17 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 18 MR. McLAUGHLIN: Running 47 pound buttress 19 would have been a nonsubstantive change and it was 20 available. Running 40 pound, GBCD was a better choice 21 due to torque resistance and the well objectives. 22 Next slide. The change to 40 pound casing was 23 not a substantive change because of historical field 24 precedent. Bruce platform wells have historically run 25 nine and five-eights, 40 pound, L80 casing to greater AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 41 1 depths without incident. Some examples are well 5-87. 2 This is a 1989 gas well where nine and five-eights, 40 3 pound, was run to 7,557 feet. On well 3-87, a 1984, 4 nine and five-eights, 40 pound, was run to 4,676 feet. 5 Next slide. On August 21st, 2025, myself and 6 Wyatt Rivard from Hilcorp and Mel Rixse and Jim Regg 7 from AOGCC conducted an informal review. At that time 8 AOGCC acknowledged the distinction between minor and 9 substantive changes. Hilcorp asserted a key factor for 10 determination of whether a change is minor or 11 substantive should be based on increase in risk. There 12 was no agreement from the AOGCC. The industry standard 13 for evaluating and communicating risk is an eight by 14 eight matrix that uses severity and likelihood. The 15 casing substitution caused no change in the risk 16 profile. 17 Hilcorp inquired whether a change from a 18 premium connection to an API connection would be 19 considered substantive. AOGCC generally acknowledged 20 that such a change would likely be considered a minor, 21 nonsubstantive change. This is consistent with 22 historical practice. Hilcorp countered that from a 23 risk perspective such a change is more substantive than 24 a change in casing weight under these circumstances. 25 Hilcorp also inquired whether a change to a heavier AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 42 1 weight casing would be considered substantive. AOGCC's 2 response suggested that going to a heavier weight 3 casing would likely be considered a minor, 4 nonsubstantive change. This is the mindset that bigger 5 and heavier is better. That is not based on 6 engineering. Hilcorp countered that from a risk 7 perspective heavier weight casing could be more 8 substantive due to decreased hole size which impacts 9 hit tolerance. AOGCC acknowledged that Hilcorp's 10 casing selection was based on inventory and that both 11 sizes were sufficient for the well loads from an 12 engineering perspective. 13 Next slide. After the informal review other 14 order 222 was published. This included two AOGCC 15 findings and conclusions. The first was that Hilcorp 16 acknowledged that the approved permit to drill 17 identified nine and five-eights, 47 pound casing was to 18 be run based on the 10-401 form. This is correct. The 19 second finding was that Hilcorp must request approval 20 to utilize a casing weight that is different from the 21 casing weight identified in the 10-401 application. 22 Not once in the findings or conclusion was substantive 23 change addressed. Nonsubstantive changes are allowed 24 under 20 AAC 25.507. Hilcorp's response to the other 25 order 222 is that the AOGCC position does not factor in AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 43 1 engineering or risk in determining whether a change is 2 considered substantive. Hilcorp agrees that if it had 3 changed to a thinner walled casing that resulted in 4 greater material risk to integrity. Such a change 5 would be considered substantive and approval would be 6 required under 20 AAC 25.507. 7 A change is not substantive simply because it 8 is different from the original information included in 9 the permit to drill form 10-401. Minor changes and 10 deviations occur frequently without issue. Threads 11 listed in the 10-401 form are changed without approval. 12 The depth and cement volumes in the 10-401 form are 13 changed on just about every well. The 10-401 is simply 14 a mid point when drilling a well. The operator should 15 be expected to keep the same risk and scope profile as 16 programmed however minor changes are to be expected and 17 are addressed in the regulations under 25.507. 18 Next slide In conclusion the substitution was 19 a nonsubstantive change. There was no change to scope 20 or risk. Operations were not impacted. Minor changes 21 are allowed under regulation 25.507. Any changes 22 associated with a change in casing weight were in fact 23 minor. No safety or regulatory integrity was 24 compromised. The 40 pound casing was well within 25 design limits as demonstrated by Mr. Howard. The AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 44 1 casing was tested per the original permitted value. 2 There was no change to the operating emblem. Hilcorp 3 requests withdrawal of the NOV. 4 That's all I have. 5 COMMISSIONER WILSON: Commissioner Chmielowski, 6 do you have any questions? 7 COMMISSIONER CHMIELOWSKI: Not at this time. 8 Maybe after a recess. 9 COMMISSIONER WILSON: Okay. So we will take a 10 20 minute recess to confer with Staff. 11 COMMISSIONER CHMIELOWSKI: Sure. So the time 12 is 3:52. What time should we be back on the record? 13 COMMISSIONER WILSON: 4:12. 14 COMMISSIONER CHMIELOWSKI: 4:12. Okay. We get 15 back at 4:12. 16 (Off record - 3:52 p.m.) 17 (On record - 4:12 p.m.) 18 COMMISSIONER WILSON: It is now 4:12. We will 19 resume the hearing. 20 Commissioner Chmielowski, do you have any 21 further questions. 22 COMMISSIONER CHMIELOWSKI: Yes, I just have one 23 more question. 24 Mr. McLaughlin, was the nine and five-eights 25 inch casing rotated after it was run in the hole? AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 45 1 MR. McLAUGHLIN: Yes, it was. If -- if I can 2 refer to my notes I..... 3 COMMISSIONER CHMIELOWSKI: Yeah. 4 MR. McLAUGHLIN: .....I can tell you exactly 5 how. 6 COMMISSIONER CHMIELOWSKI: Sure. 7 MR. McLAUGHLIN: So the nine and five-eights 8 casing had a reamer shoe on the bottom which means it 9 was set up for rotation. The connections were set up 10 for rotation, that's why we went with the semi-premium 11 connections. We ran it with a casing running tool, the 12 blonc casing running tool, so we could rotate. In 13 these surface casing runs getting casing to bottom is 14 -- can be difficult with the -- the little angle inch 15 so we wanted the ability to rotate. And so that's a 16 big design objective for us. 17 It was rotated at 15 RPM on bottom. It wasn't 18 needed to be rotated to get to bottom, but once we -- 19 we ran the string into depth we -- we reciprocated and 20 rotated. We landed the hanger, we pumped cement and 21 then we reciprocated during the cement job. So it was 22 just rotated off bottom, it wasn't required to work 23 past any ledges or drilling. 24 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 25 That's all I have. AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 46 1 COMMISSIONER WILSON: And now I'd like to offer 2 to any member of the public the opportunity to testify 3 or provide comments. 4 Is there anyone in the room that would like to 5 testify. 6 (No comments) 7 COMMISSIONER WILSON: Is there anyone on Teams 8 that would like to testify. On Teams the code to 9 unmute is star six. If anyone has technical 10 difficulties Samantha Coldiron can be reached at 907- 11 793-1223 or you can call the AOGCC main number at 907- 12 279-1433. So we will pause 60 seconds to allow people 13 time to unmute. 14 (No comments) 15 COMMISSIONER WILSON: We paused for 60 seconds, 16 but hearing no other business the time is 4:16, the 17 hearing is now adjourned. 18 (Off record - 4:16 p.m.) 19 (END OF REQUESTED PORTION) 20 21 22 23 24 25 AOGCC 12/2/2025 ITMO: HILCORP ALASKA Docket No. OTH-25-037 Computer Matrix, LLC Phone: 907-227-5312 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 47 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 47 are a true, 4 accurate, and complete transcript of proceedings in 5 Docket number: OTH-25-037, transcribed under my 6 direction from a copy of an electronic sound recording 7 to the best of our knowledge and ability. 8 9 10 DATE SALENA A. HILE, (Transcriber) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Alaska Oil and Gas Conservation Commission •Mel Rixse – Senior Petroleum Engineer at AOGCC •42 years of Industry Experience •Licensed Petroleum Engineer in State of Alaska •Bachelors of Science Degree in Mechanical Engineering from Colorado State University -1982 AOGCC Staff Testimony 1 Alaska Oil and Gas Conservation Commission •The Permit-to-Drill approved by AOGCC on June 25, 2025, included installation of 9-5/8“ 47# L-80 secondary surface casing. •Hilcorp notified AOGCC on July 8, 2025, that the well was being constructed with 9-5/8" 40# L-80 casing so they were requesting to reduce the upcoming casing test pressure to a lower pressure of 3000 psi. (Per regulation 50% of burst.) •After review of the permitted well , AOGCC determined that Hilcorp had unilaterally chosen to run 9-5/8" 40# L-8O surface casing, a lighter casing with a larger internal diameter and lower burst and collapse resistance, than what was permitted. •Per 20 AAC 25.507 an operator may not undertake a substantive change to an approved program or activity without AOGCC approval. 20 AAC 25.507(a) further describes the information that must be submitted to AOGCC. To make a change, the well's current condition and proposed change must be provided to AOGCC for review and approval. Basis for Finding the Violation of Noncompliance on Development Well - Granite Pt St 17586 011 Drilled in July 2025 2 Alaska Oil and Gas Conservation Commission 20 AAC 25.015. Changes to a program in a permit to drill (b) To change a program approved in a Permit to Drill or to change information under 20 AAC 25.005(c) after drilling operations start, the operator shall (1) submit and obtain the commission's approval of a new application for a Permit to Drill if the proposed bottom-hole location or the proposed location of an objective formation is changed by more than 500 feet laterally or vertically, or if the change requires a spacing exception under 20 AAC 25.055; or (2) submit and obtain the commission's approval of an Application for Sundry Approvals (Form 10-403) if the change is not covered by (1) of this subsection; the Application for Sundry Approvals must set out the approved program, the current condition of the well, and the proposed changes; in cases where prompt approval is needed, oral approval may be requested from the commission; if oral approval is obtained, the name of the representative of the commission who provided oral approval and the date of the approval must be included on the Application for Sundry Approvals, which must be submitted within three days for final approval by the commission. 3 Alaska Oil and Gas Conservation Commission Granite Point St 17586 011 Approved Permit to Drill (10-401) 4 Alaska Oil and Gas Conservation Commission Hilcorp Justification 5 Alaska Oil and Gas Conservation Commission Wellbore Schematic 6 Alaska Oil and Gas Conservation Commission 9-5/8” Casing Running 7 Alaska Oil and Gas Conservation Commission 9-5/8” Cementing Shoe track Mixed instructions and inconsistent calculations for important volume calculations during cementing. Note that calculations made on 47# casing not 40# and compounded by an 80’ shoe track length which is counter to 120’ in the procedure. 8 Alaska Oil and Gas Conservation Commission Casing test 50% of Burst per Regulation 9 Alaska Oil and Gas Conservation Commission Casing Design Information Performed by Hilcorp 10 Alaska Oil and Gas Conservation Commission 10-407 As-Built Completion Schematic 9-5/8” 40# casing continues to state the wrong nominal ID 11 Alaska Oil and Gas Conservation Commission Summary •All dimensions for surface casing in approved Permit to Drill reference 9-5/8” 47# L-80 and could mislead on: •Driftability and configuration of plugs, test packers, liner top packers etc. (RTTS run because of failed casing test. ) •Displacement volumes for cement volume in shoe track •Spacer volumes change •Pickup and slack off weights •Casing test pressures •If allowed in surface casings why not allow in much longer strings where hole volumes might be critical for well control or conditions where casing design factors are approaching limits? •9-5/8” 40# L-80 casing could have likely been approved with 10-403 with by providing clear communication regarding casing running, cementing, casing load resistance, and schematics. •Changes to casing drift, casing make-up torque, critical cementing volumes become ambiguous if not clearly communicated to AOGCC, rig crews, and service suppliers. 12 OTH-25-037AOGCC Public Hearing December 2, 2025 22222 Introduction Timeline and Position Hilcorp respectfully disagrees that running 9-5/8" 40# L-80 casing in BR 11-86 constituted a violation of 20 AAC 25.507. Basis for disagreement: ‒Engineering Equivalency / Not a Substantive Change –The substitution did not materially alter the well design, safety margins, or barrier integrity. Position Timeline May 28, 2025 – PTD package signed/submitted by Hilcorp (Sean McLaughlin). June 20, 2025 – AOGCC approves PTD 225-057 for Granite Pt St 17586 011 (BR 86-11). June 28, 2025 (approx.) – Planned spud date shown on the approved PTD form. July 8, 2025 – Hilcorp requests a reduced pressure test (3,000 psi). AOGCC commented that 9-5/8" 40# L-80 was run in the well (initially referenced as BR 11-86 (225-057). July 8, 2025 – Hilcorp submits a 10-403 request to change the approved program in connection with the pressure test. July 11, 2025 – Verbal approval reported for the 10-403 request. July 11, 2025 – Casing pressure test performed. July 18, 2025 – AOGCC requests withdrawal of the 10-403. July 31, 2025 – AOGCC issues Notice of Proposed Enforcement (Docket OTH-25-037). August 13, 2025 – Hilcorp requests informal review. August 21, 2025 – Informal review held at AOGCC offices. October 3, 2025 – AOGCC issues Other Order 222. October 10, 2025 – Hilcorp requests hearing pursuant to 20 AAC 25.540. October 14, 2025 – AOGCC schedules public hearing December 2, 2025. 33333 Change to 40# Casing Was Not a Substantive Change Regulatory Standard 20 AAC 25.507 prohibits “substantive changes” without prior AOGCC approval. “Substantive change” is not defined in statute or regulation; AOGCC has historically applied it to modifications that materially affect wellbore integrity, barrier performance, or compliance with casing design requirements. AOGCC has not issued clear guidance defining “substantive change” for casing substitutions. Applying it here represents a new interpretation rather than consistent practice. 44444 Change to 40# Casing Was Not a Substantive Change Safety Margins & Well Integrity Unaffected MASP = 1,839 psi. 40# L-80 burst/collapse/tensile ratings remain well above design requirements 40# was tested to the original permitted pressure (3,500 psi) The change did not alter the well barrier envelope or cement program Note: Change from 47# to 40# would be a substantive change where casing weight is a design criteria for permafrost subsidence damage resistance on the North Slope 55555 Change to 40# Casing Was Not a Substantive Change Expert Witness Assessment John A. Howard, P.E. ‒President, Altus Well Experts, Inc Design Validation Charts showing design limits 66666 Change to 40# Casing Was Not a Substantive Change Operational Interchangeability 47# and 40# are both 9-5/8", L-80, with premium couplings; couplings are interchangeable No change to casing running tools or well control barriers Note: Hilcorp had the option to utilize 9-5/8” 47# BTC though this would have more materially deviated from the approved design intent (i.e. the #40 was the closest engineering equivalent) 77777 Change to 40# Casing Was Not a Substantive Change Historical Field Precedent Bruce Platform wells have historically run 9-5/8" 40# L-80 casing to greater depths without incident Examples: ‒5-87 (1989 Gas well) 9-5/8” 40# run to 7,557’ ‒3-87 (1984) 9-5/8” 40# run to 4,676’ 88888 Hilcorp Notes from AOGCC Informal Review August 21, 2025 ‒Sean McLaughlin and Wyatt Rivard from Hilcorp and Mel Rixse and Jim Regg from AOGCC conduct informal review AOGCC acknowledged a distinction between minor and substantive changes ‒Hilcorp asserted the key factor for determination of whether a change is minor or substantive should be based on increase in risk. ‒Hilcorp inquired whether a change from a premium connection to an API connection would be considered substantive •AOGCC generally acknowledged that such change would likely be considered a minor “non-substantive” change •Hilcorp countered that from a risk perspective, such a change is more substantive than a change in casing weight under these circumstances. ‒Hilcorp inquired whether a change to a heavier weight casing would be considered substantive •AOGCC response suggested going to a heavier weight casing would likely be considered a minor “non-substantive” change •Hilcorp countered that from a risk perspective, heavier weight casing could be more substantive due to decreased hole size (which impacts kick tolerance). •AOGCC acknowledged that Hilcorp’s casing selection was based on inventory and that both sizes were sufficient for the well loads from an engineering perspective. 99999 Other Order 222 AOGCC Findings and Conclusions: ‒Hilcorp acknowledged that the approved PTD 225-057 identified 9-5/8” 47# casing was to be run based on the 10-401 form ‒Hilcorp must request approval to utilize a casing weight that is different from the casing weight identified in the 10-401 application Hilcorp Response ‒AOGCC position does not factor in risk in determining whether a change is considered substantive ‒Hilcorp agrees that if it had changed to a thinner walled casing that resulted in a greater material risk to integrity, such change would be considered “substantive” and approval would be required under 20 AAC 25.507 ‒A change is not “substantive” simply because it’s different from the original information included in a PTD form10-401. Minor changes and deviations occur frequently without issue 1010101010 Conclusion The substitution was a non-substantive change. No safety or regulatory integrity was compromised. Hilcorp requests withdrawal of the NOV. BR 11-86 Surface Casing: Design Change Stress Assessment For Hilcorp Alaska November 2025 © Altus Well Experts, Inc.© Altus Well Experts, Inc. BR 11-86 Surface Casing Review: Project Scope •9-5/8” Surface Casing program change from 47# DWC/C to 40# GB CD •Well data import and review in Landmark WELLCAT 5000.1.17 •Assess any significant design risk due to reduction in pipe weight •Client Engineer: Sean McLaughlin, Drilling Manager, Hilcorp Alaska LLC •Altus Consulting Engineer: Olli Coker, M.S. Petr. Eng. –Engineering Advisor, MPD, Geothermal, Casing Design –Principal Engineer, Altus Well Experts Inc. (15 years) –Principal Engineer, ConocoPhillips Global Wells Technology (29 years) •Altus Supervisor: John A. Howard, P.E. –President, Altus Well Experts, Inc. –Phone: +1.713.858.5040 jhoward@altuswellexperts.com 11/30/2025 2 © Altus Well Experts, Inc.© Altus Well Experts, Inc. Design Verification Approach •The Client’s original analysis for using 9-5/8” 47# L-80 casing with DWC/C connections was verified with no errors. •An independent study of the as-built well with an analysis using 9- 5/8” 40# L-80 casing with GB CD connections was conducted using WellCat for thermal and stress analysis. •As-built input data from the client was verified by comparison to API and manufacturer sources and was imported into the program. •The analysis approach added temperature deration, as-cemented initial conditions, conservative design safety factors, and additional checks of stress for both 3000psi and 3500psi pressure tests. 11/30/2025 3 © Altus Well Experts, Inc.© Altus Well Experts, Inc. Executive Summary of Key Results •The Client’s original analysis for using 9-5/8” 47# L-80 casing with DWC/C connections produced stresses that fell well within the client triaxial and uniaxial safety factor limits. •The Altus independent analysis for using 9-5/8” 40# L-80 casing with GB CD connections produced stresses that fell well within the client triaxial and uniaxial safety factor limits. •In addition, it is noted that the manufacturer of the GB CD connection on the 40# pipe claims compression (and therefor bending) strength higher than the claimed rating for the DWC/C connection on the 47# pipe. 11/30/2025 4 © Altus Well Experts, Inc.© Altus Well Experts, Inc. Stress Plots for the As-Designed Surface Casing 11/30/2025 5 © Altus Well Experts, Inc.© Altus Well Experts, Inc. Triaxial Stress 9-5/8” 47# L-80 DWC/C Casing 11/30/2025 6 © Altus Well Experts, Inc.© Altus Well Experts, Inc. Triaxial Safety Factors 9-5/8” 47# L-80 DWC/C Casing 11/30/2025 7 Loads not shown had safety factors greater than 10 © Altus Well Experts, Inc.© Altus Well Experts, Inc. Axial Safety Factors 9-5/8” 47# L-80 DWC/C Casing 11/30/2025 8 Loads not shown had safety factors greater than 10 © Altus Well Experts, Inc.© Altus Well Experts, Inc. API Burst Safety Factors 9-5/8” 47# L-80 DWC/C Casing 11/30/2025 9 Loads not shown had safety factors greater than 10 © Altus Well Experts, Inc.© Altus Well Experts, Inc. API Collapse Safety Factors 9-5/8” 47# L-80 DWC/C Casing 11/30/2025 10 Loads not shown had safety factors greater than 10 © Altus Well Experts, Inc.© Altus Well Experts, Inc. Stress Plots for the As-Built Surface Casing 11/30/2025 11 © Altus Well Experts, Inc.© Altus Well Experts, Inc. Triaxial Stress 9-5/8” 40# L-80 GB CD Casing 11/30/2025 12 © Altus Well Experts, Inc.© Altus Well Experts, Inc. Triaxial Safety Factors 9-5/8” 40# L-80 GR CD Casing 11/30/2025 13 © Altus Well Experts, Inc.© Altus Well Experts, Inc. Axial Safety Factors 9-5/8” 40# L-80 GR CD Casing 11/30/2025 14 © Altus Well Experts, Inc.© Altus Well Experts, Inc. API Burst Safety Factors 9-5/8” 40# L-80 GR CD Casing 11/30/2025 15 Loads not shown had safety factors greater than 10 © Altus Well Experts, Inc.© Altus Well Experts, Inc. API Collapse Safety Factors 9-5/8” 40# L-80 GR CD Casing 11/30/2025 16 Loads not shown had safety factors greater than 10 © Altus Well Experts, Inc.© Altus Well Experts, Inc. Conclusions 11/30/2025 17 © Altus Well Experts, Inc.© Altus Well Experts, Inc. Summary of Results •This analysis was limited to investigating the as-designed and as-built stresses for only the 9-5/8” Surface Casing. •For both the original analysis with 9-5/8” 47# L-80 casing and DWC/C Connections, and the as-built design with 9-5/8” 40# L-80 casing and GB CD Connections, all stresses were well within client design safety factors for the loads examined. •Dynamic Bending loads / fatigue issues were not examined due to the 40# connection compression ratings, low doglegs and a reported small number of rotations. 5/8/2014 18 9 Stephen O. McKeever 2459 Sprucewood Street Anchorage, Alaska 99508 mckeeversteve@gmail.com +1.907.351.5004 AOGCC 333 W. 7th Ave. Anchorage, Alaska 99501 Re: Comments on Docket #OTH-25-037, Other Order 222 Sent via email to Samantha Coldiron at samantha.coldiron@alaska.gov on November 28, 2025 To whom it may concern: With this letter I am providing comments regarding the above docket in which operator Hillcorp Alaska was found to be in violation of 20 AAC 25.507 “Change of an approved program”). As the Commission likely knows 20 AAC 25.015 (b) also addresses changes in a program in a permit to drill after drilling has commenced. It is clear to me from reading the publicly available documents that Hillcorp did not follow these regulations. The approved Permit to Drill, the only document that should be considered, clearly lists 47#casing as the weight of the casing that the Commission was permitting. Hillcorp’s failure to gain approval (likely an approval that would have been granted) to run the 40# casing before installing it is a “significant” change in the approved (i.e. permitted) program, and thus Hillcorp is in violation of the pertinent regulations. A reasonable person would have concluded that 47# casing was to be run due to the numerous places in the document “86-11 Drilling Program, Bruce Platform” that Hillcorp submitted with their application for the Permit to Drill that the specifications, performance properties, and volume calculations reference 47# casing, not 40# casing. Perhaps, though, a reviewer may have paused when seeing on page 4 of this document the “47/40” listed as the weight of the surface casing and then inquired of Hillcorp why the weight of the casing was so listed. Regarding the proposed reduction in the fine amount from $100,000 to $30,000, the AOGCC will have knowledge of Hillcorp’s past behavior and compliance with regard to the nine items the Commission is obligated to consider per AS 31.05.150(g). The only one of those items I can comment on is 31.05.150(g)(5): “the benefits derived by the person committing the violation from the violation;” While it is likely that Hillcorp saved money by buying and running a lighter weight of casing (not only the purchase cost of the casing but also perhaps rig time and day rate expenses if the 47# casing was not readily available) but in all likely hood the Commission would have approved the change if Hillcorp had followed the regulation and notified the Commission in advance of running the casing. So Hillcorp likely did not gain any benefits from the violation of 20 AAC 25.507 and 20 AAC 25.015 (b). Signed, Stephen McKeever Anchorage, Alaska 8 From:Coldiron, Samantha J (OGC) To:"Hobie Temple" Cc:Denali Kemppel; Sean McLaughlin; Wyatt Rivard Subject:RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Date:Monday, November 24, 2025 3:12:00 PM Attachments:OTH-25-037 Public Hearing Notice, Hilcorp request for hearing Granite Pt St 17586 011.pdf Hobie – Please see my responses in red below. Thank you, Samantha Coldiron AOGCC Special Assistant (907) 793-1223 From: Hobie Temple <hobie.temple@hilcorp.com> Sent: Monday, November 24, 2025 1:36 PM To: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Cc: Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Thanks Samantha. We had a few additional questions regarding the procedure: 1. What is being covered in the 10 am hearing? We assume it’s largely procedural, though some additional details on what’s being covered will help us to determine whether we need to be present. Will the commissioners be present? Commissioner Wilson will start the hearing and then explain that Commissioner Chmielowski is at Jury Duty, and we will continue this hearing at 2:30pm December 2, 2025. Hilcorp does not need to be present at the 10am hearing. 2. Can you share beforehand what facts/conclusions Mel intends to cover? Will the scope go beyond the Notice of Enforcement and Order 222? Is the testimony being done in person? I will be sending a copy of the presentation by end of day on November 26, 2025. 3. Similarly, would we be able to review any materials/presentations/exhibits before the hearing? Yes, see above. 4. Will the testimony be limited to factual narration or will opinions also be presented? While I do not know what Mel will testify to yet, if he is qualified as an expert by the Commissioners, then he can give an opinion. Any opinion will be shared in advance in his slide deck. 5. Will we have an opportunity to respond to this testimony or ask questions to Mel at the hearing? Yes, Mel will testify first, and you will also have his slide deck in advance so Hilcorp can respond in its presentation. Typically, only the Commissioners can ask questions CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. of witnesses (20 AAC 25.540(c)(9)), however, in an enforcement hearing a party may ask questions of opposing witnesses pursuant to 20 AAC 25.540(e). 6. We are working on having an expert witness available at the hearing. What does the commission need beforehand to have this individual testify? Typically, in regular hearings expert witnesses do not need to be noticed in advance, however, under the specific procedures for enforcement hearings, 20 AAC 25.540(e) (2) requires expert witnesses to be noticed in advance. The Commission will waive that requirement for this hearing to avoid a continuance. However, please provide any info in advance when available. During the swear in process they can identify that they wish to be an expert witness, then provide their credentials on record. 7. Will there be a Teams or similar virtual invite to the hearing? The Teams information was provided in the Notice of Public Hearing that I sent to Hilcorp on October 14, 2025. I have attached the notice here too. If you want a certain individual added to the Teams invite just let me know their email address. Happy to discuss these over the phone if easier. Also, as a heads up, we have a slide deck that Sean will be walking through for the actual hearing and will ensure that is sent to you before the end of the day on the 26th. Thank you! Hobie D. HOBIE TEMPLE Associate General Counsel Hilcorp Alaska, LLC 3800 Centerpoint Drive, #1400 Anchorage, Alaska 99503 o: (907) 777-8350 | c: (336) 380-2936 | hobie.temple@hilcorp.com From: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Sent: Wednesday, November 19, 2025 3:18 PM To: Hobie Temple <hobie.temple@hilcorp.com> Cc: Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Yes, both Commissioners will be present. Jury duty is only during the morning half of the day, so they are both able to be there for an afternoon hearing. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Samantha Coldiron AOGCC Special Assistant (907) 793-1223 From: Hobie Temple <hobie.temple@hilcorp.com> Sent: Wednesday, November 19, 2025 3:17 PM To: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Cc: Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Also, just to clarify, will both commissioners be present at the December 2 hearing? D. HOBIE TEMPLE Associate General Counsel Hilcorp Alaska, LLC 3800 Centerpoint Drive, #1400 Anchorage, Alaska 99503 o: (907) 777-8350 | c: (336) 380-2936 | hobie.temple@hilcorp.com From: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Sent: Wednesday, November 19, 2025 3:03 PM To: Hobie Temple <hobie.temple@hilcorp.com> Cc: Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Hobie – We will continue this hearing at 2:30pm on December 2, 2025. Hilcorp representatives do not need to be in person for the 10am continuation but are welcome to be there if desired. Please have your presentation to me by November 26 close of business (AOGCC closes at 4:30pm). AOGCC Senior Petroleum Engineer Mel Rixse has knowledge of the relevant facts for this enforcement proceeding and is intending to testify at the hearing consistent with the facts and conclusions alleged in the Notice of Proposed Enforcement Action and Other Order 222. Regards, Samantha Coldiron AOGCC Special Assistant (907) 793-1223 From: Coldiron, Samantha J (OGC) Sent: Tuesday, November 18, 2025 2:21 PM To: 'Hobie Temple' <hobie.temple@hilcorp.com> Cc: Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Hobie - One of our Commissioners has been selected to serve on a jury which will go through the timeframe for the December 2 hearing. We will need to gavel in and reconvene this hearing to a different date, I am tentatively looking at 10am on January 6, 2026, or January 8, 2026. Does either one of those dates work for Hilcorp? Please let me know as soon as possible. Thank you, Samantha Coldiron AOGCC Special Assistant (907) 793-1223 From: Hobie Temple <hobie.temple@hilcorp.com> Sent: Tuesday, October 14, 2025 3:36 PM To: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Received, thank you. D. HOBIE TEMPLE Associate General Counsel Hilcorp Alaska, LLC 3800 Centerpoint Drive, #1400 Anchorage, Alaska 99503 o: (907) 777-8350 | c: (336) 380-2936 | hobie.temple@hilcorp.com From: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Sent: Tuesday, October 14, 2025 3:33 PM To: Hobie Temple <hobie.temple@hilcorp.com> Cc: jim.regg <jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Hobie, See attached. Please have Hilcorp’s presentation submitted by close of business November 26, 2025. Regards, Samantha Coldiron AOGCC Special Assistant (907) 793-1223 From: Hobie Temple <hobie.temple@hilcorp.com> Sent: Friday, October 10, 2025 6:04 PM To: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Cc: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Samantha, In response to Other Order 222 (OTH-25-037), Hilcorp would like to request a hearing pursuant to 20 AAC 25.540. Please see attached for a formal written request. Thank you, Hobie D. HOBIE TEMPLE Associate General Counsel Hilcorp Alaska, LLC 3800 Centerpoint Drive, #1400 Anchorage, Alaska 99503 o: (907) 777-8350 | c: (336) 380-2936 | hobie.temple@hilcorp.com From: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Sent: Friday, October 3, 2025 2:40 PM To: Hobie Temple <hobie.temple@hilcorp.com> Cc: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; jim.regg <jim.regg@alaska.gov>; Rixse, 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. Melvin G (OGC) <melvin.rixse@alaska.gov>; Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Please see attached. Regards, Samantha Coldiron AOGCC Special Assistant (907) 793-1223 From: Hobie Temple <hobie.temple@hilcorp.com> Sent: Wednesday, August 13, 2025 8:59 AM To: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Cc: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: Notice of Proposed EA Granite Pt St 17586 011 Samantha, Please find attached a response to the notice of proposed enforcement action (Docket # OTH-25- 037) requesting an informal review. Please let us know if you have any questions. Thank you, Hobie D. HOBIE TEMPLE Associate General Counsel Hilcorp Alaska, LLC 3800 Centerpoint Drive, #1400 Anchorage, Alaska 99503 o: (907) 777-8350 | c: (336) 380-2936 | hobie.temple@hilcorp.com 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 the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 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 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 responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 7 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: OTH-25-037 Other Order 222 Hilcorp Alaska, LLC (Hilcorp) requested a hearing regarding Other Order 222, Docket Number OTH-25-037. The Alaska Oil and Gas Conservation Commission (AOGCC) grants the request. A public hearing on the matter has been scheduled for December 2, 2025, at 10:00 a.m. The hearing, which may be changed to full virtual, if necessary, will be held in the AOGCC hearing room located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call-in information is (907) 202-7104 Conference ID: 967 251 769#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Samantha Coldiron at least two business days before the scheduled public hearing to request an invitation for the MS Teams. In addition, written comments regarding this matter may be submitted to the AOGCC at 333 West 7th Avenue, Anchorage, AK 99501, or samantha.coldiron@alaska.gov. Comments must be received no later than the conclusion of the December 2, 2025, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Coldiron at (907) 793-1223 no later than November 25, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner FOR Samantha Coldiron Digitally signed by Samantha Coldiron Date: 2025.10.14 15:17:05 -08'00' Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.10.14 15:26:31 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Public Hearing Notice (Hilcorp) Date:Tuesday, October 14, 2025 3:51:30 PM Attachments:OTH-25-037 Public Hearing Notice, Hilcorp request for hearing Granite Pt St 17586 011.pdf Hilcorp Alaska, LLC (Hilcorp) requested a hearing regarding Other Order 222, Docket Number OTH-25-037. The Alaska Oil and Gas Conservation Commission (AOGCC) grants the request. Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v Lisi Misa being first duly sworn on oath deposes and says that she is a representative of the An- chorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the afore- said place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on AFFIDAVIT OF PUBLICATION ______________________________________ Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES ______________________________________ 10/19/2025 and that such newspaper was regularly distrib- uted to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed________________________________ Subscribed and sworn to before me Account #: 100869 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501 Order #: W0055709 Cost: $209.61 Notice of Public HearingSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: OTH-25-037 Other Order 222 Hilcorp Alaska, LLC (Hilcorp) requested a hearing regarding Other Order 222, Docket Number OTH-25-037. The Alaska Oil and Gas Conservation Commission (AOGCC) grants the request. A public hearing on the matter has been scheduled for December 2, 2025, at 10:00 a.m. The hearing, which may be changed to full virtual, if necessary, will be held in the AOGCC hearing room located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call-in information is (907) 202-7104 Conference ID: 967 251 769#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Samantha Coldiron at least two business days before the scheduled public hearing to request an invitation for the MS Teams. In addition, written comments regarding this matter may be submitted to the AOGCC at 333 West 7th Avenue, Anchorage, AK 99501, or samantha.coldiron@alaska.gov. Comments must be received no later than the conclusion of the December 2, 2025, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Coldiron at (907) 793-1223 no later than November 25, 2025. Jessie L. Chmielowski Gregory C. WilsonCommissioner Commissioner Pub: Oct. 19, 2025 STATE OF ALASKA THIRD JUDICIAL DISTRICT ______________________________________2025-10-20 2026-08-04 Document Ref: VMZYI-3V2W8-QADVH-HNLN9 Page 5 of 24 6 By Samantha Coldiron at 8:24 am, Oct 14, 2025 5 From:Coldiron, Samantha J (OGC) To:"Hobie Temple" Cc:Denali Kemppel; Sean McLaughlin; Wyatt Rivard Subject:RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Date:Thursday, August 14, 2025 1:56:00 PM Thank you for confirming. I will send out a meeting invite to be held here at AOGCC offices. Samantha Coldiron AOGCC Special Assistant (907) 793-1223 From: Hobie Temple <hobie.temple@hilcorp.com> Sent: Thursday, August 14, 2025 1:42 PM To: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Cc: Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Samantha, No, for Hilcorp it will be Sean and Wyatt (cc’d) attending. I was helping to get the meeting organized but was not going to attend. Thanks, Hobie D. HOBIE TEMPLE Associate General Counsel Hilcorp Alaska, LLC 3800 Centerpoint Drive, #1400 Anchorage, Alaska 99503 o: (907) 777-8350 | c: (336) 380-2936 | hobie.temple@hilcorp.com From: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Sent: Thursday, August 14, 2025 1:36 PM To: Hobie Temple <hobie.temple@hilcorp.com> Cc: Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Hobie – To facilitate a productive and truly informal review, it has been both operators’ and the AOGCC’s historical practice to limit informal review meetings to only technical staff. Will Hilcorp attorneys also be attending this meeting? If so, I will also request our counsel to attend. Thank you, Samantha Coldiron AOGCC Special Assistant (907) 793-1223 From: Hobie Temple <hobie.temple@hilcorp.com> Sent: Thursday, August 14, 2025 10:58 AM To: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Cc: Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: RE: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Samantha, Appreciate you making time to meet. We are available at 1 PM August 21st. We are happy to host at Hilcorp’s offices or can go to AOGCC’s offices. Thank you, Hobie D. HOBIE TEMPLE Associate General Counsel Hilcorp Alaska, LLC 3800 Centerpoint Drive, #1400 Anchorage, Alaska 99503 o: (907) 777-8350 | c: (336) 380-2936 | hobie.temple@hilcorp.com From: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Sent: Wednesday, August 13, 2025 9:48 AM To: Hobie Temple <hobie.temple@hilcorp.com> 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. Cc: Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] RE: Notice of Proposed EA Granite Pt St 17586 011 Hobie – We have availability next Thursday, August 21, at 10am or 1pm. Please let me know which time works for Hilcorp. Thank you, Samantha Coldiron AOGCC Special Assistant (907) 793-1223 From: Hobie Temple <hobie.temple@hilcorp.com> Sent: Wednesday, August 13, 2025 8:59 AM To: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Cc: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Denali Kemppel <dkemppel@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: Notice of Proposed EA Granite Pt St 17586 011 Samantha, Please find attached a response to the notice of proposed enforcement action (Docket # OTH- 25-037) requesting an informal review. Please let us know if you have any questions. Thank you, Hobie D. HOBIE TEMPLE Associate General Counsel Hilcorp Alaska, LLC 3800 Centerpoint Drive, #1400 Anchorage, Alaska 99503 o: (907) 777-8350 | c: (336) 380-2936 | hobie.temple@hilcorp.com 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 the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 4 By Samantha Coldiron at 9:10 am, Aug 13, 2025 3 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 July 31, 2025 CERTIFIED MAIL – RETURN RECEIPT REQUESTED 7018 0680 0002 2052 9860 Mr. Dan Marlow Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Re: Docket Number: OTH-25-037 Failure to Notify of Changes to Approved Permit Granite Point Field; Granite Pt St 17586 011 (PTD 2250570) Dear Mr. Marlow: Pursuant to 20 AAC 25.535, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby notifies Hilcorp Alaska, LLC (Hilcorp) of a proposed enforcement action. Nature of the Apparent Violation or Noncompliance (20 AAC 25.535(b)(1)) Hilcorp has violated the provisions of 20 AAC 25.507 (“Change of an approved program”) while performing well construction operations at Granite Point Field Granite Pt St 17586 011. Basis for Finding the Violation or Noncompliance (20 AAC 25.535(b)(2)) Development well Granite Pt St 17586 011 was drilled in July 2025. The Permit-to-Drill approved by AOGCC on June 25, 2025, included installation of 9-5/8” 47# L-80 secondary surface casing. Hilcorp notified AOGCC on July 8, 2025, that a well identified as BR 11-86 had been run with 9- 5/8” 40# casing and was requesting to pressure test the casing to a reduced pressure of 3000 psi. At the time, AOGCC could not locate a well identified as BR 11-86 in its records. After requesting Hilcorp clarify the well name, it was determined that Hilcorp was referring to well Granite Pt St 17586 011 (PTD 225-057). After review of the permitted well referenced, AOGCC determined that Hilcorp had unilaterally chosen to run 9-5/8” 40# L-80 secondary surface casing, a lighter casing with a larger internal diameter and lower burst resistance, than what was permitted. Docket Number: OTH-25-037 Notice of Proposed Enforcement July 31, 2025 Page 2 of 3 Per 20 AAC 25.507 an operator may not undertake a substantive change to an approved program or activity without AOGCC approval. 20 AAC 25.507(a) further describes the information that must be submitted to AOGCC. To make a change, the well’s current condition and proposed change must be provided to AOGCC for review and approval. Proposed Action (20 AAC 25.535(b)(3)) For this violation, the AOGCC intends to impose a civil penalty on Hilcorp under AS 31.05.150 in the amount of $100,000.1 In addition, within fourteen days of receipt of this letter (next business day if the due date falls on a weekend), Hilcorp is requested to provide AOGCC with a written response describing the steps that will be taken to assure no reoccurrence of this compliance failure. Rights and Liabilities (20 AAC 25.535(b)(4)) Within 15 days after receipt of this notification – unless the AOGCC, in its discretion, grants an extension for good cause shown – Hilcorp may file with the AOGCC a written response that concurs in whole or in part with the proposed action described herein, requests informal review, or requests a hearing under 20 AAC 25.540. If a timely response is not filed, the proposed action will be deemed accepted by default. If informal review is requested, the AOGCC will provide Hilcorp an opportunity to submit documentary material and make a written or oral statement. If Hilcorp disagrees with the AOGCC’s proposed decision or order after that review, it may file a written request for a hearing within 10 days after the proposed decision or order is issued. If such a request is not filed within that 10-day period, the proposed decision or order will become final on the 11th day after it was issued. If such a request is timely filed, the AOGCC will hold its decision in abeyance and schedule a hearing. If Hilcorp does not concur in the proposed action described herein, and the AOGCC finds that Hilcorp violated a provision of AS 31.05, 20 AAC 25, or an AOGCC order, permit or other approval, then the AOGCC may take any action authorized by the applicable law including ordering one or more of the following: (i) corrective action; (ii) suspension or revocation of a permit or other approval; and (iii) imposition of penalties under AS 31.05.150. In taking action after an informal review or hearing, the AOGCC is not limited to ordering the proposed action described herein, as long as Hilcorp received reasonable notice and opportunity to be heard with respect to the AOGCC’s action. Any action described herein or taken after an informal review or hearing does not limit the action the AOGCC may take under AS 31.05.160. 1 AS 31.05.150(g) requires AOGCC to consider nine criteria in setting the amount of a civil penalty. Docket Number: OTH-25-037 Notice of Proposed Enforcement July 31, 2025 Page 3 of 3 Questions regarding this letter should be directed to Mel Rixse at 907-793-1231. Sincerely, Gregory C. Wilson Jessie /Chmielowski Commissioner Commissioner cc: Phoebe Brooks (AOGCC) Jim Regg (AOGCC) AOGCC Inspectors Mel Rixse (AOGCC) Aras Worthington, Hilcorp (aras.worthington@hilcorp.com) Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.31 09:15:14 -08'00' Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.31 09:25:44 -08'00' 2 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Sean McLaughlin To:Rixse, Melvin G (OGC) Cc:Cody Dinger; Regg, James B (OGC) Subject:RE: [EXTERNAL] RE: BR 11-86 (225-057) Date:Tuesday, July 8, 2025 1:22:37 PM Yes, the casing was run and is cemented. Changing the casing weight was NOT a significant change and well within my authority. I reached out to change the test pressure, which the AOGCC has indicated is a significant change. If not approved, I will test to 3500 psi as permitted. The casing is perfectly fine to test as permitted. A face to face is necessary to determine what constitutes a substantive change. I’m ready to meet at your earliest convenience. Regards, sean From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, July 8, 2025 1:09 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Cody Dinger <cdinger@hilcorp.com>; jim.regg <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] RE: BR 11-86 (225-057) Sean, From AOGCC inspectors is sounds like the 40# casing is already run and cemented. Is this correct? If so, AOGCC is evaluating how to proceed with Hilcorp’s unilateral decision to make this change without AOGCC notification and approval. I have no reason to meet face to face. 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). CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. cc. Jim Regg, Cody Dinger From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, July 8, 2025 12:55 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Cody Dinger <cdinger@hilcorp.com> Subject: Re: [EXTERNAL] RE: BR 11-86 (225-057) Mel, Hilcorp will submit a 10-403 as requested. However, I still don’t have a clear answer. Is a change from 9-5/8” 47# to 40# significant for this casing run. If so, I will request a face to face to discuss further. Regards, Sean On Jul 8, 2025, at 12:37 PM, Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> wrote: Sean, Changing casing grades and test pressures, especially long strings that are penetrating deeper hydrocarbon zones with BOPE are very significant. Please submit a 10-403. 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 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). Cc Cody Dinger From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, July 8, 2025 12:15 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Cody Dinger <cdinger@hilcorp.com> Subject: Re: [EXTERNAL] RE: BR 11-86 (225-057) Mel, Is changing the casing weight a significant change? I don’t believe it is. I could change the weight and keep the permitted pressure test value. Correct? Casing weight adjustments are fairly frequent. Changing the casing pressure test value seems to be a substantial change to the AOGCC. The reason I ask is 1) the threshold for substantial change varies by regulator and company. And 2) We regularly run heavier weight casing than required for the casing design. We are considering permitting a minimum casing weight and grade. Would an increased casing weight trigger a Change to Approved Program? The regulations are punitive for running higher quality casing than necessary for a well. Sean On Jul 8, 2025, at 11:41 AM, Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> wrote: Cody, Sean, I don’t have access to your internal system. For future approvals I can utilize the approved PTD number, but it is appreciated when the approved well name as described in the approved PTD is utilized also. In this case, it is “Granite Pt St 17586 011”. When numbers don’t match, I am compelled to understand the conflict. As per the 20 AAC 25.030. Casing and cementing. (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). For 9-5/8” 47# L-80 as described in the approved PTD <image002.png> <image003.png> The regulation calls for 50% of 6870 psi or 3435 psi. If Hilcorp is planning to run the casing described: 9-5/8” 40# GBCD was run on BR 11-86. I’d like to reduce the casing pressure test to 3000 psi. MASP – 1839 psi. 9-5/8# 40# Internal Yield 5,750 psi please submit a 10-403 with a request to change the approved program for AOGCC to review. 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). CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Cc. Sean McLaughlin From: Cody Dinger <cdinger@hilcorp.com> Sent: Tuesday, July 8, 2025 10:58 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] RE: BR 11-86 (225-057) Hi Mel, Internally we reference the well number (11) first and the abbreviated state ADL (86) second. Historically, that’s how they are setup, the reason for that is to keep them in numerical order in our filing system and Wellview. Attached screenshot of Wellview/File Drive well names for reference. <image001.png> <image006.png> From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, July 8, 2025 10:40 AM To: Cody Dinger <cdinger@hilcorp.com> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] RE: BR 11-86 (225-057) <image007.png> <image008.png> Cody, Is Hilcorp carrying this well as 11-86 or is it 86-11. AOGCC carries the well name as described in your approved permit to drill which I have as Granite Pt St 17586 011. 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. Sean From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, July 8, 2025 10:10 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: RE: [EXTERNAL] RE: BR 11-86 (225-057) Mel, The well will be BR 11-86 in our files, as has been the case for this field for the last 40 years. So, the well name is accurate to me. Inconsistencies like that is why we were asked to provide the PTD number, which I have done, and it is accurate. Speaking of accuracy, the returned PTD email from the AOGCC had the wrong well name. No need to copy Joe on these emails, Cody Dinger is the Regulatory Tech for Offshore. Is the change of casing test pressure approved? Is it a substantive change? I would think not but I can’t read minds or keep up with the inconsistencies and the constant change in regulation interpretation by the AGOCC. sean --------------------------------------------------- CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. <image009.png> ----------------------------------------------------------- <image010.png> From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, July 8, 2025 8:41 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Joseph Lastufka <joseph.lastufka@hilcorp.com> Subject: [EXTERNAL] RE: BR 11-86 (225-057) Sean, Is this Granit Point State 17586 011 (PTD 225-057)? I have done an extensive search for something in our database matching “BR 11-86” and find nothing. AOGCC always appreciates accurate information when a request is made. 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. Bryan McLellan, Joe Lastufka From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, July 8, 2025 7:23 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: BR 11-86 (225-057) 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, 9-5/8” 40# GBCD was run on BR 11-86. I’d like to reduce the casing pressure test to 3000 psi. MASP – 1839 psi. 9-5/8# 40# Internal Yield 5,750 psi Regards, sean Sean McLaughlin Hilcorp Alaska, LLC Drilling Manager Sean.McLaughlin@hilcorp.com Cell: 907-223-6784 The information contained in this email message is confidential and may be legally privileged and isintended only for the use of the individual or entity named above. If you are not an intended recipientor if you have received this message in error, you are hereby notified that any dissemination,distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, thenpromptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibilityof the recipient to ensure that the onward transmission, opening, or use of this message and anyattachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and isintended only for the use of the individual or entity named above. If you are not an intended recipientor if you have received this message in error, you are hereby notified that any dissemination,distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, thenpromptly 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 considersappropriate. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Sean McLaughlin To:Rixse, Melvin G (OGC) Cc:Cody Dinger Subject:Re: [EXTERNAL] RE: BR 11-86 (225-057) Date:Tuesday, July 8, 2025 12:55:08 PM Mel, Hilcorp will submit a 10-403 as requested. However, I still don’t have a clear answer. Is a change from 9-5/8” 47# to 40# significant for this casing run. If so, I will request a face to face to discuss further. Regards, Sean On Jul 8, 2025, at 12:37 PM, Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> wrote: Sean, Changing casing grades and test pressures, especially long strings that are penetrating deeper hydrocarbon zones with BOPE are very significant. Please submit a 10-403. 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 Cody Dinger From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, July 8, 2025 12:15 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Cody Dinger <cdinger@hilcorp.com> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Subject: Re: [EXTERNAL] RE: BR 11-86 (225-057) Mel, Is changing the casing weight a significant change? I don’t believe it is. I could change the weight and keep the permitted pressure test value. Correct? Casing weight adjustments are fairly frequent. Changing the casing pressure test value seems to be a substantial change to the AOGCC. The reason I ask is 1) the threshold for substantial change varies by regulator and company. And 2) We regularly run heavier weight casing than required for the casing design. We are considering permitting a minimum casing weight and grade. Would an increased casing weight trigger a Change to Approved Program? The regulations are punitive for running higher quality casing than necessary for a well. Sean On Jul 8, 2025, at 11:41 AM, Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> wrote: Cody, Sean, I don’t have access to your internal system. For future approvals I can utilize the approved PTD number, but it is appreciated when the approved well name as described in the approved PTD is utilized also. In this case, it is “Granite Pt St 17586 011”. When numbers don’t match, I am compelled to understand the conflict. As per the 20 AAC 25.030. Casing and cementing. (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). For 9-5/8” 47# L-80 as described in the approved PTD <image002.png> <image003.png> The regulation calls for 50% of 6870 psi or 3435 psi. If Hilcorp is planning to run the casing described: 9-5/8” 40# GBCD was run on BR 11-86. I’d like to reduce the casing pressure test to 3000 psi. MASP – 1839 psi. 9-5/8# 40# Internal Yield 5,750 psi please submit a 10-403 with a request to change the approved program for AOGCC to review. 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. Sean McLaughlin From: Cody Dinger <cdinger@hilcorp.com> Sent: Tuesday, July 8, 2025 10:58 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] RE: BR 11-86 (225-057) CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Hi Mel, Internally we reference the well number (11) first and the abbreviated state ADL (86) second. Historically, that’s how they are setup, the reason for that is to keep them in numerical order in our filing system and Wellview. Attached screenshot of Wellview/File Drive well names for reference. <image001.png> <image006.png> From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, July 8, 2025 10:40 AM To: Cody Dinger <cdinger@hilcorp.com> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] RE: BR 11-86 (225-057) <image007.png> <image008.png> Cody, Is Hilcorp carrying this well as 11-86 or is it 86-11. AOGCC carries the well name as described in your approved permit to drill which I have as Granite Pt St 17586 011. 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. Sean From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, July 8, 2025 10:10 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: RE: [EXTERNAL] RE: BR 11-86 (225-057) Mel, The well will be BR 11-86 in our files, as has been the case for this field for the last 40 years. So, the well name is accurate to me. Inconsistencies like that is why we were asked to provide the PTD number, which I have done, and it is accurate. Speaking of accuracy, the returned PTD email from the AOGCC had the wrong well name. No need to copy Joe on these emails, Cody Dinger is the Regulatory Tech for Offshore. Is the change of casing test pressure approved? Is it a substantive change? I would think not but I can’t read minds or keep up with the inconsistencies and the constant change in regulation interpretation by the AGOCC. sean --------------------------------------------------- <image009.png> ----------------------------------------------------------- <image010.png> From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, July 8, 2025 8:41 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> 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. Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Joseph Lastufka <joseph.lastufka@hilcorp.com> Subject: [EXTERNAL] RE: BR 11-86 (225-057) Sean, Is this Granit Point State 17586 011 (PTD 225-057)? I have done an extensive search for something in our database matching “BR 11-86” and find nothing. AOGCC always appreciates accurate information when a request is made. 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. Bryan McLellan, Joe Lastufka From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, July 8, 2025 7:23 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: BR 11-86 (225-057) Mel, 9-5/8” 40# GBCD was run on BR 11-86. I’d like to reduce the casing pressure test to 3000 psi. MASP – 1839 psi. 9-5/8# 40# Internal Yield 5,750 psi Regards, sean Sean McLaughlin Hilcorp Alaska, LLC Drilling Manager Sean.McLaughlin@hilcorp.com Cell: 907-223-6784 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, thenpromptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibilityof the recipient to ensure that the onward transmission, opening, or use of this message and anyattachments will not adversely affect its systems or data. No responsibility is accepted by thecompany in this regard and the recipient should carry out such virus and other checks as it considersappropriate. 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 recipientor if you have received this message in error, you are hereby notified that any dissemination,distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, thenpromptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibilityof the recipient to ensure that the onward transmission, opening, or use of this message and anyattachments will not adversely affect its systems or data. No responsibility is accepted by thecompany 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 isintended only for the use of the individual or entity named above. If you are not an intended recipientor if you have received this message in error, you are hereby notified that any dissemination,distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, thenpromptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibilityof the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Sean McLaughlin To:Rixse, Melvin G (OGC) Cc:Cody Dinger Subject:Re: [EXTERNAL] RE: BR 11-86 (225-057) Date:Tuesday, July 8, 2025 12:14:49 PM Mel, Is changing the casing weight a significant change? I don’t believe it is. I could change the weight and keep the permitted pressure test value. Correct? Casing weight adjustments are fairly frequent. Changing the casing pressure test value seems to be a substantial change to the AOGCC. The reason I ask is 1) the threshold for substantial change varies by regulator and company. And 2) We regularly run heavier weight casing than required for the casing design. We are considering permitting a minimum casing weight and grade. Would an increased casing weight trigger a Change to Approved Program? The regulations are punitive for running higher quality casing than necessary for a well. Sean On Jul 8, 2025, at 11:41 AM, Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> wrote: Cody, Sean, I don’t have access to your internal system. For future approvals I can utilize the approved PTD number, but it is appreciated when the approved well name as described in the approved PTD is utilized also. In this case, it is “Granite Pt St 17586 011”. When numbers don’t match, I am compelled to understand the conflict. As per the 20 AAC 25.030. Casing and cementing. (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). For 9-5/8” 47# L-80 as described in the approved PTD <image002.png> <image003.png> The regulation calls for 50% of 6870 psi or 3435 psi. If Hilcorp is planning to run the casing described: 9-5/8” 40# GBCD was run on BR 11-86. I’d like to reduce the casing pressure test to 3000 psi. MASP – 1839 psi. 9-5/8# 40# Internal Yield 5,750 psi please submit a 10-403 with a request to change the approved program for AOGCC to review. 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. Sean McLaughlin From: Cody Dinger <cdinger@hilcorp.com> Sent: Tuesday, July 8, 2025 10:58 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] RE: BR 11-86 (225-057) Hi Mel, Internally we reference the well number (11) first and the abbreviated state ADL (86) second. Historically, that’s how they are setup, the reason for that is to keep them in numerical order in our filing system and Wellview. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Attached screenshot of Wellview/File Drive well names for reference. <image001.png> <image006.png> From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, July 8, 2025 10:40 AM To: Cody Dinger <cdinger@hilcorp.com> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] RE: BR 11-86 (225-057) <image007.png> <image008.png> Cody, Is Hilcorp carrying this well as 11-86 or is it 86-11. AOGCC carries the well name as described in your approved permit to drill which I have as Granite Pt St 17586 011. 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. Sean CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, July 8, 2025 10:10 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: RE: [EXTERNAL] RE: BR 11-86 (225-057) Mel, The well will be BR 11-86 in our files, as has been the case for this field for the last 40 years. So, the well name is accurate to me. Inconsistencies like that is why we were asked to provide the PTD number, which I have done, and it is accurate. Speaking of accuracy, the returned PTD email from the AOGCC had the wrong well name. No need to copy Joe on these emails, Cody Dinger is the Regulatory Tech for Offshore. Is the change of casing test pressure approved? Is it a substantive change? I would think not but I can’t read minds or keep up with the inconsistencies and the constant change in regulation interpretation by the AGOCC. sean --------------------------------------------------- <image009.png> ----------------------------------------------------------- <image010.png> From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, July 8, 2025 8:41 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Joseph Lastufka <joseph.lastufka@hilcorp.com> Subject: [EXTERNAL] RE: BR 11-86 (225-057) Sean, 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. Is this Granit Point State 17586 011 (PTD 225-057)? I have done an extensive search for something in our database matching “BR 11-86” and find nothing. AOGCC always appreciates accurate information when a request is made. 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. Bryan McLellan, Joe Lastufka From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, July 8, 2025 7:23 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: BR 11-86 (225-057) Mel, 9-5/8” 40# GBCD was run on BR 11-86. I’d like to reduce the casing pressure test to 3000 psi. MASP – 1839 psi. 9-5/8# 40# Internal Yield 5,750 psi Regards, sean Sean McLaughlin Hilcorp Alaska, LLC Drilling Manager From:Sean McLaughlin To:Cody Dinger; Rixse, Melvin G (OGC) Subject:RE: [EXTERNAL] RE: BR 11-86 (225-057) Date:Tuesday, July 8, 2025 11:12:38 AM Attachments:image001.png image006.png image007.png image008.png image009.png image010.png image002.png Mel, I permitted as BR 86-11 to be consistent with the Unocal convention and our directional database (see below). This is because Unocal used the abbreviated state number (86) and the well number, 11. Until recently both naming conventions were in our system. We have since gone to the well number first and lease second since that is the current folder structure organization. sean sean From: Cody Dinger <cdinger@hilcorp.com> Sent: Tuesday, July 8, 2025 10:58 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] RE: BR 11-86 (225-057) Hi Mel, Internally we reference the well number (11) first and the abbreviated state ADL (86) second. Historically, that’s how they are setup, the reason for that is to keep them in numerical order in our filing system and Wellview. Attached screenshot of Wellview/File Drive well names for reference. From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, July 8, 2025 10:40 AM To: Cody Dinger <cdinger@hilcorp.com> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] RE: BR 11-86 (225-057) CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Cody, Is Hilcorp carrying this well as 11-86 or is it 86-11. AOGCC carries the well name as described in your approved permit to drill which I have as Granite Pt St 17586 011. 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. Sean From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, July 8, 2025 10:10 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: RE: [EXTERNAL] RE: BR 11-86 (225-057) Mel, The well will be BR 11-86 in our files, as has been the case for this field for the last 40 years. So, the well name is accurate to me. Inconsistencies like that is why we were asked to provide the PTD number, which I have done, and it is accurate. Speaking of accuracy, the returned PTD email from the AOGCC had the wrong well name. No need to copy Joe on these emails, Cody Dinger is the Regulatory Tech for Offshore. Is the change of casing test pressure approved? Is it a substantive change? I would think not but I can’t read minds or keep up with the inconsistencies and the constant change in regulation interpretation by the AGOCC. sean --------------------------------------------------- CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. ----------------------------------------------------------- From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, July 8, 2025 8:41 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Joseph Lastufka <joseph.lastufka@hilcorp.com> Subject: [EXTERNAL] RE: BR 11-86 (225-057) Sean, Is this Granit Point State 17586 011 (PTD 225-057)? I have done an extensive search for something in our database matching “BR 11-86” and find nothing. AOGCC always appreciates accurate information when a request is made. 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 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. aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Bryan McLellan, Joe Lastufka From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, July 8, 2025 7:23 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: BR 11-86 (225-057) Mel, 9-5/8” 40# GBCD was run on BR 11-86. I’d like to reduce the casing pressure test to 3000 psi. MASP – 1839 psi. 9-5/8# 40# Internal Yield 5,750 psi Regards, sean Sean McLaughlin Hilcorp Alaska, LLC Drilling Manager Sean.McLaughlin@hilcorp.com Cell: 907-223-6784 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 anintended 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 receivedthis 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 thismessage 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 andother checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not anintended 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 receivedthis 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 thismessage 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 andother checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not anintended 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 receivedthis 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 thismessage 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 andother checks as it considers appropriate. From:Sean McLaughlin To:Rixse, Melvin G (OGC) Cc:McLellan, Bryan J (OGC); Joseph Lastufka; Cody Dinger Subject:RE: [EXTERNAL] RE: BR 11-86 (225-057) Date:Tuesday, July 8, 2025 10:10:31 AM Attachments:image001.png image002.png Mel, The well will be BR 11-86 in our files, as has been the case for this field for the last 40 years. So, the well name is accurate to me. Inconsistencies like that is why we were asked to provide the PTD number, which I have done, and it is accurate. Speaking of accuracy, the returned PTD email from the AOGCC had the wrong well name. No need to copy Joe on these emails, Cody Dinger is the Regulatory Tech for Offshore. Is the change of casing test pressure approved? Is it a substantive change? I would think not but I can’t read minds or keep up with the inconsistencies and the constant change in regulation interpretation by the AGOCC. sean --------------------------------------------------- ----------------------------------------------------------- CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, July 8, 2025 8:41 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Joseph Lastufka <joseph.lastufka@hilcorp.com> Subject: [EXTERNAL] RE: BR 11-86 (225-057) Sean, Is this Granit Point State 17586 011 (PTD 225-057)? I have done an extensive search for something in our database matching “BR 11-86” and find nothing. AOGCC always appreciates accurate information when a request is made. Mel Rixse 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. 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. Bryan McLellan, Joe Lastufka From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, July 8, 2025 7:23 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: BR 11-86 (225-057) Mel, 9-5/8” 40# GBCD was run on BR 11-86. I’d like to reduce the casing pressure test to 3000 psi. MASP – 1839 psi. 9-5/8# 40# Internal Yield 5,750 psi Regards, sean Sean McLaughlin Hilcorp Alaska, LLC Drilling Manager Sean.McLaughlin@hilcorp.com Cell: 907-223-6784 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. 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:Sean McLaughlin To:Rixse, Melvin G (OGC) Subject:BR 11-86 (225-057) Date:Tuesday, July 8, 2025 7:22:59 AM Mel, 9-5/8” 40# GBCD was run on BR 11-86. I’d like to reduce the casing pressure test to 3000 psi. MASP – 1839 psi. 9-5/8# 40# Internal Yield 5,750 psi Regards, sean Sean McLaughlin Hilcorp Alaska, LLC Drilling Manager Sean.McLaughlin@hilcorp.com Cell: 907-223-6784 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?CO 76B Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 5,956 N/A Casing Collapse Structural Conductor 2,260psi Surface 4,750psi Intermediate Production 7,500psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Eric Dickerman Contact Email:Eric.Dickerman@hilcorp.com Contact Phone:(907) 564-4061 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7/22/2025 4-1/2" LTP / SSSV ±3,500 (MD) ±2,637 (TVD) / ±500 (MD) ±500 (TVD) 5,956 Perforation Depth MD (ft): See schematic 2,456 See schematic 39054-1/2" 228' 30" 13-3/8" 9-5/8" 655' 3,684' MD 5,020psi 6,870psi 655' 2,732' 655' 3,684' Length Size Proposed Pools: 228' 228' L-80 TVD Burst 3,500 8,430psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018742 / ADL0017586 225-057 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20737-00-00 Hilcorp Alaska, LLC Granite Pt St 17586 011 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Other: Initial Completion, N2 Granite Point Undefined Gas Same 4,715 5,900 4,660 1,839psi N/A No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 12:16 pm, Jul 08, 2025 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.07.08 11:36:12 - 08'00' Dan Marlowe 1267) 325-406 SFD 7/16/2025MGR10JUL25 Perforate 48 hour notice to AOGCC for service coil BOPE test to 3500 psi. CBL to AOGCC for review and approval to perforate. 10-404 DSR-7/6/25*&: SFD Granite Pt Gas Pool is governed by CO 76B SFD Granite Pt Gas Pool * Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.17 09:15:09 -08'00'07/17/25 RBDMS JSB 071825 Initial Completion Well: Granite Pt St 17586 011 Well Name:Bruce 86-11 API Number:50-733-20737-00-00 Current Status:New drill gas well Leg:Leg #2 (East corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:225-057 First Call Engineer:Eric Dickerman (907) 564-4061 Second Call Engineer:Casey Morse (907) 777-8322 Maximum Expected BHP:2,310 psi at 4,715’ TVD - 0.49 psi/ft – 10-401 page 40 Max. Potential Surface Pressure: 1,839 psi MPSP -0.1 psi/ft gas grad. to surface – 10-401 page 39 Field/Pool: Granite Point Field, Undefined Gas Pool Applicable Frac Gradient: 0.832 psi/ft using 16.0 ppg EMW – 10-401 page 40 Shallowest Allowable Perf TVD: MPSP/(Frac grad. – Gas grad.) = 1,839 psi / (0.832 – 0.1 psi/ft) = 2,512’ TVD Brief Well Summary: Spartan 151 is currently drilling Granite Pt. St. 17586 011 (Bruce 86-11). The primary target is the Tyonek sands, with a back up target of the Beluga sands. The surface casing section was drilled to TD at 3,684’. An 8- 1/2” production interval is planned to be drilled to a target TD of 5,965’ MD and cased with a 4-1/2” production liner. The upper completion is planned to be a 4-1/2” tieback. Objective: Initial completion post rig. Confirm CBL, actual Pool top and bottom, and shallowest allowable perf TVD approval from AOGCC before perforating. Wellbore information: x A 9-5/8” x 4-1/2” liner lap test, a 4-1/2” MIT-T, and a 9-5/8” x 4-1/2” MIT-IA will be performed to 2,000 psi on the rig per the approved 10-401. x The well will be completed with a tubing retrievable subsurface safety valve set at ± 400’. x Granite Point Undefined Gas Pool top = Top of Lower Beluga sands, estimated at 3,884’ MD / 2,849’ TVD from prognosis. x Granite Point Undefined Gas Pool bottom = Top of Tyonek C sands. TD is planned at the bottom of the Tyonek A sands. Initial Completion Well: Granite Pt St 17586 011 Slickline Procedure: 1. MIRU Slickline. 2. Pressure test PCE to 250 psi low / 3,500 psi high. 3. Open sliding sleeve to allow annulus fluids to be circulated from wellbore. 4. Drift to PBTD. 5. RDMO Slickline. Eline Procedure: (if slickline is able to drift to PBTD) 6. MIRU Eline. 7. Pressure test PCE to 250 psi low / 3,500 psi high. 8. Log CBL from PBTD to top of production liner (estimated at 3,500’). a. Submit CBL to AOGCC for approval prior to perforating. 9. RDMO Eline. Coiled Tubing Procedure: 10. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment. 11. Pressure test BOP and PCE to 250 psi low / 3,500 psi high. a. Provide AOGCC with 48hr witness notification for BOP test. 12. MU cleanout BHA. 13. RIH to PBTD and circulate the well from drilling mud to filtered inlet water. 14. If Eline is unable to log CBL, RIH with CBL toolstring in carrier then log from PBTD to top of production liner (estimated ±3,500’). Submit CBL to AOGCC for approval. 15. RIH and blow well dry with nitrogen. Recover annulus fluid as well. 16. RDMO CTU. Slickline Procedure: 17. MIRU Slickline. 18. Pressure test PCE to 250 psi low / 3,500 psi high. 19. Close sliding sleeve. 20. Dummy gun drift to PBTD. 21. RDMO Slickline. ELine Perf procedure 22. MIRU Eline and Nitrogen package. 23. Pressure test PCE and N2 treating iron to 250 psi low / 3,500 psi high. 24. Confirm CBL, actual Pool top and bottom, and shallowest allowable perf TVD approval from AOGCC before perforating. 25. Perforate target gas sands in the Granite Point Undefined Gas Pool per Reservoir Engineer/Geologist. a. Top pool from prognosis = 3,884’ MD / 2,849’ TVD. b. Bottom pool = deeper than TD. c. Use Nitrogen to pressurize wellbore to target shooting pressure. 26. RDMO Eline and Nitrogen. Initial Completion Well: Granite Pt St 17586 011 CONTINGENCY Eline plug/patch: (if any zone makes unwanted solids or water) 1. RU Nitrogen to tubing and pressure test treating iron to 250 psi low / 3,500 psi high. 2. Pressure up on tubing and displace water back into formation. 3. MIRU Eline. 4. Pressure test PCE to 250 psi low / 3,500 psi high. 5. Set 4-1/2” CIBP or patch to shut off unwanted interval per OE. 6. RDMO Eline and Nitrogen. CONTINGENCY Coiled Tubing Cleanout: (if any zone brings in excessive fill and needs to be cleaned out) 1. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment. 2. Pressure test BOP and PCE to 250 psi low / 3,500 psi high. a. Provide AOGCC with 48hr witness notification for BOP test. 3. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to target depth per OE. a. Working fluid will be 6% KCl (8.6 ppg). b. Take returns to surface from the coiled tubing by 4-1/2” annulus. c. Add foam and nitrogen as necessary to carry solids to surface. 4. RIH and blow well dry with nitrogen. 5. RDMO CTU. Operations: 6. Perform SVS test within 5 days of steady production. Attachments: 1. Proposed Wellbore Schematic 2. CT BOP Drawing 3. Nitrogen procedure Updated By: JLL 07/07/25 PROPOSED Granite Point Field Well: BR 11-86 (Granite Pt St 17586 11) Last Completed: Future PTD: 225-057 API: 50-733-20737-00-00 RKB: MSL = 115’ MLLW to Mud Line – 62’ 4/5 3 1 2 PBTD = ±5,900’ / TVD = ±4,660’ TD = ±5,956’ / TVD = ±4,715’ 13-3/8” 12-1/4” hole 9-5/8” 8-1/2” hole 4-1/2” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 30” Structural - - Weld 28” Surf 228’ 13-3/8 Conductor 68 L-80 BTC 12.415” Surf 655’ 9-5/8" Surf Csg 40 L-80 GBCD 8.681” Surf 3,684’ 4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958” ±3,500’ 5,956’ TUBING DETAIL 4-1/2" Prod Tieback 12.6 L-80 IBT 3.958” Surf ±3,500’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD)Btm TVD)FT Date Status Undefined Gas Pool ± 3,884 PBTD ±2,849 PBTD Future Proposed JEWELRY DETAIL No Depth MD) Depth TVD)ID Item 1 ±400’ ±400’ TRSV with X Nipple (ID = 3.813”) 2 ±3,440 ±2,606’ Chemical Injection Mandrel 3 ±3,470’ ±2,622’ 4-1/2” Sliding Sleeve with X nipple (ID = 3.813”) 4 ±3,500’ ±2,637’ Seal Stem 5 ±3,500’ ±2,637’ Liner hanger / LTP Assembly OPEN HOLE / CEMENT DETAIL 13-3/8" Est. TOC @ Surface 1151 ft3 9-5/8" Est. TOC @ Surface (40% excess) L – 1341 ft3 / T – 252 ft3 4-1/2” Est. TOC @ TOL (40% excess) L – 757 ft3 / T – 206 ft3 GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date TBD GLM’s STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank. 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: Granite Point St17586 011 Field, Undefined Gas Pool Hilcorp Alaska, LLC Permit to Drill Number: 225-057 Surface Location: 1983' FSL, 2059' FWL, Sec 31, T11N, R11W, SM, AK Bottomhole Location: 2441' FNL, 669' FEL, Sec 36, T11N, R12W, SM, AK Dear Mr. McLaughlin: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 20th day of June 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.20 13:54:02 08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 5,956' TVD: 4,715' 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): 115' 15. Distance to Nearest Well Open Surface: x-269670 y-2559349 Zone-4 N/A to Same Pool:1488' GP St 17586 09 16. Deviated wells:Kickoff depth: 700 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 60 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 17-1/2" 13-3/8" 68# L-80 BTC 600' Surface Surface 600' 600' 12-1/4" 9-5/8" 47# L-80 DWC/C 3,700' Surface Surface 3,700' 2,736' 8-1/2" 4-1/2" 12.6# L-80 GBCD 2,456' 3,500' 2,629' 5,956' 4,715' Tieback 4-1/2" 12.6# L-80 IBT 3,500' Surface Surface 3,500' 2,629' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD 228' 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 N/A 228' Drilling Manager Sean Mclaughlin 21. I hereby certify that the foregoing is true and the procedure approved herein will not be Surface Perforation Depth TVD (ft): Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 Production Liner Intermediate Conductor/Structural 30"228' Authorized Title: Authorized Signature: Authorized Name: Perforation Depth MD (ft): Effect. Depth MD (ft):Effect. Depth TVD (ft): Casing CementVolumeSizeLength Total Depth MD (ft):Total Depth TVD (ft): MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 757 ft3 / T - 206 ft3 1839 2615' FSL, 65' FWL, Sec 31, T11N, R11W, SM, AK 2441' FNL, 669' FEL, Sec 36, T11N, R12W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1983' FSL, 2059' FWL, Sec 31, T11N, R11W, SM, AK ADL 18742 / ADL 17586 8130 18. Casing Program:Top - Setting Depth - Bottom Granite Pt St 17586 011 Granite Point Field Undefined Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Plugs (measured): including stage data) 022224484 Specifications 2310 L - 1151 ft3 L - 1341 ft3 / T - 252 ft3 GL / BF Elevation above MSL (ft): Tieback Assy. 6/28/2025 5402' to nearest unit boundary No ype of W L l R L Class: osN No s N Drsh s sDr h h 84 o well is p G Se Se 20 AA SeSe Se NosNo S G y No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Gavin Gluyas at 1:46 pm, May 28, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.05.28 11:47:50 - 08'00' Sean McLaughlin 4311) DSR-6/3/25 268 BOPE test to 3000 psi. Annular to 2500 psi. 48 hour notice. Surface casing pressure test and FIT digital data to AOGCC immediately upon completion of FIT. 11:18 am, Jun 04, 2025 50-733-20737-00-00 MGR18JUN2025 225-057 A.Dewhurst 18JUN25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.20 13:54:17 -08'00' 06/20/25 06/20/25 RBDMS JSB 062425 86-11 Drilling Program Bruce Platform Sean McLaughlin PTD May 22, 2025 BR 86-11 PTD APD xxxxxxx Contents 1. Well Summary.....................................................................................................................................2 2. Management of Change Information................................................................................................3 3. Tubular Program................................................................................................................................4 4. Drill Pipe Information........................................................................................................................4 5. Internal Reporting Requirements.....................................................................................................5 6. Planned Wellbore Schematic.............................................................................................................6 7. Drilling Summary...............................................................................................................................7 8. Mandatory Regulatory Compliance / Notifications.........................................................................8 9. R/U and Preparatory Work.............................................................................................................10 10. Drill 17-1/2” hole, Run 13-3/8” conductor, Cement to surface.....................................................10 11. N/U 21-1/4” 2M Diverter..................................................................................................................12 12. Drill 12-1/4” Surface Hole Section...................................................................................................13 13. Run 9-5/8” Surface Casing...............................................................................................................14 14. Cement 9-5/8” Surface Casing.........................................................................................................17 15. 8-1/2” Production hole Preparatory Work.....................................................................................20 16. Drill 8-1/2” Production Hole Section...............................................................................................21 17. Run 4-1/2” Production Liner...........................................................................................................22 18. Cement 4-1/2” Production Liner.....................................................................................................25 19. Wellbore Clean Up & Displacement...............................................................................................28 20. Run Completion Assembly...............................................................................................................28 21. BOP Schematic..................................................................................................................................29 22. Wellhead Schematic..........................................................................................................................30 23. Anticipated Drilling Hazards...........................................................................................................31 24. FIT Procedure...................................................................................................................................32 25. Choke Manifold Schematic..............................................................................................................33 26. Casing Design Information ..............................................................................................................35 27. 8-1/2” Hole Section MASP...............................................................................................................36 28. Plot (NAD 27) (Governmental Sections).........................................................................................37 29. Slot Diagram......................................................................................................................................38 30. Directional Program (wp01) - Attached separately......................................................................39 Page 2 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 1. Well Summary Well BR 86-11 Drilling Rig Rig 151 Leg & Slot Leg 2 / Slot 4 Directional plan wp01 Pad & Old Well Designation Bruce Platform Planned Completion Type 4-1/2” 12.6# Liner, 4-1/2” Tubing GL Comp Target Reservoir(s)A0-10 Kick off point NA Planned Well TD, MD / TVD 5956’ MD / 4715’ TVD PBTD, MD 5856’ AFE Number AFE Days AFE Drilling Amount Work String 5” DP NC-50 RKB – AMSL 115’ MSL to ML 62’ Well_Desc X_SPAK4_27 Y_SPAK4_27 X_SPAK4_83 Y_SPAK4_83 Lon_NAD83 Lat_NAD83 Location BR 86-11_SHL 269670.30 2559349.40 1409693.93 2559112.85 -151.30 61.00 1983' FSL, 2059' FWL, Sec 31, T11N, R11W, SM, AK BR 86-11_TPH 267688.97 2560021.37 1407712.65 2559784.83 -151.31 61.00 2615' FSL, 65' FWL, Sec 31, T11N, R11W, SM, AK BR 86-11_BHL 266959.50 2560260.29 1406983.20 2560023.76 -151.32 61.00 2441' FNL, 669' FEL, Sec 36, T11N, R12W, SM, AK Page 3 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 2. Management of Change Information Date: May 22, 2025 Subject: Changes to Approved Permit to Drill File #: BR 86-11 Drilling Program Significant modifications to Drilling Program for PTD will be documented and approved below. Changes to an approved PTD will be communicated and approved by the AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approval: Drilling Manager Date Prepared: Engineer Date Page 4 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 3. Tubular Program Hole Section OD (in)ID (in)Drift in) Conn OD (in) Wt ft)Grade Conn Burst psi) Collap se psi) Tension k-lbs) Structural(in place)30”28”Welded 17-1/2” Conductor 13.375 12.415 12.259 13.375 68 L-80 BTC 5020 2260 932 12-1/4” Surface 9.625”8.681”8.525”10.625”47/40 L-80 DWC/C 6870 4750 1086 8-1/2” Production 4-1/2”3.958”3.833”5.0”12.6#L-80 GBCD 8430 7500 288 Minimum of 100’ overlap required between casing strings 4. 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 5”4.276 3.25 6.625 19.5 S-135 NC50 15,638 10,029 560k Page 5 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 5. Internal Reporting Requirements 1. Fill out daily drilling report and cost report. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Try to capture any out-of-scope work as NPT. This helps later when aggregating end of well reports. 2. Afternoon Updates x Submit a short operations update every day to kenaiciodrilling@hilcorp.com 3. EHS Incident Reporting o Notify EHS field coordinator. Garrett St. Clair: C: (907) 252-7780 o Spills: Adrian Kersten: C: 907-564-4820 Sean Mclaughlin o Report ALL spills to the water within 15 minutes. o Submit Hilcorp Incident report to contacts above within 24 hrs 4. Casing Tally x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com 5. Casing and Cmt report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com Page 6 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 6. Planned Wellbore Schematic Page 7 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 7. Drilling Summary BR 86-11 is a 5956’ MD / 4715’ TVD development gas well drilled from leg 2 slot #4 off the Bruce platform. The base plan is an infill gas well to the Tyonek TM15. The well will be completed with a 4-1/2” gas lift tie-back completion. Drilling operations are expected to commence approximately July 2025. General sequence of operations pertaining to this drilling operation: Rig 1. Rig 151 will MIRU over leg 2, slot 4 2. Drill 17-1/2” Conductor hole to 600’ 3. Run 13-3/8” conductor. Perform stab in surface to surface cement job 4. ND riser, Rig up 21-1/4” x 2M Diverter 5. Drill 12-1/4” Surface hole to 3700’ MD. x GR/Res LWD for Surface hole 6. Run 9-5/8” casing to surface. Cement in single stage 7. ND Diverter, NU 13-5/8” BOPE. Test to 3000psi 8. Test casing to 3500 psi. 9. Mill shoe track with 20’ of new formation. 10. Perform FIT to 14.0 ppg EMW 11. Drill 8-1/2” production hole to 5956’ MD, performing short trips as needed x Triple Combo LWD x Open Hole eline logs as needed 12. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean. 13. Perform Clean out run to polish bore 14. Perform liner lap test to 2000 psi. 15. Run 4-1/2” gas lift completion. 16. Land hanger and test.MIT-T to 2000 psi, MIT-IA to 2000 psi 17. ND BOPE, NU tree and test void Page 8 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 8. Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The test of BOP equipment will be to 250/3000 psi for 5/5 min (annular to 2500).Confirm that these test pressures match those specified on the APD. o The upper casing flange is rated to 5000 psi. o The highest reservoir pressure expected is 2310 psi in the TM11 (4715' TVD). MASP is 1839 psi with 0.1psi/ft gas in the wellbore. x If the BOP is used to shut in on the well in a well control situation,ALL BOP components utilized for well control must be tested prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system” x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Review all conditions of approval of the 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. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Page 9 May 22, 2025 BR 86-11 PTD APD xxxxxxxx Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 8.5” x 13-5/8” Shaffer 5M annular x 13-5/8” 5M Shaffer SL Double gate x Blind ram in bottom cavity x Mud cross x 13-5/8” 5M Shaffer SL single gate x 3-1/16” 5M Choke Manifold x Standpipe, floor valves, etc Initial Test: 250/3000 Annular 2500 psi) Subsequent Tests: 250/3000 Annular 2500 psi) x Primary closing unit: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex electric driven pump Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48 hours notice prior to full BOPE test. x Any other notifications required in APD conditions of approval. 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 / (C): 907-250-9193 / Email:bryan.mclellan@alaska.gov Melvin Rixse / Petroleum Engineer / (O): 907-793-1231 / Email:melvin.rixse@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 9. R/U and Preparatory Work 1. N/U 24” riser assembly to 30” landing ring 2. Mix Spud mud for 17-1/2” hole section. 3. Install 7” liners in mud pumps. Plan to pump at 1000 gpm to clean the 30” conductor. 7” liners will deliver 575 gpm @ 98% eff @ 3623 psi. 10. Drill 17-1/2” hole, Run 13-3/8” conductor, Cement to surface 1. P/U 17-1/2” drilling assy: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. x Recommended BHA: 17-1/2” mill tooth bit with 9” directional motor, 8” UBHO sub, 5” DP x Pump at 1000 gpm to clean the hole effectively. 2. 17-1/2” hole mud program summary: x Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. x Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. System Type:8.8 – 9.6 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 11 May 22, 2025 BR 86-11 PTD APD xxxxxxxx Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 0-600 8.8 – 9.6 80-120 20 - 40 35 - 55 <10 8.5 – 9.5 System Formulation:Aquagel / FW spud mud Product Concentration Fresh Water soda Ash AQUAGEL BARAZAN D+ PAC-L /DEXTRID LT BARACARB 5/25/50 STEELSEAL 50/100/400 BAROFIBRE BAROID 41 caustic soda ALDACIDE G 0.905 bbl 0.5 ppb 15 - 25 ppb as needed if required for <10 API FL 5 ppb total 5 ppb total 4.0 ppb as required for weight 8.8 – 9.2 ppg 0.1 ppb (8.5 –9.5pH) 0.1 ppb AQUAGEL and BARAZAN D+ should be used to maintain rheology. Begin system with a 55 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 - 20 ppb total) BARACARBs/BAROFIBRE/STEELSEALs should be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. While drilling, monitor the torque and drag to determine if liquid lubricant is required. If so, approval from town will be required prior to additions of lubricants. Additions of CON DET PRE- MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating high-clay content sections. Maintain the pH in the 8.5 – 9.5 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. Mix a ~50 bbl LCM pill prior to drilling out of the conductor, to be available for immediate use if losses are seen drilling the Surface hole. The pill formulation will be the 50 ppb pill from the LCM tree. Mix the recommended LCM material in thinned back base mud. Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Sweep Formulations: 20 barrels mud, add 1.0 ppb BARAZAN D. Additions of CON DET PREMIX are recommended when penetrating high-clay content sections to reduce the incidence of bit balling and shaker blinding. At TD, a Walnut “flag” (20 bbl pill with 15 ppb of Wallnut M) could be pumped to gauge hole washout to help calculate the required cement volume. The cement will then be pumped and drilling mud will be used to bump the plug. Pretreat this chase mud with 1 ppb Bicarb and 0.5 ppb citric acid. Page 12 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 3. TIH in the 30” drive pipe. Records indicate the 30” drive pipe had 79’ of penetration. The conductor has not been drifted and fill depth is unknown. Bottom of drivepipe is expected at 194’ 4. Drill vertical hole to 600’. x Close approach: 87-04 (Suspended with deep cement plug) x Use eline gyro to verify directional control 5. Run 13-3/8” 68# L-80 BTC conductor. x Include stab in double valve float shoe for inner string cement job (PESI) 6. Land mandrel hanger. After landing all fluid returns with be through two 4” outlets on the 30” casing. 7. Rig up false table and bowl. 8. Run 5” drill pipe with stab in stinger to the float equipment. (verify stinger tool joint connection) 9. Pump 15.3# cement until cement is observed at surface (monitor overboard line). Unstab from float and lay in ~50’ of cement in the 13-3/8” conductor (~8bbls). Displace cement in drillpipe and conductor to mud. Be prepared to overboard cement returns. x Drive pipe (28”) x Conductor - 134 bbls (228’) x OH x Conductor – 65 bbls (40% excess) x Shoe Volume (40’) – 6 bbls x Drill Pipe volume (560’) – 10 bbls x Conductor cement volume required on location – 275 bbls x Annular cement to surface is required. 11. N/U 21-1/4” 2M Diverter 1. N/D riser 2. N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 21-1/4” x 2 M riser on 28” landing ring. x N/U 21-1/4” 2M diverter w/16” outlet. x Knife gate, 16” diverter line. x 75’ between ignition source and diverter outlet required. Close approach: 87-04 (Suspended with deep cement plug) Page 13 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 3. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure.Annular element must close in less than 45 seconds. 4. Set wear bushing in wellhead. 5. Diverter Line Orientation: 12. Drill 12-1/4” Surface Hole Section 1. 12-1/4” hole mud program summary: x Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 9.2 ppg. x Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. System Type:9.2 – 10.0 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Page 14 May 22, 2025 BR 86-11 PTD APD xxxxxxxx Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 600 – 3700 9.0–10.0 80-120 20 - 40 35 - 55 <10 8.5 – 9.5 2. PU Drilling BHA x 12-1/4” Kymera Bit x 8” motor w/ 1.5 deg bend x GR/Res x UBHO for Gyro operations 3. TIH w/ 12-1/4” directional drilling assy drill 12-1/4” hole section . x Eline gyro required until clean tool face and MWD surveys are obtained. x Close approach: o 87-04- Deep set cement plug, Suspended well x Pump at 800 gpm. Short trips and sweep will be required. Ensure shaker screens are set up to handle this flowrate. x Circulate hole clean and pump sweep before dropping rate to prevent fall back and sticking. Maximize drill string RPMs, Pump sweeps and 6rpm rheology (target 10) to ensure effective hole cleaning. x Keep swab and surge pressures low when tripping. x Do not allow MW to drop below a 9.2 ppg. Plan to TD hole section with 9.8 ppg MW o 2300’ MD 9.4 ppg o 3000’ MD 9.8 ppg x Pull wiper trips as often as necessary. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Take MWD surveys every stand drilled. x Rationale for casing shoe depth is to set ~180’ MD above the Granite Point Gas Pool. Planned shoe depth is 2736’ TVD and the top of pool is expected at 2949’ TVD. o BR 87-06 17-1/2” OH to 3471’ TVD on diverter o BR 86-08 17-1/2” OH to 3468’ TVD on diverter o BR 42-12 17-1/2” OH to 3108’ TVD on diverter o BR 42-16 17-1/2” OH to 3030’ TVD on diverter 13. Run 9-5/8” Surface Casing 1. R/U and pull wear bushing. 2. R/U Parker (Volant) 9-5/8” casing running equipment x Ensure 9-5/8” DWC/C x NC50 XO on rig floor and M/U to FOSV. Page 15 May 22, 2025 BR 86-11 PTD APD xxxxxxxx x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Plan to rig up Volant CRT if available x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8-1/2” on the location prior to running. x Note that 47# drift is 8.525” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 3. P/U shoe joint, visually verify no debris inside joint. 4. Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” BTC, 1 Centralizer 10’ from bottom w/ stop ring 1 joint – 9-5/8” BTC, NO Centralizer 1 joint – 9-5/8” BTC, 1 Free floating centralizer x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. 5. Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Centralization: x 1 centralizer every joint to the conductor shoe x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 120’ shoe track Page 16 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 6. Continue running 9-5/8” surface casing x Fill casing while running using the Volant tool. x Centralization: No centralizers in the conductor. 7. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 8. Slow in and out of slips. 9. P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. Page 17 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 10. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Conventional circulation is not permissible once casing hanger is landed. 11. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 14. Cement 9-5/8” Surface Casing 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. x Discuss how to handle cement returns at surface. Ensure overboard lines are in place and observable. x Decide which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x 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 x Review test reports and ensure pump times are acceptable. x 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). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 5. Fill surface cement lines with water and pressure test. 6. Pump remaining 60 bbls 10.5 ppg tuned spacer. 7. Drop bottom plug– FOX rep to witness. 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 surface. Page 18 May 22, 2025 BR 86-11 PTD APD xxxxxxxx Estimated Total Cement Volume: Cement Slurry Design: 9. Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger, and continue with the cement job. 10. After pumping cement, drop top plug and displace cement with spud mud out of mud pits. Lead Slurry Tail Slurry Density 12.0 lb/gal 15.3 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk 8.78 bbls for 120' shoe track 47.83 bbls 286.7 bbls - mgr 1341 cu ft 500' Tail Cement length Displacement volume of cement (3700' - 120') * .07321 = 262.09 BBLS - mgr Page 19 May 22, 2025 BR 86-11 PTD APD xxxxxxxx x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, FOX Cementers during the entire job. 11. Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be bumped. 12. Lower string and land hanger in wellhead again. Cement returns will be out the 2 x 4” side outlets. Ensure hose is in place to take returns and dump into the inlet over the side of the platform. 13. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 14. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 1 shoe track volume, ±6 bbls before consulting with Drilling Engineer. 15. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 16. Be prepared for cement returns to surface. Cement return to be taken overboard. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. 17. Close 4” valves on wellhead side outlet and monitor pressure build up. 18. R/D cement equipment. Flush out wellhead with FW. 19. Back out and L/D landing joint. Flush out wellhead with FW. 20. M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 21. Lay down landing joint and pack-off running tool. Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold Page 20 May 22, 2025 BR 86-11 PTD APD xxxxxxxx x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to sean.mclaughlin@hilcorp.com and cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 15. 8-1/2” Production hole Preparatory Work 1. N/D the Diverter 2. N/U 13-3/8” 5M multi-bowl wellhead assy. Install 9-5/8” packoff P-seals. Test to 3000 psi. 3. 6” liners to be installed in mud pump #1 and pump #2. x Pump range for drilling will be ~420 gpm. This can be achieved with one or both pumps. 4. 8-1/2” Production hole mud program summary: x Primary weighting material to be used for the hole section will be barite to minimize solids. Ensure enough barite is on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. x Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. System Type:LNSD WBM Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 3700- TD 9.8-10.8 40-53 6-15 13-24 8.5-9.5 11.0 System Formulation: 2% KCL/BDF-976/GEM GP Product Concentration Water KCl Caustic BARAZAN D+ DEXTRID LT PAC L BDF-976 GEM GP 0.905 bbl 7 ppb 0.2 ppb (9 pH) 1.0 ppb (as required 18 YP) 1-2 ppb 1 ppb 4 ppb 1.0% by volume Page 21 May 22, 2025 BR 86-11 PTD APD xxxxxxxx BARACARB 5/25/50 STEELSEAL 50/100/400 BAROFIBRE BAROTROL PLUS SOLTEX BAROID 41 ALDACIDE-G 5 ppb (1.7 ppb of each) 5 ppb (1.7 ppb of each) 1.7 ppb 4.0 ppb 2 – 4 ppb as needed 0.1 ppb 5. Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP’s from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. 6. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. 7. NU 13-5/8” BOPE as follows (top down): x 13-5/8” x 5M Shaffer annular BOP. x 13-5/8” 5M Shaffer SL Double ram. (2-7/8” X 5” VBR in top cavity, blind ram in btm cavity) x 13-5/8” mud cross x 13-5/8” 5M Shaffer SL single ram. (2-7/8” X 5” VBR) x N/U pitcher nipple, install flowline. x Install (2) manual valves on kill side of mud cross. Manual valve used as inside or “master valve”. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 8. Run BOPE test plug. 9. Test BOPE. x Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened. x Test VBRs on a 5” and 4-1/2” test joints (3000 psi) x Test Annular on a 4-1/2” test joint (2500 psi) x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 10. Pull test plug, set wear bushing 16. Drill 8-1/2” Production Hole Section 1. Ensure BHA components have been inspected previously. Page 22 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 2. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 3. PU 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. x Triple Combo LWD tools required (DEN, POR, RES) 4. Ensure TF offset is measured accurately and entered correctly into the MWD software. 5. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 6. Ensure to have enough 5” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 7.R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. 8. Drill out shoe track and 20’ of new formation. 9. CBU and condition mud for FIT. 10. Conduct FIT to 14.0 ppg EMW. With 9.4 BHP and 10.4 ppg MW there will a 48 bbl KTV. 11. Drill 8-1/2” hole section to 5956’ MD / 4715’ TVD x Start hole section with 9.8 ppg MW.After 4500’ MD maintain a MW above 10.4 ppg. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. 12. At TD; pump sweeps, CBU, and pull a wiper trip back to the 9-5/8” shoe. 13. POOH LDDP and BHA 14. 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 4-1/2” test joint. 17. Run 4-1/2” Production Liner Email Casing test and FIT digital data to AOGCC immediately upon completion of FIT. - mgr Page 23 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 1. R/U Baker 4-1/2” liner running equipment. x Ensure 5” NC50 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill liner while running. x Ensure all liner has been drifted and tally verified prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). Centralizer 10’ from the bottom with stop ring x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x Landing collar pup bucked up. No centralizer x Centralizers will be run on 4-1/2” liner every joint to 3700’. 4. Continue running 4-1/2” production liner to TD x Short joint run every 1000’, RA Tag 1000’ from bottom. x Fill liner while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Utilize a collar clamp until weight is sufficient to keep slips set properly. 80' Shoe track - mgr Page 24 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 5.Ensure to run enough liner to provide at least 100’ overlap inside casing. Ensure setting sleeve will not be set in a connection. 6. Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 7. M/U Baker ZXP liner top packer. Fill liner tieback sleeve with “XANPLEX”, ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 8. RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 9. RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 10. M/U top drive and fill pipe while lowering string every 10 stands. 11. Set slowly in and pull slowly out of slips. Page 25 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 12. Circulate 1-1/2 drill pipe and liner volume at 9-5/8” shoe prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 15. P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 16. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. 18. Cement 4-1/2” Production Liner 1. Hold a pre-job safety meeting over the upcoming cmt operations. 2. Attempt to reciprocate the casing during cmt operations until hole gets sticky. 3. Pump 15 bbls 12.5 ppg spacer. 4. Test surface cmt lines to 4500 psi. 5. Pump remaining 10 bbls 12.5 ppg spacer. 6. Mix and pump cement per below recipe and volume below with xx lbs/bbl of loss circulation fiber. Please independently verify cement volume with actual inputs. Ensure cmt is pumped at designed weight. Job is designed to pump 40% OH excess but if wellbore conditions dictate otherwise decrease or increase excess volumes. Cement volume is designed to bring cement to 3700’ MD (TOL). 7. Displacement fluid will be CLEAN drilling mud. Please independently verify with actual inputs. TOL estimated to be ~ 3500' w/ 200' liner overlap. -mgr Page 26 May 22, 2025 BR 86-11 PTD APD xxxxxxxx Slurry Information: 8. Drop DP dart and displace with 10.4 ppg WBM. 9. Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point Lead Slurry Tail Slurry Density 12.0 lb/gal 15.3 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Estimated Cement Displacement Volume = (0.017762 * 3500') + (((5956' - 80') - 3500') * (0.015218)) = 98.32 bbls - mg r Page 27 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 10. 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. Reduce pump rate as required to avoid packoff. 11. Bump the plug. Do not overdisplace by more than 2 bbls. 12. Pressure up to 4200 psi to release the running tool (HRD-E) from the liner 13. Bleed pressure to zero to check float equipment. 14. P/U, verify setting tool is released. 15. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 16. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. 18. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 19. POOH, LDDP. Backup release from liner running tool: 20. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 21. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 22. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 28 May 22, 2025 BR 86-11 PTD APD xxxxxxxx Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if liner is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Note: Send Csg & cmt report + “As-Run” liner tally to sean.mclaughlin@hilcorp.com 19. Wellbore Clean Up & Displacement 1. No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. 2. Test liner lap to 2000 psi after cement has reached 500 psi compressive strength. 10 min operational assurance test. 20. Run Completion Assembly 1. Run 4-1/2” tubing completion assembly to above the liner top x Tubing will be 4-1/2” L-80 12.6# IBT x SSSV to be placed at 500’ x CIM to be placed at 2000’ x GLM’s will be run. 2. Swap the well over to FIW x Circulate a hi-vis pill followed by a soap train per Baroid x Circulate FIW until clean-up is satisfactory. x Leave FIW in the annulus. Page 29 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 3. Space out and land seal bore in tie back sleeve. RILDs. 4.Test IA to 2000 psi and tubing to 2000 psi. Charted 30 min. 5. Install BPV in wellhead. 6. ND BOPE, NU tree, test void 7. Rig Down 21. BOP Schematic Page 30 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 22. Wellhead Schematic Superseded by readable drawing on following page. Bruce Platform Grassroots New drills 08/09/2024 Valve, Wing, SSV, WKM-M, 3 1/8 5M FE, w/ 15'’ operator BHTA, Otis, 4 1/16 5M FE x 9.5 Otis quick union top Valve, Upper master, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Swab, WKM-M 4 1/16 5M FE, HWO, EE trim Tubing hanger, Catcus CTF-ONE-CCL, 4 ½ Hydril 563 pin bottom x 6.125 LH acme top, 4'’ Type H BPV profile, 2- ¼ npt control line ports Valve, master, WKM-M, 4 1/16 5M FE, HWO, EE trim Cactus, MBU-EU-CFL- R-DBLO Wellhead system, 13 5/8'’ 5M API quick connect top w/ 4- 2 1/16 5M SSO 28'’ 13 3/8'’ 9 5/8'’ 4 ½’’ 4'’ LPO x 2 Page 31 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 23. Anticipated Drilling Hazards Lost Circulation: Little indication of LC in offset wells. x Maintain sufficient volumes while drill. x Maintain ability to take on FIW during drilling phase x If a LC event occurs pumping cement will be the likely remedy Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual-composition carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. x Minimize swab and surge pressures x Minimize back reaming through coals when possible H2S: H2S gas is not present is planned hole sections Anti Collision: o 87-04- Suspended with deep set cement plug Abnormal Pressure: o Not well understood. Drill with similar MW’s used on 86-09 87-04- Suspended with deep set cement plug Not well understood Page 32 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 24. FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. Add casing pressure test data to graph if recent and available. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 33 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 25. Choke Manifold Schematic Page 34 May 22, 2025 BR 86-11 PTD APD xxxxxxxx Page 35 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 26. Casing Design Information Page 36 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 27. 8-1/2” Hole Section MASP Page 37 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 28. Plot (NAD 27) (Governmental Sections) Page 38 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 29. Slot Diagram BR 86-11 Slot 4 Page 39 May 22, 2025 BR 86-11 PTD APD xxxxxxxx 30. Directional Program (wp01) - Attached separately. 0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 45504875True Vertical Depth (650 usft/in)-975 -650 -325 0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 Vertical Section at 287.44° (650 usft/in)9-5/ 8" x 12-1/4"4-1/ 2" x 8-1/2"0 500 1 0 0 0 1 5 0 0 200025003000350040004 5 0 0 5 0 0 0 5 5 0 0 5 9 5 6 BR 86-11 wp01 Start Dir 2º/ 100' : 700' MD, 700'TVD Start Dir 3º/100' : 800' MD, 799.98'TVD Start Dir 4º/100' : 900' MD, 899.78'TVD End Dir : 2277. 84' MD, 2017.92' TVD Start Dir 3º/100' : 3527. 84' MD, 2642.92'TVD End Dir : 5194. 51' MD, 3965.27' TV Total De pth : 5956' MD, 4715. 19' TV Top Lower Beluga Lower Beluga Top A0 Top A1 Top A2 Top A3 Top A9 Top A10 TM10 Hilcorp Alaska, LLC Calculation Method: Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: BR 86- 11 Water Depth: 62.00 N/-S +E/- W Northing Easting Latittude Longitude 0.00 0.00 2559349.40 269670.30 60° 59' 56.2565 N 151° 17' 51.3537 W SURVEY PROGRAM Date: 2025-05-20T00: 00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 0.00 1400.00 BR 86-11 wp01 (BR 86-11) 3_Gyro-GC_Drop+Sag 1400.00 3700.00 BR 86-11 wp01 (BR 86- 11) 3_MWD+AX+Sag 3700.00 5956.00 BR 86-11 wp01 (BR 86- 11) 3_ MWD+AX+Sag REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: BR 86-11, True North Vertical (TVD) Reference: RKB @ 115.00usft (151)Measured Depth Reference: RKB @ 115.00usft ( 151)Calculation Method: Minimum Curvature Project: Granite Point Site:Bruce Platform Well:Plan: BR 86- 11 Wellbore:BR 86-11 Design:BR 86-11 wp01 CASING DETAILS TVD TVDSS MD Size Name 2735.60 2620.60 3700.00 9-5/8 9-5/ 8" x 12-1/4"4715.19 4600.19 5956.00 4-1/2 4-1/ 2" x 8-1/2"SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 0.00 0.00 0.00 0.00 0.00 0.00 0. 00 0.00 0.00 2 700.00 0.00 0.00 700.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/ 100' : 700' MD, 700'TVD 3 800.00 2.00 294.00 799.98 0.71 -1.59 2.00 294.00 1.73 Start Dir 3º/100' : 800' MD, 799.98'TVD 4 900.00 5.00 294.00 899.78 3.19 -7.17 3.00 0.00 7.80 Start Dir 4º/100' : 900' MD, 899.78'TVD 5 1100.00 13.00 294.00 1097.16 15.91 -35.73 4. 00 0.00 38.85 6 2277.84 60.00 287.00 2017.92 231.18 -681.28 4.00 -8.28 719.25 End Dir : 2277. 84' MD, 2017.92' TVD 7 3527.84 60.00 287.00 2642.92 547.68 -1716.51 0.00 0.00 1801.75 Start Dir 3º/100' : 3527. 84' MD, 2642.92'TVD 8 5194.51 10.00 287.00 3965.27 818.39 -2601.97 3.00 180.00 2727.63 End Dir : 5194. 51' MD, 3965.27' TVD 9 5956.00 10.00 287.00 4715.19 857.05 -2728.42 0.00 0.00 2859.86 Total Depth : 0 1 0 12 3 4 0 3 4 53 53- 6 7 8 8 8 2 3 0 4 97 7/9 0&'//0 3 9 0= 4 0 546 506 3 7.&7' 0'&;' 4 9 3 9 0=0 789 2 7 9789 0 0 0;&7 7& 0 3 2 7()*9 7$9 506 7$9 789 546 7$9 0&77'&'''&'''&'' 789 789 546 7$9 2 789 506 7$97$9 7$9 786 9 786 9 786 9 0''&'''&'''&''0''&''% 7&'''&''/&''/&''00..&.7&''/&''7&. 0& 0;& .07&''%&''.''&''0 7&0 7&''7&''0; %&. 0& 7&'' ;&'' 7&''0&.//0&''00&7 070&7/&.//0&''0&7 /0&./ 00/0&'' '&''%7&% ;0 0/7/0&'%7 0 %& ./0&'' '&''%7 0 7$9 789 789 546 7$9 0 7$9 4 7$9 506 7$97$9 0'&;'/7.&7' 0'&;'/7.&7' 0'&;'/7.&7' 0'&;'/7.&7' 7''&'' '&'' 7''&'' '&'' '&'''&''/0'&;'/7.&7'/ 0'&;'/7.&7'; 0'&;'/7.&7'7 0''&'' '&'' 0''&'' '&'' '&'''&''/0'&;'/7.&7'% 6 @ @ 0..&.07&''/0//77&.0; A>6 @BB=B 0 0& 0/.7&''/0;0 7&0 0& C>6 B BB=@ 7&''/0&. 7&'/7&'' .&.' 0& 0;/.7&''/7&7&'' ; 0 07 /%&.7/./&';/0007 7&'' 7&% 0&0 0./.'&0./0;&;'7&'' . 7''&'' /7&.; 0 % &; 7/7%&' /7';&/' 0 7&'' ;%&. 7 7. 7 .&// 7&% 7&'' 7 0&%7%7&77/7;77'&/7&'' /;/&% 0''&'' ;0&/0 ' &7 0 &0./7'/7''&%7%70 7&'' /0/ 7'&.' 0 %&'0 / & ; 7;/0 /7 &;7/700&'0 7&'' ;%/&%' 77&.' 0 7/&'0&0./00&'//7..&/. 0;&; 7&'' 7/'&% 7 7&/; 7 0%/0&%%/0&.//07 &7&'' 7.;&% 0&7 00&;;/7&;70&%/ 7&7&'' %0 & 7 00& . / &0 0&0& 7 /00;&;' 7&'' 00&7 0&./ /; & 0&''/07&' 7&'' 0 .&/% 4 @@=C?@=B 0. 0&''/0%&%//7&'''&'' 0;77 7''&'' 0.&'' /0 7%/0&''/77&'''&'' 7 0&7; 0/0&''/7&'''&'' . &7 0.&'' ; /&0% 70&''/0/7&'''&'' ..7 0''&'' 00&''/70'0&7&'''&'' 7&7 0.&'' ;0//0&''/7&'7/0;7&07&'''&'' 0 &77 0 7/0&''/7 07/0 0//7&'''&'' 7 0.&'' 7 7&'; 0.&;0&''/77/0 0/7&'''&'' 77&7 7/.&'' 7;.&;% 0&''/0& 7/7&'''&'' 7; &/7 70.&'' 7 7&0 77%&''/0&''/7&7/&%7&'''&'' 0&7 7 0&0&''/7 7&'''&'' 7&77 7''&'' 0.&'' % %&; 0&''/0'&/%/7./7 7&'''&'' 7 7'&7%/0&''/0 0&.%/77/7&'''&'' 000&7 0&7 7/&./ %70&00&''/0 7/0&./'&'' 0% A>6 A @=C?C B 0&7 /0 %07 00%&0&''/00 ;&'' 7 0 7$9 789 789 546 7$9 0 7$9 4 7$9 506 7$97$9 0''&'' %7&7 /0;%&0&''/0 0&/7/0 7 0 B 6 D E 6CD 7 /0.%&; 0&''/0 0% &'// 7&%7 7.&;' /7.&'' 7&;;/0&''/0 0/0/0;7&'';&'' / 7 7 /0&''/0 00&0/077& ;;&'' / 7 7%&7 /0&%; 0%&0&''/070&00&7% 7 7/&7 /7 00&.7/&0&''/0 7 &7/7 ;&'' /70&;; 7 7 ;0;&7. 0&/0./0&''/0 70 7/7.;&'' / 7 7 ;0 %&7' 0&''/0 7 .&. /7.;0%&; 7 7''&'' ;;&7 ;7. 0;/&;' 7'/0&''/0 7&.%/0&7.;7.;&'' /7;;&/ 7 7 ;0&.0 070&.7 0 &%7/0&''/0 7& ;/77& 7;0 ;&'' /7 7 7. ;07.&00&/;/0&''/0 77%&..;7./& 7 0&7 ;7'%& 7 0 70&''/0 0&%7 ;&'' /0 7 0''&'' /7&7 ;7.7&0% 00%&/; 70&''/0 7;/0;& .;0.&0%;&'' / 7 7 ;0 7.0&''/0 0&0./70 &% 7 70 ;0 70&''/0 70/7 7& 7 7 ;0.00&''/0 7&00/7&; 7 7 ;0.0&''/0 7.&00&.0; 7 ;00%&0 7'/0&''/0 70 7& 0 0;&70&'' 00&''/07;;0;/&'';&'' /0'/&.' 7 ;0/&7 7&'0&''/00%0&7 ;&'' /0' 7&7/0&''/0 0&/ /0 0 7&.% A 7&% '&'' ;0 0/0&''/00 ;&'' /0/0&7 4 BC=AB @? 0'&0 00&''/0 7&/%/7;;0 '&'' /0/ 7 07 7./0&''/0 0&0%/7&7& %'&'' /07%&.% 7''&'' '&'' 7 0&70&''/0777 '&'' /0 7 0'/0&''/0 7&0%/77 0 7 7&0&''/0 7/7 &'%7 7.&0. 0''&'' '&'' 7 7 77&'% 0&''/0 07/7 7%7 7 7 0/7&/. '&'' 7 7 0&'' 7%&/. 7/0&''/0&0;/70&0070/&'''&'' / B 7 7.& ; 0'/&%//0&''/7/7 77 00 7 7 7&/ 0 .& //0&''/07/0&/7 7%&'7 '&'' /7 70 '&'' 7 0/7&0&''/070 7 0 %&'' 0&'7 0/0&''/7 0 7$9 789 789 546 7$9 0 7$9 4 7$9 506 7$97$9 C B 7 0 %& . 0&'% 0/7//0&''/7 B C@ B?C 6 D E 6 D 7$97$9 7D97D90 7 270 %& .%7 2 7:/0;%&0''&''.7 7$9 7$9 7890789 2 7&%7 /7.&'' ,8 70 7 7 0 %&'' ,! ''&'' 0;&70&'' , 7 7 0/7&/. 7 7 0&'' , 7 8 7$9 7$9 546 7$9 506 7$9 0''&'' 0''&'' '&'' '&'' 4 0''=4 0''=,?4 0..&.0 4 4 0..&.4 0 0& 0 4 7>< ''=4 0 4 00&7 /0&./ %&. 0; 1 4 00&7=4 0&./=4 0&7 /7/&./ /; & 4 0&7=4 7/&./=,?4 7&% ;0 %70&0 1 4 7&% =4 0=4 7 0 %& . 0 ,4 @ 4 70 %& .=4 1 Dewhurst, Andrew D (OGC) From:Sean McLaughlin <sean.mclaughlin@hilcorp.com> Sent:Wednesday, 18 June, 2025 16:04 To:Dewhurst, Andrew D (OGC) Cc:Rixse, Melvin G (OGC) Subject:RE: [EXTERNAL] Granite Pt St 17586-11 PTD (225-057) Andy, Pore pressures were primarily determined from actual oset wells. BR 86-11 and 86-10 are located on dierent sides of a fault. BR 86-11 will be drilled on the north side of the fault. BR 86-09 and BR 86-03 were also drilled on the north side of the fault. As such, they were used more heavily when prognosing pore pressure. The uncertainty has to do with relating mud weights in old drilling records to pore pressures (well 86-03 drilled in 1967). When doing so the pore pressure seems to be higher than the regional trend. However, this could be an artifact of the drilling environment at the time. The planned mud weight is equivalent to the actual MW of 86-09 (1993). This may make the well signicantly overbalanced when comparing to the regional data. Regards, sean From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Wednesday, June 18, 2025 3:27 PM To: Sean McLaughlin <sean.mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: [EXTERNAL] Granite Pt St 17586-11 PTD (225-057) Sean, I am completing my review of the Granite Pt St 17586-11 PTD and have a question about the anticipated pore pressures. x How were the predicted pore pressures determined? I see the note about them being not well understood; I’m just trying to understand what they are based on, the magnitude of uncertainty, and what is driving the anticipated dierences between BR 86-11 and 86-10. Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov 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 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. 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 nogreater 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. GRANITE PT Granite Pt St 17586 11 UNDEFINED GAS 225-057
