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Home My WebLink About225-0901. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: Kuparuk River Field Torok Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 24,600 None Casing Collapse Structural Conductor Surface 2,470 Intermediate 4,790 Production 7,850 Liner 9,210 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:Allen Eschete Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 12/16/2025 24,594'13,591' 4-1/2" 5201' Halliburton TNT Prod Packer Baker ZXP, No SSSV 7-5/8" 20" 10-3/4" 80' 7-5/8"10,997' 2,694' 133' 119' 2,733' 5,012'11168' 11,035' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL393883 / ADL025528 / ADL025544 / ADL390434 225-090 P.O. Box 100360, Anchorage, Alaska 99510-0360 50-103-20925-00-00 ConocoPhillips Alaska, Inc. Proposed Pools: KRU 3T-614 AOGCC USE ONLY 11,590 Tubing Grade: Tubing MD (ft): TNT Packer: 10,827' MD / 4,920' TVD ZXP: 11,003' MD / 4,969' TVD Perforation Depth TVD (ft): L-80 11,009' Perforation Depth MD (ft): 4-1/2" 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 Length Size TVD Burst Allen.Eschete@ConocoPhillips.com 907-265-6558 Senior Completions Engineer None5,201 24,594 5,201 1,828 10,860 MD 6,890 5,210 119' 2,471' 4,978' Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Allen Eschete DN: OU=ConocoPhillips Alaska, O=Completions Engineering , CN=Allen Eschete, E=Allen.Eschete@ConocoPhillips.com Reason: I am the author of this document Location: Date: 2025.12.02 14:47:11-09'00' Foxit PDF Editor Version: 13.1.6 Allen Eschete 325-734 By Grace Christianson at 7:52 am, Dec 03, 2025 DSR-12/3/25 CDW 12/08/2025 TS 12/8/25 12/16/2025 VTL 12/8/2025 10-404 12/08/25 SECTION 1 - AFFIDAVIT 10 AAC 25.283 (a)(1) Exhibit 1 is an affidavit stating that the owners, landowners, surface owners and operators within one-half mile radius of the current or proposed wellbore trajectory have been provided notice of operations in compliance with 20 AAC 25.283(a)(1). SECTION 2 PLAT 20 AAC 25.283 (2)(A) Plat 1: Wells within 1/2 mile Table 1: Wells within 1/2 miles (2)(C) 26 wells CDW 12/08/2025 SECTION 3 FRESHWATER AQUIFERS 20 AAC 25.283(a)(3) There are no known underground sources of drinking water within one-half mile radius of the current or proposed wellbore trajectory. Well 3T-614 lies within acreage that was located inside the former Oooguruk Unit before it was purchased by ConocoPhillips Alaska Inc. and included within the 12th expansion of the KRU. Page 17 of EPA class I UIC permit number AK1I009-B for Oooguruk Unit disposal wells DW-1 and DW-2 (obtained with that purchase) states: The requirement to monitor the strata overlying the confining zone for fluid movement is waived since the aquifers at the Oooguruk Unit are too naturally saline to qualify as USDWs (meet No USDW criteria). SECTION 4 PLAN FOR BASELINE WATER SAMPLING FOR WATER WELLS 20 AAC 25.283(a)(4) There are no water wells located within one-half mile of the current or proposed wellbore trajectory and fracturing interval. A water well sampling plan is not applicable. SECTION 5 DETAILED CEMENTING AND CASING INFORMATION 20 AAC 25.283(a)(5) All casing is cemented and tested in accordance with 20 AAC 25.030. See Wellbore schematic for casing details. SECTION 6 ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL 20 AAC 25.283(a)(6) Casing & Cement Assessments: The 10-3/4 casing cement report on 10/14/2025 shows that the job was pumped with 394 barrels of 11.0 ppg lead cement and 61 barrels 15.8 ppg tail cement. This was displaced with 234 bbl 9.8 ppg spud mud. The plug bumped and the floats held. The 7-5/8 casing cement report on 10/22/2025 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 159 barrels of 14.0 ppg lead cement, followed with 63 barrels of 15.3 ppg tail cement. This was displaced with 499 barrels of 9.5 ppg NAF. The plug bumped, pressure was bled off, and floats were confirmed to be holding. According to the log and SLB interpretation, the good TOC reached 8,353 MD with a transition zone up to 4,194. We also had the ConocoPhillips Cementing SME (Dale Doherty) review the log, and his interpretation is that the TOC reached approximately 6,300 MD with VDL pipe signal slightly fading and the amplitude readings suggesting that the cement is still setting up. The 4-1/2 liner cement report on 11/03/2025 shows the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 380 barrels of 15.3 ppg cement. The cement was displaced with 302 bbls of 9.5 ppg brine and the plugs bumped and held for 5 minutes. Floats held. 60 bbls of mud push with trace cement was observed after circulating a bottoms up from the liner top packer indicating the entire lateral is cemented. Summary All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Based on engineering evaluation of the wells referenced in this application, ConocoPhillips has determined that this well can be successfully fractured within its design limits. SECTION 7 PRESSURE TEST INFORMATION AND PLANS TO PRESSURE- TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 10/15/2025 the 10-3/4 casing was pressure tested to 3,000 psi for 30 minutes On 10/22/2025 the 7-5/8 casing was pressure tested to 4,000 psi for 30 minutes. On 11/05/2025 the 4-1/2 tubing was pressure tested to 4,200 psi for 30 minutes. On 11/05/2025 The 7-5/8 casing by 4-1/2 tubing annulus was pressure tested to 3,850 psi for 30 minutes. AOGCC Required Pressures [all in psi] Maximum Predicted Treating Pressure (MPTP) 7,050 Annulus pressure during frac 3,500 Annulus PRV setpoint during frac 3,600 7-5/8" Annulus pressure test 3,850 4-1/2" Tubing pressure Test 4,200 Electronic PRV 8,050 Highest pump trip 7,550 4200 psi tubing test allows max surf frac pressure of 7318 psi with 3500 psi IA hold pressure. CDW 12/08/2025. SECTION 8 PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283(a)(8) Size Weight, ppf Grade API Burst, psi API Collapse, psi 10-3/4 45.5 L-80 5,209 2474 7-5/8 29.7 L-80 6,885 4,789 7-5/8 33.7 P-110S 10,860 7,870 4-1/2 12.6 L-80 8,430 7,500 Table 2: Wellbore pressure ratings Stimulation Surface Rig-Up Kuparuk 10K Frac Tree SECTION 9 DATA FOR FRACTURING ZONE AND CONFINING ZONES 20 AAC 25.283(a)(9) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that: The fracturing zone, the Torok Oil Pool, has an average thickness of approximately 300 ft TVD over the course of the lateral section of well 3T-614, from where it intersects the top formation at 11,146 MD (-4,955 TVDSS) to the TD of the well. The Torok Oil Pool is comprised of thinly interbedded sandstone, siltstone, and silty shale layers. The sandstone and siltstone components are litharenites, moderately to well sorted, and very fine grained. The silty shales are composed of clay-rich, moderately to poorly sorted silt and clay . The estimated fracture pressure for the Moraine interval is approximately 12.5-13.5 ppg. The overlying confining interval of the Torok Formation consists of mudstones and siltstones with a thickness of approximately 840 TVD along the 3T-614 trajectory. The top of the Torok confining interval in the well starts at 8,623 MD (-4,116 TVDSS). The estimated fracture gradient of the overlying Torok formation is approximately 0.82 psi/ft. The underlying confining zone below the Base Moraine consists of lower Torok, HRZ, and Kalubik shales totaling approximately 500 TVD. The estimated fracture gradient for this section ranges from 15-18 ppg, with the gradient increasing down section. The Base Moraine is estimated from seismic to be at -5,260 TVDSS along the length of the well. The estimated formation pressure within the Torok Oil Pool is 2,285psi at a depth of 5,200 TVDSS. SECTION 10 LOCATION, ORIENTATION AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE 20 AAC 25.283(a)(10) ConocoPhillips has formed the opinion, based on following assessments for each well and seismic, well, and other subsurface information currently available that none of these wells will interfere with containment of the hydraulic fracturing fluid within the one-half mile radius of the proposed wellbore trajectory. Casing & Cement assessments for all wells that transect the confining zone: 3S-612: The 7-5/8 casing cement report on 11/4/2018 shows that the job was pumped as designed, indicating competent cementing operations. 12.5 ppg MPII was pumped before dropping bottom plug, this was then chased with 303bbls of 15.8 ppg Class G cement and the top plug was dropped. This was chased with 9.5 ppg LSND mud. The plug bumped, pressured up to 1500 psi and held for 5 min. Floats were checked and they held. Full returns were seen throughout the job. A TOC was then logged and determined at 8,270MD/3,832 TVDRKB/3,768 TVDSS Source: 218-111 - Laserfiche WebLink 3S-625: The 7-5/8 casing cement report on 9/29/2022 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 297 barrels of 15.3ppg cement with BMII. The cement was displaced with 574 barrels of 9.6ppg LSND drilling mud. The plug did not bump and 50% of shoe track volume was pumped. Losses totaled 21 barrels during the job. Cement floats held. A cement bond log indicates competent cement with a cement top @ 7,850 MD (3,970 TVDRKB / 3,908 TVDSS). Source: 222-079 - Laserfiche WebLink 3T-613: The intermediate casing cement job was pumped with 211 bbls of 14.0ppg lead cement and 59 bbls of 15.3ppg tail cement. Plugs bumped and floats held. Source: Laserfiche WebLink 225-036 3T-616: The intermediate casing cement job was pumped with 117 bbls of 14.0ppg with BMII lead cement and 58bbls of 15.3ppg tail cement. Plugs bumped and floats held. Source: Laserfiche WebLink 224-138 3T-616 PB1: The abandonment plug consisted of 42bbls of 16.3ppg cement laid in at the heel of the wellbore into the 7-5/8 intermediate casing shoe. The cement top was then tagged at 9,065 MD/5,104 TVD/5,053 TVDSS with 12klbs. Coyote isolated via main wellbore 3T-616. Source: Laserfiche WebLink 224-138 3T-616 PB2: Not cemented. Coyote isolated via main wellbore 3T-616. Source: Laserfiche WebLink 224-138 3T-619: The intermediate cement job was pumped with 191 barrels of 14.0 ppg lead cement, followed with 61 barrels of 15.3 ppg tail cement. This was displaced with 520 barrels of 10.0 ppg NAF. The plug bumped, pressure was bled off, and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 7,652 MD (3,974 TVDRKB). The intermediate column of good cement of 437 MD in combination with the weaker column of cement above in excess of 2600 MD meets regulation (AOGCCs approval on 09/03/2025). Source: 225-063 - Laserfiche WebLink 3T-622: The Intermediate casing cement job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 433 barrels of 13.5 ppg cement. The cement was displaced with 303 bbls of 9.5 ppg brine and the plugs bumped and held for 5 minutes. Floats held. 112 bbls of good cement were observed after circulating a bottoms up from the liner top packer indicating the entire lateral is cemented. Source: 225-079 - Laserfiche WebLink Nuna-1: The 7-5/8 casing was cemented in place on 2/16/2012. The cement report indicates that the job was pumped with 40 bbls 15.8ppg Class G cement. The plugs bumped and partial returns were observed during the job (pg. 187 at link). Suspension operations began on 1/18/2023 where a cement retainer was set at 9,062 CTMD and 65bbls of Class G cement was pumped through the retainer. Another retainer was placed at 7,965 MD and 48bbls of 15.8ppg cement was pumped with another 12 bbls laid on top of the retainer. The TOC was tagged at 7,003 MD and a MIT-T performed to 1700 psi, witnessed by AOGCC on 3/1/2023. A tubing cut was completed at 6,960 MD and the 4.5 tubing was then pulled. A CIBP was set at 6,910 MD and tested to 1,200 psi. Cement was laid on top of the retainer and tagged at 6,621 MD two times with 12klbs. Source: Laserfiche WebLink 211-155 Colville Delta 3: Colville Delta 3 was abondoned on 3/31/1986 with a cement retainer set at 5000' MD. Additionally, a surface plug was pumped and witnessed by AOGCC. Cement was then pumped down the 7" x 9-5/8 annulus. The wellhead was removed and the 9-5/8" and 7" casing were cut off. A plate was welded over the 7" casing and deemed adequately plugged by the AOGCC according to the Plugging and Location Clearance Report on 2/27/96.Source: 185-211 - Laserfiche WebLink SECTION 11 LOCATION OF, ORIENTATION OF AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFINING ZONES 20 AAC 25.283(a)(11) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that four faults transect the Torok Oil Pool reservoir within one half mile radius of the 3T-614 wellbore trajectory shown in Plat 1. Two faults intersect the 3T-614 well trajectory at 20,792 MD (Fault 1) and 20,913 MD (Fault 2) respectively. Both are interpreted to strike NE-SW, downthrown to the South with less than 20 of offset. There are two other faults within the half mile radius, but neither intersect the 3T-614 wellbore. The first, (Fault 3), is southwest of the 3T-614 toe, striking NE-SW, downthrown to the South with approximately 10 of throw in the ½ mile radius. The second (Fault 4), is located to the Northwest of the 3T-614 heel, striking NE-SW, downthrown to the South with approximately 10 of throw. All faults in the ½ mi area of the 3T-614 are difficult to trace on the seismic data, due to a) lack of fine-scale resolution at the Torok Oil Pool level and b) lack of reflectivity in the overlying Torok shales, the result of the monotonous shaly lithology. Faults 1 and 2 are interpreted to be confined to the Moraine interval as they are not explicitly mapped on seismic and are interpreted only on well log correlation. Fault 3 is seismically mappable but not interpreted to penetrate through the overburden, into the overlying hydrocarbon bearing Coyote Oil Pool. Fault 4 is mapped both on seismic and with well penetrations and has the potential to penetrate through the overburden into the overlying hydrocarbon bearing Coyote Oil Pool, however; due to the shaly overburden and horizontal stress acting on the fault (interpreted to be 15.8 ppg at the faults mapped orientation) the fault will not interfere with containment. If there is any indication that a fracture has intersected any mapped fault (or any other faults unmapped to date) during fracturing operations, ConocoPhillips will go to flush and terminate the stage immediately. SECTION 12 PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC 25.283(a)(12) 3T-614 was completed in November 2025 as a horizontal injector in the Torok formation. The well is completed with a 4.5 tubing upper completion and a cemented 4.5 liner with 22 dart activated sliding sleeve and 4 ball drop activated sliding sleeve lower completion. The first stage frac will be pumped through a toe initiator valve in the toe of the lateral. After the 1st stage, a ball/dart will be dropped to shift open the 2nd stage sleeve and isolate the first stage. A frac will then be pumped through the 2nd stage. Balls/darts will continue to be dropped to provide isolation from the previous stage and open each subsequent stage. Proposed Procedure: Halliburton Pumping Services: 1. Conduct Safety Meeting and Identify Hazards. Inspect Wellhead and Pad Condition to identify any pre- existing conditions. 2. Ensure the frac tree was tested to ~10,000 psi at rig. 3. Ensure all pre-frac well work has been completed and confirm the tubing and annulus are filled with a freeze protect fluid to 2,235 MD / 2,124 TVD. 4. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 5. MIRU 40 clean insulated Frac tanks (450 bbls usable volume per tank), with a berm surrounding the tanks that can hold a single tank volume plus 10%. Load tanks with either seawater or treated produced water. 6. MIRU HES Frac Equipment. 7. PT Surface lines to ~9,500 psi using a Pressure test fluid. 8. Test IA Pop off system to ensure lines are clear and all components are functioning properly. 9. Bring up pumps and increase annulus pressure to 3,500 psi as the tubing pressures up. 10. Pump Frac Stages 1 through 27 by following attached pump schedule at ~37 bpm with a maximum expected treating pressure of ~7,050 psi. Skip stage 8 due to proximity of fault. 11. The well is ready for Post Frac well prep/production tree installation, coiled tubing cleanout and flowback. SECTION 13 POST-FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.283(a)(13) Flowback will be initiated through a de-sander unit until the fluids clean up at which time it will be turned over to production for initial clean up production. Frac Design Attachments: 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-614 (PTD No. 225-090; Sundry No. 325-734) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 December 8, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. TS 12/4/25 (a)(2) Plat Provided with application. TS 12/4/25 (a)(2)(A) Well location Provided with application. Well lies in Section 1 of T12N, R07E, UM. TS 12/4/25 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNRs Alaska Mapper application (accessed online 12/4/25, 2025), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of KRU 3T-614. There are no subsurface water rights or temporary subsurface water rights within 5 miles of the surface location of KRU 3T-614. TS 12/4/25 (a)(2)(C) Identify all well types within ½ mile Provided with application. The operator has identified 26 wells within ½ mile radius. TS 12/4/25 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None: 3T-614 lies within the boundary of the Kuparuk River Unit Aquifer Exemption map as currently depicted on EPA Region 10s Alaska Oil & Gas Aquifer Exemptions Interactive Map, available through EPA Region 10s web site. The boundary of the Aquifer Exemption as currently depicted on the EPA website differs from the boundary of the Kuparuk River Unit of 1984 that forms the basis for the aquifer exemption granted by Title 40 CFR 147.102(b)(3). AOGCC is currently seeking guidance from EPA Region 10 as to which of those AEO boundaries applies in this area. TS 12/8/25 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-614 (PTD No. 225-090; Sundry No. 325-734) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 December 8, 2025 It is unlikely that there are freshwater sands beneath the surface casing shoes of wells drilled in the 3T Pad area. An examination of well logs and a quick-look Pickett Plot analysis by AOGCC of a prominent, water-wet sand beneath permafrost above the surface casing shoe in nearby well Colville Delta 3 (PTD 185-211-which has open-hole resistivity and porosity well logs) between 1,942' and 1,966' MD (-1,905' to -1,929' TVDSS), yielded TDS values greater than 11,000 mg/l. This sand correlates to the interval in 3T-614 from 2067 to 2,084 MD (-1,935 to -1,949 TVDSS), which lies about 9,500 to the southeast of Colville Delta 3. If the shallowest water bearing sand in the Colville Delta 3 is of a TDS concentration higher than that of freshwater, it is probable that all water bearing zones below are also higher in TDS concentration. Additional supporting evidence that there are no potential underground sources of drinking water from other resources: Well 3T-614 lies within acreage that was located inside the former Oooguruk Unit before it was purchased by CPAI and included within the 12th Expansion of the KRU. According to page 17 of EPA's UIC Class 1 Permit Number AK11009-B for Oooguruk Unit disposal wells DW-1 and DW-2: The requirement to monitor the strata overlying the confining zone for fluid movement is waived since the aquifers at the Oooguruk Unit are too naturally saline to qualify as USDWs (meet No USDW criteria). 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-614 (PTD No. 225-090; Sundry No. 325-734) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 December 8, 2025 Further support is found in Conclusion 14 of AIO 33 for the nearby Oooguruk-Kuparuk Oil Pool also states: Formation water salinity calculations by the Commission using log data from four exploratory wells and methods compatible with the Rwa method endorsed by the EPA confirm that there are no aquifers within the Affected Area that could serve as underground sources of drinking water. (a)(4) Baseline water sampling plan Not applicable. There are no water wells within a ½ - mile radius of the 3T-614 wellbore trajectory. TS 12/4/25 (a)(5) Casing and cementing information Provided with application. As drilled schematic attached, as built not generated to date. CDW 12/08/2025 (a)(6) Casing and cementing operation assessment 10-3/4 surface casing cemented to surface with 455 bbl pumped. 7-5/8 casing shoe at 11168 ft MD. TOC by sonic log good cement 8353 ft, fair cement from 4194 ft. CPAI interpretation is good cement may be up to 6300 ft MD with cement still setting up. Log shows adequate bonding in area of the liner lap and sleeve/frac interval is well below shoe No issues with cement for the upcoming stimulation. 4.5 liner top and packer 11003 ft MD, production packer 10827 ft MD. Liner cemented with no losses of 380 bbl pumped and cement traces circulated off liner top indicating cement to liner top. Uppermost frac sleeve 11431 ft MD. CDW 12/08/2025 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 Only exempt freshwater aquifers present. (See Section (a)(3), above.) TS 12/4/25 (a)(6)( B) Each hydrocarbon zone is isolated Yes, cement isolates each hydrocarbon zone. TS 12/4/25 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-614 (PTD No. 225-090; Sundry No. 325-734) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 December 8, 2025 Coyote and Moraine isolated by 7-5/8 intermediate casing cement. TOC at 4,194 MD / 2,978 TVD (fair); 6,300 MD / 3,545 TVD (interpreted); 8,353 MD / 4,096 TVD (good). Top Coyote is 8,361 MD / 4,098 TVD. CDW 12/08/2025 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3850 psi MITIA planned, 4200 psi MITT plan. CDW 12/08/2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi wellhead max. frac. Pressure 7318 psi. Pump knock out 7550 and ePRV 8050 psi., tree test 10000 psi, lines test 9500 psi. CDW 12/08/2025 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper confining zones: Mudstones and siltstones of the Torok Formation with a thickness of approximately 840 TVD along the 3T-614 Trajectory. Fracture gradient expected to be about to 0.82psi/ft (15.8 ppg EMW). Fracturing Zone: 300 TVT of Torok Oil Pool interbedded very fine-grained sandstone, siltstone and silty shale between 11,146 MD and the total depth of the well 24,600 MD (-4,955 to -5,150 TVDSS). Fracture gradient expected to be about 0.65 to 0.70 psi/ft (12.5 to 13.5 ppg EMW). Lower confining zone: Lower Torok, HRZ shale, and Kalubik shale that have an aggregate TVT of about 500. From seismic, the base of the Moraine is estimated to be -5,260 TVDSS. Fracture gradient expected to range from about 0.78 to 0.94 psi/ft (15 to 18 ppg EMW). TS 12/4/25 (a)(10) Location, orientation, report on mechanical condition of each well that may transect the confining zones and sufficient information to determine wells will not interfere with containment of It is highly unlikely that any of the wells or wellbores within a ½-mile radius will interfere with hydraulic fracturing fluids from this operation because of cement isolation and / or separation distance. There are 10 wells (including plug backs) within ½ mile of 3T-614 that penetrate the confining intervals. TS 12/4/25 CDW 12/08/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-614 (PTD No. 225-090; Sundry No. 325-734) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 December 8, 2025 hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory AOGCC evaluated all wells that may transect the confining zones within the 3T-614 Area of Review and found it highly unlikely that any of these wells will interfere with fracturing fluids due to cement-isolation and/or separation distance or direction. (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory Four faults. It is unlikely that any faults will interfere with containment of the injected fracturing fluids; however, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. The operator has identified four faults or fracture zones through seismic or well data within a ½-mile radius of KRU 3T-614. None of these faults are expected to interfere with containment of injected fluids due to their being a) confined to the Moraine interval and / or b) sufficiently sealed by in-situ horizontal stress and the overlying confining zones. See application for details. TS 12/4/25 (a)(12) Proposed program for fracturing operation Provided with application. CDW 12/08/2025 (a)(12)(A) Estimated volume Provided with application. 27 stages. 57K bbl total dirty vol. 5.278Million lb total proppant. CDW 12/08/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 12/08/2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. Patina, Resmetrics, and Halliburton disclosure provided. CDW 12/08/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 12/08/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-614 (PTD No. 225-090; Sundry No. 325-734) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 December 8, 2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 7050 psi. Max. 7318 psi allowable treating pressure. Max pressure is 7550 psi to 8050 psi to Pump shutdown. With 3500 psi back pressure IA (IA popoff set 3600 psi), max tubing differential should be 3550 psi. CDW 12/08/2025 (a)(12)(F) Fractures height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-lengths of the induced fractures will range from 100 to 160. The anticipated height of the induced fractures is between 210 and 275. None of the induced fractures are expected to penetrate through either of the thick confining intervals above or below the 3T-614. TS 12/4/25 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. CPF3 or Drill Site 3Ts facilities. CDW 12/08/2025 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3500 psi back pressure, plan to test to 3850 psi, popoff set as 3600 psi CDW 12/08/2025 (c) Fracturing string (c)(1) Packer >100 below TOC of production or intermediate casing 4.5 tubing will be anchored with a retrievable packer set at approx. 10827 ft with sleeve planned for 11431 ft. 4.5 liner top and packer 11003 ft MD. Liner cemented with no losses of 380 bbl pumped - and cement traces circulated off liner top indicating cement to liner top. 7-5/8 casing shoe at 11168 ft MD. TOC by sonic log good cement 8353 ft, fair cement from 4194 ft. CPAI interpretation is good cement may be up to 6300 ft MD with cement still setting up. Log shows adequate bonding in area of the liner lap and sleeve/frac interval is well below shoe No issues with cement for the upcoming stimulation. CDW 12/08/2025 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 4200 psi. Max pressure differential is estimated as 3550 psi (7050 with 3500 psi backpressure) so test of 4200 psi satisfies > 110% CDW 12/08/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-614 (PTD No. 225-090; Sundry No. 325-734) Paragraph Sub-Paragraph Section Complete? AOGCC Page 7 December 8, 2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 9000 psi line pressure test, pump knock out 7550 psi with max. global kickout 8050 psi. IA PRV set as 3600 psi. CDW 12/08/2025 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 12/08/2025 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 3600 psi. Surface annulus open. Frac pressures continuously monitored. CDW 12/08/2025 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 12/08/2025 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above). TS 12/4/25 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. TS 12/4/25 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. 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Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Tolman, Ben V To:Loepp, Victoria T (OGC); Lau, Jack J (OGC); Regg, James B (OGC) Cc:Broussard, Brian T; Hobbs, Greg S Subject:3T-614 (PTD: 225-090) False Gas Alarm Date:Saturday, October 18, 2025 6:01:20 PM All, A false H2S low alarm went off earlier today on Doyon 142 while drilling ahead in the 3T- 614 intermediate hole section. Exact details are below. Please let us know if you have any follow-up questions. At 08:20 hrs while drilling ahead at 8240’ MD (in the intermediate hole section), a H2S 10 PPM flashing alarm went off from the cellar sensor, with the monitor reading 11PPM. The rig crew picked up off bottom and stopped drilling operations. The subbase was cleared of personnel. The alarm station was reading 4 PPM (monitored from the driller’s cabin). The Toolpusher took readings on the rig floor and cellar area with a handheld gas monitor. No H2S readings were detected in any area of the subbase. The Electrician went to inspect / troubleshoot the sensor & determined that the false alarm was from cleaning solution fumes in close proximity to the sensor. An all clear was given to the crew. The alarm was cleared on the gas detection system. The gas sensor was re-tested to confirm functionality. Drilling operations were resumed. Thanks, Ben Tolman & Brian Broussard Ben Tolman | D142 Drilling Superintendent | ConocoPhillips, Alaska O: 907-265-6828| M: 307-231-3550 | ATO-1536, Anchorage, AK 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:Hobbs, Greg S To:McLellan, Bryan J (OGC) Cc:Lau, Jack J (OGC) Subject:FW: KRU 3T-614 (PTD: 225-090) Date:Wednesday, October 15, 2025 2:42:06 PM Attachments:Outlook-ky23pcv5.png USA_ConocoPhillips_3T-614_10 34in_Casing_InvizionRT_Post_Job_Report_20251013_rev1.1.docx Bryan, Brian did not know to cc you. Greg From: Broussard, Brian T <Brian.T.Broussard@conocophillips.com> Sent: Wednesday, October 15, 2025 2:32 PM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; jack.lau@alaska.gov Cc: Tolman, Ben V <Ben.V.Tolman@conocophillips.com>; Earhart, Will C <William.C.Earhart@conocophillips.com>; Doyon 142 Drilling Supv <d142cm@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: KRU 3T-614 (PTD: 225-090) Hi Jack, Doyon 142 completed the surface cementing job on the 3T-614 (PTD: 225-090). Job report from SLB is attached. Job Summary: Pump 110 bbl 10.5 ppg spacer Drop bottom plug Pump 394 bbl 11 ppg lead cement Pump 61 bbl 15.8 ppg tail cement Drop top plug Pump 20 bbl fresh water Displace with 234 bbl of 9.8 ppg spud mud Bumped plugs and floats held Had minor losses of 48 bbl throughout the job Returned 184 bbl of cement to surface Surface shoe at 2,738'MD/2,474'TVD Please let me know if you have any questions. Thanks, Brian Broussard Drilling Engineer – Kuparuk 700 G Street, Anchorage, AK 99501 Cell: 337.967.0516 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KUPARUK RIV UNIT 3T-614 JBR 11/26/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:7 7 5/8" and 5" test joints used for testing. BOP Misc fail/passes: Upper pipe rams door seals failed and had to be replaced. The lower pipe rams had one door seal that had to be replaced. The oteco gasket on the choke hose failed and was tightened and passed the retest. Other F/P: The dart valve failed and had to be replaced. Both the upper and lower IBOP valves failed and were replaced and tested after I had left location. The charts were sent to me to show they passed and I gave them the go ahead to continue working. 16 charge bottles ranging from 950 psi to 1000 psi. Test Results TEST DATA Rig Rep:H. Huntington/K. HaugOperator:ConocoPhillips Alaska, Inc.Operator Rep:A. Lundale/Celie Hull Rig Owner/Rig No.:Doyon 142 PTD#:2250900 DATE:10/14/2025 Type Operation:DRILL Annular: 250/3500Type Test:INIT Valves: 250/5000 Rams: 250/5000 Test Pressures:Inspection No:bopGDC251015202459 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 10.5 MASP: 1828 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 F Lower Kelly 1 F Ball Type 2 P Inside BOP 1 FP FSV Misc 0 NA 14 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8" 5000 P #1 Rams 1 7 5/8" Solid P #2 Rams 1 Blind/Shear P #3 Rams 1 3 1/2"x6" VB P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8" 5000 P HCR Valves 2 3 1/8" 5000 P Kill Line Valves 3 3 1/8" 5000 P Check Valve 0 NA BOP Misc 4 See Details FP System Pressure P3000 Pressure After Closure P1775 200 PSI Attained P10 Full Pressure Attained P52 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6@1987 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P16 #1 Rams P7 #2 Rams P7 #3 Rams P7 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2          Attachments - BOPE Test Charts; Accumulator Drawdown Test Report; Test Sequence; Emails re: # of Failures and Recent Between Wells Maintenance -- J. Regg BOPE Test - Doyon 142 KRU 3T-614 (PTD 2250900) AOGCC Insp# bopGDC251015202459 10/14/2025 BOPE Test - Doyon 142 KRU 3T-614 (PTD 2250900) AOGCC Insp# bopGDC251015202459 10/14/2025 DOYON RIG 142 ACCUMULATOR DRAW DOWN WORKSHEET 3T-614 DATE: 10-14-2025 ACCUMULATOR PSI 3000 MANIFOLD PSI 1575 FUNCTION RAMS/ANNULAR/ HCR'S, DON'T FUNCTION BLINDS! FUNCTION ONE RAM TWICE LET PRSSURE STABILIZE AND RECORD BACK UP NITROGEN BOTTLE'S ACCUMULATOR PSI 1775 NITROGEN BOTTLE'S PSI BOTTLE # 1 2000 BOTTLE # 2 2000 BOTTLE # 3 2025 BOTTLE # 4 2000 BOTTLE # 5 2000 BOTTLE # 6 1900 AVG FOR 6 BOTTLE'S =1987 TURN ON ELEC. PUMP, SEC FOR 200 PSI =10 TURN ON AIR PUMP'S TIME FOR FULL CHARGE =52 Annular time: 16 UPR time: 7 Blind/ Shear time: 7 LPR time: 7 KILL HCR time: 2 Choke HCR time: 2 Test Bope 7-5/8” & 5” 250/3500 On The Annular Both Test Joints 250/5000 On Everything Else 1. 7-5/8” TJ, Annular 250/3500 2. 5” Dart valve 3.5” FOSV #1 4. 7-5/8” TJ, UPR’s CMV’s #’s 1, 12, 13, 14, Rig floor kill line valve 250/5000 5. CMV’s #’s 9, 11, Mezz Kill line valve 250/5000 6. CMV’s #’s 8, 10, HCR Kill, 5” FOSV #2 250/5000 7. CMV’s #’s 6, 7, Manual Kill 250/5000 8. Super Choke 250/2000 9.Manual Choke 250/2000 10. CMV’s #’s 2, 5 250/5000 11. HCR Choke 250/5000 12.Manual Choke 250/5000 Remove 7-5/8”Test Joint 13. CMV’s #’s 3, 4, Blind rams 250/5000 Install 5” Test joint 14. 5” TJ Annular 250/3500 15.5” TJ 3-1/2” X 6” Lower VBR’s 250/5000 Koomey Draw Down 16. Top Drive Upper IBOP 17. Top Drive Lower IBOP Test Bope 7-5/8” & 5” 250/3500 On The Annular Both Test Joints 250/5000 On Everything Else IBOP=2 Manual choke=1 LPR’s=1 Dart=1 Mud Cross=6 Total Components=32 TIW=2 Annular=2 CMV’s =14 UPR’s=1 Hyd. choke=1 Blind/Shears=1 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:Hobbs, Greg S To:Regg, James B (OGC) Subject:RE: [EXTERNAL]FW: Doyon Rig 142 3T-614 Date:Thursday, October 16, 2025 7:57:44 AM Attachments:image001.png BWM 3T-614 10-11-25.doc They just did one. They did not write the times, but they go through the stack over about 12 hours while surface is being drilled. This is an example of failures that occur over time even with a robust process. The report is attached- Greg From: Regg, James B (OGC) <jim.regg@alaska.gov> Sent: Wednesday, October 15, 2025 9:09 PM To: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: [EXTERNAL]FW: Doyon Rig 142 3T-614 CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. When was the last time they did BWM inspection? Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Rig 142 <rig142@doyondrilling.com> Sent: Wednesday, October 15, 2025 8:01 PM To: DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Cook, Guy D (OGC) <guy.cook@alaska.gov> Subject: Doyon Rig 142 3T-614 Doyon Rig 142 3T-614 BOPE test report 10-15-2025 Kelly Haug BOPE Test - Doyon 142 KRU 3T-614 (PTD 2250900) AOGCC Insp# bopGDC251015202459 10/14/2025 Rig 142 Tourpusher Rig142@doyondrilling.com Doyon Rig 142 Office 907-670-6002 Cell, 907-355-5834 10/16/2025, 9:05am Email from Greg Hobbs, CPAI -responding to my email question about # of failures on 10/14/2025 Doyon 142 BOPE test) Year to Date CPAI BWM program statistics: The door seal failures on 142 are rare and they do not change out the seals every maintenance. The Oteco connection does leak occasionally after the connection, IBOP’s and Dart Valve failures are a bit of a surprise- The IBOP’s were installed a month ago or so according to the report. Dept.: CPAI Drilling and Wells Form Name: BWM Inspection Report Appendix No.: D Issue Date TBD Revision No. 0 Revision Date 16-Apr-2014 Prepared By M.Kneale Approved By Level No. Uncontrolled When Printed Page 1 of 8 Dept.: CPAI Drilling and Wells Form Name: BWM Inspection Report Appendix No.: D Issue Date TBD Revision No. 0 Revision Date 16-Apr-2014 Prepared By M. Kneale Approved By Level No. Uncontrolled When Printed Page 2 of 8 Dept.: CPAI Drilling and Wells Form Name: BWM Inspection Report Appendix No.: D Issue Date TBD Revision No. 0 Revision Date 16-Apr-2014 Prepared By M. Kneale Approved By Level No. Uncontrolled When Printed Page 3 of 8 Rig Name: Doyon 142 Report Date: 10-11-25 Equipment Involved: Annular, single gate upper, single gate blind shear, single gate lower, HCR’s, choke manifold & floor valves Document #: AK-WMS-8.9 Manufacturer: Hydril Model #: 13 5/8” 5M Serial #: 161260 Date/Time – 10-11-25 / 2300 Date/Time – 10-11-25 / 2300 Equipment Inspection Summary Inspection Summary: • Annular- • Element, Installed new on 8/18/25. • BOP-ANN-021 • Serial # 1223-1740 • Element # 0822-0548 • Total cycles on element = 16 • API ring between = BX 160, Installed 9-22-24 • Single gate upper- • 7 5/8” Solid Body Rams • Guides good, wear plates good. • Door seals, Installed new on 10/14/23. • Ram seals are in good working condition. • Bolts and bosses good • Cavities in good condition • s/n = R-6492-1 DS / r-6492-2 ODS • Total cycles = 175 • API ring Between = BX 160 • Single gate Blinds/Shear • 14” operator’s • Guides good, Wear plates good. • Cavities in good condition, Changed door seals on 12-13-23. • Ram seals are in good condition, All seals, both sides, replaced on 8-9-2025 • Bolts and Bosses’ good • s/n= BOP-BLO-461 DS, Installed 8-9-2025 • s/n= BOP-BLO-462 ODS Installed 8-9-2025 • Total cycles = 12 • API ring between blinds and mud cross = BX 160 • API ring between mud cross and LWR’s = BX 160 • Single gate lower- • 3-1/2” X 6” VBR’s • Guides good, Wear Plates good. • Cavities good, Door seals Installed new on 4-14-24. • Ram seals are in good condition, changed door seals on 4-14-24 • Bolts and Bosses look good. • s/n= N6892-2 DS, N6894-1 ODS • Total cycles = 123 Dept.: CPAI Drilling and Wells Form Name: BWM Inspection Report Appendix No.: D Issue Date TBD Revision No. 0 Revision Date 16-Apr-2014 Prepared By M. Kneale Approved By Level No. Uncontrolled When Printed Page 4 of 8 Inspection Details Choke Manifold • All Choke valves changed out Dec-6-21, SN# noted in CPA Critical Well Control Equipment Testing and Cycle Count info worksheet. • Greased choke manifold valves tested both hyd & manual choke valves, function choke panel. • Choke Manifold valves tested 8/18/25. • Kill tested good on 8/18/25. • Changed out Kill HCR valve with S/N 22020001 on 5/17/23. • Changed out Manual Kill with valve S/N 239698 on 1/11/22. • Changed out Choke HCR valve with S/N 1422050049 on 2/18/23. • Changed out Manual Choke valve with S/N 238901 on 1-11-22. Accumulator- • Checked fluid level and at proper operating level. • Nitrogen back up bottles Avg. = 2000 psi • Accumulator tested on 8/18/25. • New lines to all preventers installed 1/30/18. • New triplex pump A 12/22/18 • All fluid and filters changed 9/9/25 Floor Valves- • New Valves 7/5/2025 • 5” delta 527 DART M&M S/N M24-0257-4 Total cycles = 54 • 5” Delta 527 FOSV M&M S/N M24-0242-6 Total cycles = 54 • 5” Delta 527 FOSV M&M S/N M22-0257-1 Total cycles = 54 Top Drive Upper/Lower IBOP- • Hyd Upper IBOP- Upper SN# 85394 installed 9/10/25 • Total cycles = 419 • Lower Manual IBOP – SN# 84827 installed 9/10/25 • Total cycles = 3 Dept.: CPAI Drilling and Wells Form Name: BWM Inspection Report Appendix No.: D Issue Date TBD Revision No. 0 Revision Date 16-Apr-2014 Prepared By M. Kneale Approved By Level No. Uncontrolled When Printed Page 5 of 8 List each Action Taken and inspection. Item: Upper pipe rams Manufacture: Hydril / GE Assigned to: Sean Carney Required Completion Date: N/A Completed by: Sean Carney Date Completed: 10/11/25 Contractor Work Order #: Required Action; Clean and inspect rams and seals changed rams to 7 5/8 solid body Item: Blinds Corresponding Root Cause: Hydril / GE Assigned to: Sean Carney Required Completion Date: N/A Completed by: Sean Carney Date Completed: 10/11/25 Contractor Work Order #: Required Action, Clean and inspect rams and seals. Item: Lower pipe rams Corresponding Root Cause: Hydril / GE Assigned to: Sean Carney Required Completion Date: N/A Completed by: Sean Carney Date Completed: 10/11/25 Contractor Work Order #: Required Action, Clean and inspect rams and seals, Dept.: CPAI Drilling and Wells Form Name: BWM Inspection Report Appendix No.: D Issue Date TBD Revision No. 0 Revision Date 16-Apr-2014 Prepared By M. Kneale Approved By Level No. Uncontrolled When Printed Page 6 of 8 Inspection Support: (Photos, Maintenance, Invoices, etc.) Annular Upper Pipe Ram O.D.S. Annular Upper Pipe Ram D.S. Dept.: CPAI Drilling and Wells Form Name: BWM Inspection Report Appendix No.: D Issue Date TBD Revision No. 0 Revision Date 16-Apr-2014 Prepared By M. Kneale Approved By Level No. Uncontrolled When Printed Page 7 of 8 Blinds D.S. Lower pipe DS Lower pipe ODS Dept.: CPAI Drilling and Wells Form Name: BWM Inspection Report Appendix No.: D Issue Date TBD Revision No. 0 Revision Date 16-Apr-2014 Prepared By M. Kneale Approved By Level No. Uncontrolled When Printed Page 8 of 8 Inspection Support: (Photos, Maintenance, Invoices, etc.) Timeline Worksheet Remediation Timeline From To Hours Date Open, inspect ram cavity’s and change upper rams to 7 5/8 solid body 10/11/25 10/11/25 Open, clean inspect Blind Rams 10/11/25 Open clean and inspect lower pipe rams 3.5 x 6” 10/11/25 Inspect Annular 10/11/25 Total time List Personnel Conducting Investigation: Position Driller: Leland Peterson Driller Team Member 1 Sean Carney Motorman Team Member 2 Sean Lincoln Motorman Team Member 3 Team Member 4 Tool Pusher: Harley Huntington CPAI Company Rep: Adam Dorr Drilling Superintendent: Sam Dye 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 Chris Brillon Wells Engineering Manager Conoco Phillips Alaska, Inc. 700 G Street Anchorage, AK, 99501 Re: Kuparuk River Field, Torok Oil Pool, KRU 3T-614 Conoco Phillips Alaska, Inc. Permit to Drill Number: 225-090 Surface Location: 1877' FSL, 496' FWL, SENE S1 T12N R7E Bottomhole Location: 4271' FSL, 1755' FWL, SENW S14 T12N R7E Dear Mr. Brillon: 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 2nd day of October 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.10.02 11:03:27 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if w ell 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: 24551.34 TVD: 5186 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: 10/28/2025 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 1002' to ADL025528 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 51 15. Distance to Nearest Well Open Surface: x-467706 y- 6003603 Zone- 4 12 to Same Pool: 883' to 3T-616 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42"20" 94 H-40 Welded 81 39 39 120 120 13.5"10.75" 45.5 L80 Hyd563 2746 39 39 2785 2439 9.875"7.625" 29.7 L80 Hyd563 10461 39 39 10500 4842 9.875"7.625" 33.7 P110-S Hyd563 800 10500 4841.8 11300 5058 6.5"4.5" 12.6 P110-S Hyd563 13401.34 11150 5001.35 24551.34 5186 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Brian Broussard Chris Brillon Contact Email:Brian.T.Broussard@cop.com Wells Engineering Manager Contact Phone:907-263-4090 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 s hales: 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 Perforation Depth MD (ft):Perforation Depth TVD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Authorized Title: Authorized Signature: Commission Use Only See cover letter for other requirements. Intermediate Production Liner Plugs (measured):Effect. Depth MD (ft):Effect. Depth TVD (ft): Surface Conductor/Structural Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks 1143sks 13.5ppg Casing Length Size Cement Volume MD Total Depth MD (ft):Total Depth TVD (ft): 902sks 11ppg, 273sks 15.8ppg 588sks 14ppg, 269sks 15.3ppg STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ConocoPhillips Alaska Inc.59-52-180 KRU 3T-614 10 yds P.O. Box 100360 Anchorage, Alaska, 99510-0360 Kuparuk River Field Torok Oil Pool 1877' FSL, 496' FWL, SENE S1 T12N R7E ADL393883 / ADL025528 / ADL025544 / ADL390434 (including stage data) 1302' FSL, 830' FWL, NWSE S34 T13N R7E LONS 01-013 4271' FSL, 1755' FWL, SENW S14 T12N R7E 5760/2560/2560/2556 GL / BF Elevation above MSL (ft): 2346 1828 18. Casing Program: No yp L l R S t g o No Noo N o D s s sD lt 80 o ssGs s S S 20 A S Noo No I S s G y E Noo s 225-090 By Grace Christianson at 10:30 am, Aug 20, 2025 10/10/2025 TS 10/1/25 Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig Annular preventer test to 2500 psig BOPE testing on a 21-day interval is approved with the attached conditions Intermediate I cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available Cement logs must be reviewed with the AOGCC as soon as available and prior to running the production liner.X DSR-9/10/25 50-103-20925-00-00 Variance of the diverter requirement under 20AAC 25.035(h)(2) is approved. VTL 10/1/2025 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.10.02 11:04:13 -08'00' 10/02/25 10/02/25 RBDMS JSB 100725 <ZhϯdͲϲϭϰ Conditions of Approval: Approval is granted to run the LWD-Sonic on upcoming well with the following provisions: 1. CPAI will provide a written log evaluation/interpretation to the AOGCC along with the log as soon as they become available. The evaluation is to include/highlight the intervals of competent cement that CPAI is using to meet the objective requirements for annular isolation, reservoir isolation, or confining zone isolation etc. Providing the log without an evaluation/interpretation is not acceptable. 2. LWD sonic logs must show free pipe and Top of Cement, just as the e-line log does. CPAI must start the log at a depth to ensure the free pipe above the TOC is captured as well as the TOC. Starting the log below the actual TOC based on calculations predicting a different TOC will not be acceptable. 3. CPAI will provide a cement job summary report and evaluation along with the cement log and evaluation to the AOGCC when they become available 4. CPAI will provide the results of the FIT when available. 5. Depending on the cement job results indicated by the cement job report, the logs and the FIT, remedial measures or additional logging may be required. 10 text here .58'67 CPAI’s request to allow BOPE testing on a 21-day interval is approved with the following conditions: - CPAI must continue to implement the Between Wells Maintenance Program as approved by AOGCC. - The initial test after rigging up BOPE to drill a well must be to the rated working pressure as provided in API Standard 53. - CPAI is encouraged to take advantage of opportunities to test within the 21-day time limit. - CPAI must adhere to original equipment manufacturer recommendations and replacement parts for BOPE. - Requests for extensions beyond 21 days must include justification with supporting information demonstrating the additional time is necessary for well control purposes or to mitigate a stuck drill string. ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 August 14, 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill 3T-614 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Moraine Injector well from the 3T drilling pad. The intended spud date for this well is 10/28/2025. It is intended that Doyon 142 be used to drill the well. 3T-614 will utilize a 13 1/2” surface hole drilled to TD and 10 3/4” casing will be set and cemented to surface. As noted in section 4 of the attached proposed drilling program, the low maximum anticipated surface pressure of the well allows use of a three preventer BOPE per 20 AAC 25.035 (e) (1) (A) (i-iii). The fourth preventer will contain solid body pipe rams that will be sized for the intermediate casing string. The 9 7/8” intermediate hole will be drilled and set in the Moraine reservoir. A 7 5/8” casing string will be set and cemented from TD to secure the shoe and cover 250’TVD above any hydrocarbon-bearing zones (Coyote). The production interval will be comprised of a 6 1/2” horizontal hole that will be landed and geo-steered in the Moraine formation. The well will be completed as a fracture stimulated Injector with 4 1/2” liner and frac sleeves, cemented from TD to the liner top. The upper completion will include a production packer with GLM’s and a downhole guage tied back to surface. A variance is requested for a BOPE test interval of 21 days for this project. Doyon 142 is a strong participant in the CPAI BOPE between well maintenance program, reflected by low failure rates in BOP tests since its entry into the CPAI fleet. The variance allows effective drilling and completion of problematic zones, or longer intervals during the well construction. It is also requested that a variance of the diverter requirement under 20AAC 25.035(h)(2) is granted for well 3T-614. At 3T, there has not been any significant indication of shallow gas hydrates to date through the surface hole interval. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1. Form 10-401 APPLICATION FOR Permit to Drill per 20 ACC 25.005 (a) 2. A proposed drilling program 3. A proposed completion diagram 4. A drilling fluids program summary 5. Pressure information as required by 20 ACC 25.035 (d)(2) 6. Directional drilling / collision avoidance information as required by 20 ACC 25.050 (b) Information pertinent to the application that is presently on file at the AOGCC: 1. Diagrams of the BOP equipment, diverter equipment and choke manifold lay out as required by 20 ACC 25.035 (a) and (b). 2. A description of the drilling fluids handling system. 3. Diagram of riser set up. If you have any questions or require further information, please contact Brian Broussard at 907-263-4090 (Brian.T.Broussard@conocophillips.com) or Chris Brillon at 907-265-6120. Sincerely, cc: 3T-614 Well File / Jenna Taylor ATO 1560 Will Earhart ATO 1552 Brian Broussard Chris Brillon ATO 1548 Drilling Engineer Jenny Doherty ATO 1410 Brian Broussard I am the author of this document 2025.08.18 16:21:14 -08'00' Brian Broussard Recommend approval of diverter variance. TS 10/1/25 3T-614 PTD Page 1 of 10 3T-614 Application for Permit to Drill Document Table of Contents 1. Well Name .............................................................................................................................................................. 2 2. Location Summary ................................................................................................................................................... 2 3. Proposed Drilling Program..................................................................................................................................... 5 4. Blowout Prevention Equipment ............................................................................................................................. 6 5. Diverter System ..................................................................................................................................................... 6 6. MASP Calculations ................................................................................................................................................ 6 7. Procedure for Conducting Formation Integrity Tests ............................................................................................. 7 8. Casing and Cementing Program ........................................................................................................................... 7 9. Drilling Fluid Program ............................................................................................................................................ 8 10. Abnormally Pressured Formation Information ................................................................................................... 9 11. Seismic Analysis ................................................................................................................................................ 9 12. Seabed Condition Analysis ................................................................................................................................ 9 13. Evidence of Bonding .......................................................................................................................................... 9 14. Discussion of Mud and Cuttings Disposal and Annular Disposal ...................................................................... 9 15. Drilling Hazards Summary ................................................................................................................................. 9 16. Proposed Completion Schematic ..................................................................................................................... 11 3T-614 PTD Page 2 of 10 1. Well Name Requirements of 20 AAC 25.005 (f) The well for which this application is submitted will be designated as 3T-614 2. Location Summary Requirements of 20 AAC 25.005(c)(2) Location at Surface 1,877 FSL, 496 FWL, SENE S1 T12N R7E, UM NAD 1927 Northings: 6003603 Eastings:467706 RKB Elevation 51’AMSL Pad Elevation 12’AMSL Top of Productive Horizon (Heel) 1302‘ FSL, 830‘ FWL, NWSE S34 T13N R7E, UM NAD 1927 Northings: 6008340 Eastings: 461197 Measured Depth, RKB: 11,300 Total Vertical Depth, RKB: 5,058 Total Vertical Depth, SS: 5,006 Total Depth (Toe) 4271‘ FSL, 1755‘ FWL, SENW S14 T12N R7E, UM NAD 1927 Northings: 5995457 Eastings: 463655 Measured Depth, RKB: 24,551 Total Vertical Depth, RKB: 5,186 Total Vertical Depth, SS: 5,135 Pad Layout 3T-614 PTD Page 3 of 10 Well Plat 3T-614 PTD Page 4 of 10 Attachment – 3T-614 Area of Review (AOR) An Area of Review plot is shown below of the 3T-614 injector planned well path and offset wells. 3T-616 is the offset well from the planned 3T-614 injector. The 3T-616 includes PB1 and PB2 wellbores. 3T-614 PTD Page 5 of 10 3. Proposed Drilling Program Requirements of 20 AAC 25.005(c)(13) 1. MIRU Doyon 142 onto 3T-614 2. Rig up and test diverter and riser, dewater cellar as needed. 3. Drill 13 1/2” hole to the surface casing point as per the directional plan. x LWD Program: arcVISION (GR, Res), TeleScope (D&I), SDI GWD (GWD) 4. Run and cement 10 3/4” surface casing to surface. 5. Install BOPE and MPD equipment. 6. Test BOPE to 250 psi low / 5,000 psi high (24-48 hr regulatory notice). 7. Pick up and run in hole with 9 7/8” drilling BHA to drill the intermediate hole section. 8. Chart casing pressure test to 3,000 psi for 30 minutes. 9. Drill out 20’ of new hole and perform LOT. Maximum LOT to 18.0 ppg. Minimum LOT required to drill ahead is 11.0 ppg EMW. 10. Drill 9 7/8” hole to section TD, setting pipe 5-10’ TVD in the Moraine Reservoir using near-bit GR. x LWD Program: arcVISION (GR, Res), TruLink (D&I), Xcel RSS (near-bit GR). 11. Run 7 5/8” casing and cement to a minimum of 250’ TVD above any hydrocarbon bearing zones (cementing schematic attached). Pressure test casing if possible on plug bump to 4,000 psi. 12. Freeze protect down the Outer Annulus (10 3/4” surface casing x 7 5/8” intermediate casing annulus). 13. Test BOPE to 250 psi low / 4,000 psi high (24-48 Regulatory notice). 14. Pick up and run in hole with 6 1/2” drilling BHA. Log top of cement with sonic tool in real-time mode. 15. Chart casing pressure test to 4,000 psi for 30 minutes if not tested on plug bump. 16. Drill out shoe track and 20 feet of new formation. Perform LOT to a maximum of 16 ppg. Minimum required leak-off value is 11.0 ppg EMW. 17. Drill 6 1/2” hole to section TD x LWD Program: Periscope (GR, Res, Directional Res), DigiScope (D&I), ADN-4 (Density, Porosity) SonicScope (Ultrasonic for TOC). 18. Pull out of hole with drilling BHA. Review intermediate cement job details and sonic log TOC. 19. Run 4 1/2” liner with toe valve, frac sleeves and liner hanger and packer to 24,551 MD. 20. Cement 4 1/2 liner from TD to liner top. Pressure test 4 1/2” liner and liner hanger packer for 30 minutes. 21. Run 4 1/2” upper completion with glass plug, production packer and gas lift mandrels. Space out and land tubing hanger. 22. Pressure test hanger seals to 5,000 psi. 23. Pressure test against the glass plug to set production packer, test tubing to 4,200 psi, chart test. 24. Bleed tubing pressure to 2,200 psi and test IA to 3,850 psi, chart test. 25. Install HP-BPV. 26. Nipple down BOP. 27. Install tubing head adapter assembly. N/U frac tree and test to 10,000 psi/5 minutes. 28. Freeze protect down tubing and annulus. 29. Secure well. Rig down and move out. Please note – This well will be frac’d 3T-614 PTD Page 6 of 10 4. Blowout Prevention Equipment Requirements of 20 AAC 25.005(c)(3 & 7) Please reference BOP schematics on file for Doyon 142. Doyon 142 will use a BOPE stack equipped with an annular preventer, fixed 7 5/8” solid body rams, blind/shear rams and variable rams while drilling and running casing in the intermediate section of 3T-614. 3T-614 has a MASP of 1,828 psi in the intermediate hole section using the methodology in section 6 MASP calculations. With a MASP less than 3000 psi ConocoPhillips classifies the operation as a Class 2. Per 20AAC 25.035.e.a.A: For an operation with a maximum potential surface pressure of 3,000 psi or less, BOPE must have at least three preventers, including: i. One equipped with pipe rams that fit the size of drill pipe, tubing or casing begin used, except that pipe rams need not be sixed to bottom-hole assemblies and drill collars. ii. One with blind rams iii. One annular type Intermediate Drilling/Casing Production Proposed Configuration: Proposed Configuration: Annular Preventer (iii) Annular Preventer 7 5/8” fixed rams during drilling Intermediate VBRs in Upper Cavity Blind/Shear Rams (ii) Blind/Shear Rams VBRs (i) VBRs in Lower Cavity 5. Diverter System (Requirements of 20 AAC 25.005(c)(7)) A diverter waiver is requested, as there have been no indications of hydrates on 3T pad. The 3T-614 proposed casing shoe depth has the 3T-613, 3T-617, 3T-612, and 3T-619 surface shoes within 500’. 6. MASP Calculations Requirements of 20 AAC 25.005(c)(4) 10 te10xt here 3T-614 PTD Page 7 of 10 (A) maximum downhole pressure and maximum potential surface pressure; Maximum Potential Surface Pressure (MPSP) is determined as the lesser of: Method 1: surface pressure at breakdown of the formation casing seat with a gas gradient to the surface Method 2: formation pore pressure at the next casing point less a gas gradient to the surface Method 1 Method 2 ܯܲܵܲ = [(ܨܩ × 0.052 )െܩܽݏ ܩݎܽ݀݅݁݊ݐ] × ܸܶܦ ܯܲܵܲ = ܨܲܲ െ (ܩܽݏ ܩݎܽ݀݅݁݊ݐ) × ܸܶܦ Where: FG – Fracture gradient at the casing seat in lb/gal 0.052 – Conversion from lb/gal to psi/ft Gas Gradient – 0.1 psi/ft TVD – True Vertical Depth of casing seat in ft RKB Where: FPP – Formation Pore Pressure at the next casing point Gas Gradient – 0.1 psi/ft The following presents data used for calculation of Maximum Potential Surface Pressure (MPSP) while drilling: Section Hole Size Previous CSG Section TD MPSP psi MPSP MPSP Size MD TVD FG ppg Pore Pressure ppg | psi MD TVD Pore Pressure ppg | psi Method 1 psi Method 2 psi SURF 13 1/2 20 119.1 119.1 10.9 8.6 53 2,785 2,490 8.6 2,261 56 56 864 INTRM 9 7/8 10 3/4 2,785 2,490 13.0 8.6 1,113 11,300 5,058 8.6 2,346 1,434 1,434 1,756 PROD 6 1/2 7 5/8 11,300 5,058 13.0 8.6 2,346 24,551 5,186 8.6 2,300 1,828 2,913 1,828 (B) data on potential gas zones; The well bore is not expected to penetrate any shallow gas zones. (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Drilling Hazards Summary 7. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) Drill out the casing shoe and perform LOT/FIT as per the procedure that ConocoPhillips Alaska has on file with the Commission. 8. Casing and Cementing Program Requirements of 20 AAC 25.005 (c)(6) Casing and Cementing Program Csg/Tbg OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H40 Welded Cemented to surface with 10 yds slurry 10 3/4 13 1/2 45.50 L80 Hyd563 Cement to Surface 3T-614 PTD Page 8 of 10 7 5/8 9 7/8 29.70 33.70 L80 P110-S Hyd563 250’ TVD above upper most producing zone (Coyote) 4 1/2 6 1/2 12.60 P110-S Hyd563 Cemented liner with frac sleeves Cementing Calculations 10 3/4” Surface Casing run to 2,785 ’ MD / 2,490 ’ TVD Cement 2,785 MD to 2,285 (500’ of tail) with Class G + Add's @ 15.8 PPG, and from 2,285' to surface with 11 ppg Arctic Lite Crete. Assume 225% excess annular volume in permafrost and 50% excess below the permafrost (1,590 ’ MD), zero excess in 20” conductor. Lead 2,286ft3 => 902 sx of 11 ppg Class G + Add's @ 2.5346 ft3 /sk Tail 316 ft3 => 273 sx of 15.8ppg Class G + Add's @ 1.1582 ft3/sk 7 5/8” Intermediate Casing run to 11300’ MD / 5,058 ’ TVD Top of slurry is designed to be at 7,418 ’ MD, which is 250’ TVD above the prognosis shallowest hydrocarbon bearing zone, Coyote. If a shallower hydrocarbon zone of producible volumes is encountered while drilling, a 2-stage cement job will be performed to isolate this zone. Assume 45% excess annular volume. Lead 900ft3 => 588 sx of 14 ppg Class G + Add's@ 1.53 ft3 /sk assuming 45% excess in 9 7/8” hole Tail 33 ft3 => 269 sx of 15.3 ppg Class G + Add's @ 1.24 ft3/sk assuming 45% excess in 9 7/8” hole 4 1/2” Production Liner run from 11,300 MD / 5,058 ’ TVD to 24,551 MD / 5,186 TVD Cement the liner from TD to the liner top using a 13.5 ppg Class G + Add's cement. Assume 30% excess annular volume in the open hole, and 0% excess in the 7 5/8” intermediate casing. Tail 2,126 ft3 => 1,143 sx of 13.5 ppg Class G + Add's @ 1.86 ft3/sk assuming 30% excess in 6 1/2” hole 9. Drilling Fluid Program Requirements of 20 AAC 25.005(c)(8)) Surface Intermediate Production Hole Size in. 13 1/2 9 7/8 6 1/2 Casing Size in. 10 3/4 7 5/8 4 1/2 Density PPG 8.6 – 9.8 9.0 – 9.5 9.0 – 10 PV cP 20-50 <22 <20 YP lb./100 ft2 30 - 80 20 - 30 9-13 Funnel Viscosity s/qt. 250 – 300 40-60 35-50 Initial Gels lb./100 ft2 30 - 50 8 - 15 5- 10 10 Minute Gels lb./100 ft2 50 - 70 <20 7 - 15 API Fluid Loss cc/30 min. N.C. – 8.0 < 10.0 < 6.0 HPHT Fluid Loss cc/30 min. N/A < 10.0 < 2.0 pH 9.5-10 9-10 9-10 Surface Hole: A water based spud mud will be used for the surface interval. Mud engineer to perform regular mud checks to maintain proper specifications. The mud weight will be maintained at 9.8 ppg by use of solids control system and dilutions where necessary. Intermediate: TS 10/1/25 3T-614 PTD Page 9 of 10 Fresh water polymer mud system. Ensure good hole cleaning by pumping regular sweeps and maximizing fluid annular velocity. Maintain mud weight at or below 9.6 ppg for formation stability and be prepared to add loss circulation material if necessary. Good filter cake quality, hole cleaning and maintenance of low drill solids (by diluting as required) will all be important. The mud will be weighted up to 9.5 ppg before pulling out of the hole. Production Hole: The horizontal production interval will be drilled with a Non-Aqueous Fluid (NAF) mud system weighted to 9.0 – 10 ppg. MPD will be utilized to add back pressure during connections to minimize pressure cycling. Diagram of Doyon 142 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. 10. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) N/A - Application is not for an exploratory or stratigraphic test well. 12. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) N/A - Application is not for an offshore well. 13. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 14. Discussion of Mud and Cuttings Disposal and Annular Disposal Requirements of 20 AAC 25.005 (c)(14) Waste fluids and cuttings generated during the drilling process will be disposed of by hauling the fluids to a KRU Class II disposal well at the 1B Facility. If needed, excess cuttings generated will be hauled to Milne Point or Prudhoe Bay Grind and Inject Facility for temporary storage and eventual processing for injection down an approved disposal well, or stored, tested for hazardous substances, and (if free of hazardous substances) used on pads and roads in the Kuparuk area in accordance with a permit from the State of Alaska. 15. Drilling Hazards Summary 13 1/2" Hole / 10 3/4” Casing Interval Event Risk Level Mitigation Strategy Conductor Broach Low Monitor cellar continuously during interval. Well Collision Low Follow real time surveys very closely, gyro survey as needed to ensure survey accuracy. Gas Hydrates Low If observed – control drill, reduce pump rates and circulating time, reduce mud temperatures Hole Swabbing on Trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out Washouts/Hole Sloughing Low Cool mud temperatures, minimize circulating times when possible Running sands and gravels Low Maintain planned mud properties, increase mud weight, use weighted sweeps 10 text here 3T-614 PTD Page 10 of 10 Lost Circulation Moderate Monitor ECDs for signs of packoff before losses occur. Keep hole clean and utilize LCM sweeps to regain circulation. 9 7/8” Hole /7 5/8” Casing Interval Event Risk Level Mitigation Strategy Sloughing shale / Tight hole / Stuck Pipe Low Good hole cleaning, pre-treatment with LCM, stabilized BHA, maintain planned mud weights and adjust as needed, real time equivalent circulating density (ECD) monitoring Lost circulation Moderate Reduce pump rates, reduce trip speeds, real time ECD monitoring, mud rheology, add lost circulation material Hole swabbing on trips Moderate Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring, Liner will be in place at TD Abnormal Reservoir Pressure (Coyote / K3) Low Well control drills, check for flow during connections, increase mud weight if necessary. 6 1/2” Hole / 4 1/2” Liner - Horizontal Production Interval Event Risk Level Mitigation Strategy Lost circulation Moderate Reduce pump rates, real time ECD monitoring, maintain mud rheology, add lost circulation material Hole swabbing on trips Moderate Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring Abnormal Reservoir Pressure Low Well control drills, check for flow during connections, increased mud weight Differential Sticking Moderate Uniform reservoir pressure along lateral, keep pipe moving, control mud weight Running Liner to Bottom Moderate Properly clean hole on the trip out with BHA, perform clean out run if necessary, utilize super sliders for weight transfer if needed, monitor T&D real time Well Proximity Risks: 3T is a multi-well pad, with several existing wells. Directional drilling/collision avoidance information as required by AOGCC 20 ACC 25.050 (b) is provided in the following attachments. Drilling Area Risks: Reservoir Pressure: Unlikely to encounter any abnormal pressure, however, the rig will be prepared to weight up if required. Weak sand stringers could be present in the overburden. LCM material will be available to seal in losses in the intermediate section. The overburden logs will be evaluated to ensure no hydrocarbon bearing zones are above the known Coyote. If identified, the primary intermediate cement job will be replanned to cover the zone as per the agency regulations. Lost Circulation: Standard LCM material and wellbore strengthening pills are expected to be effective in dealing with lost circulation if needed. Good drilling practices will be stressed to minimize the potential of taking swabbed kicks. 3T-614 PTD Page 11 of 10 16. Proposed Completion Schematic 39 500 500 1000 1000 1500 1500 2000 2000 3000 3000 5000 5000 10000 10000 24552 3T-614 wp14 Plan Summary 0 4 Dogleg Severity0 4000 8000 12000 16000 20000 24000 Measured Depth 10-3/4" Surface Casing 7-5/8" Intermediate Casing 4-1/2" Production Liner 30.0 30.0 60.0 60.0 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in] 39 100200300 400500601701802 902100311041204130514051506160617071807190820082108 2207 2307 2406 3T-617 39100200300400500599699 798 897 995 1093 1190 1288 3T-612 39 10020030040050060070080090010001099119912991399149915991699179918991999209921992299239924992599269927982898299730963195 3T-613 39100200300 400 499 597 3T-616 39100200300 400 499 597 39100200300 400 499 597 39 100200300 400500601701802 902100311041204130514051506160617071807190820082108 2207 2307 2406 3T-617 39100200300400500599698 3T-611 wp11 39100200300400500600701801901100211021203130414051507160717081811 3T-615 wp09.1 0 3000 True Vertical Depth-6000 -4000 -2000 0 2000 4000 6000 Vertical Section at 166.00° 10-3/4" Surface Casing 7-5/8" Intermediate Casing 4-1/2" Production Liner 18 35 Centre to Centre Separation0 425 850 1275 1700 2125 2550 2975 Measured Depth Equivalent Magnetic Distance DDI 7.486 SURVEY PROGRAM Date: 2019-07-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 39.00 2780.00 3T-614 wp14 (3T-614) r.5 SDI_URSA1 2780.00 11300.00 3T-614 wp14 (3T-614) MWD+IFR2+SAG+MS 11300.00 24551.34 3T-614 wp14 (3T-614) MWD+IFR2+SAG+MS Ground / 12.00 CASING DETAILS TVD MD Name 2489.76 2784.66 10-3/4" Surface Casing 5057.78 11300.00 7-5/8" Intermediate Casing 5186.00 24551.34 4-1/2" Production Liner Mag Model & Date: BGGM2025 10-Nov-25 Magnetic North is 13.49° East of True North (Magnetic Declinatio Mag Dip & Field Strength: 80.59° 57148.30nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 39.00 0.00 0.00 39.00 0.00 0.00 0.00 0.00 0.002 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.003 500.00 2.00 318.00 499.96 2.59 -2.34 1.00 318.00 -3.08 Start Build 2.004 1539.86 22.80 318.00 1510.00 167.61 -150.91 2.00 0.00 -199.14 Start 108.47 hold at 1539.86 MD5 1648.33 22.80 318.00 1610.00 198.84 -179.04 0.00 0.00 -236.25 Start Build 2.756 2701.31 51.75 318.00 2439.00 667.74 -601.24 2.75 0.00 -793.36 Start 20.00 hold at 2701.31 MD7 2721.31 51.75 318.00 2451.38 679.42 -611.75 0.00 0.00 -807.23 Start DLS 3.00 TFO -0.558 3477.79 74.45 317.78 2791.40 1176.55 -1061.27 3.00 -0.55 -1398.35 Start 5152.63 hold at 3477.79 MD9 8630.42 74.45 317.78 4172.91 4852.81 -4396.86 0.00 0.00 -5772.35 Start DLS 3.75 TFO -106.161012160.11 89.00 183.00 5161.32 3866.35 -6818.60 3.75 -106.16 -5401.07 Start 600.00 hold at 12160.11 MD 11 12760.11 89.00 183.00 5171.79 3267.26 -6850.00 0.00 0.00 -4827.37 3T Harper T01 062725 Start DLS 3.00 TFO -91.57 12 13174.58 88.68 170.57 5180.20 2854.34 -6826.80 3.00 -91.57 -4421.10 Start 236.52 hold at 13174.58 MD 13 13411.10 88.68 170.57 5185.62 2621.08 -6788.05 0.00 0.00 -4185.40 Start DLS 2.00 TFO -70.30 14 13605.89 90.00 166.90 5187.86 2430.10 -6750.00 2.00 -70.30 -3990.89 3T Harper T02 062525 Start DLS 2.00 TFO -69.42 15 13752.99 91.03 164.15 5186.53 2287.69 -6713.23 2.00 -69.42 -3843.81 Start 1441.71 hold at 13752.99 MD 16 15194.70 91.03 164.15 5160.52 901.05 -6319.43 0.00 0.00 -2403.10 Start DLS 1.00 TFO 140.42 1715328.82 90.00 165.00 5159.31 771.77 -6283.75 1.00 140.42 -2269.02 3T Harper T03 062425 Start DLS 1.00 TFO 138.66 18 15441.06 89.16 165.74 5160.14 663.17 -6255.40 1.00 138.66 -2156.79 Start 1771.57 hold at 15441.05 MD 19 17212.63 89.16 165.74 5186.19 -1053.64 -5819.11 0.00 0.00 -385.43 Start DLS 1.00 TFO -0.77 2017296.91 90.00 165.73 5186.81 -1135.31 -5798.35 1.00 -0.77 -301.16 3T Harper T04 062425 Start DLS 1.00 TFO -0.93 21 17349.45 90.53 165.72 5186.57 -1186.23 -5785.39 1.00 -0.93 -248.62 Start 1433.99 hold at 17349.45 MD 22 18783.44 90.53 165.72 5173.42 -2575.87 -5431.73 0.00 0.00 1185.30 Start DLS 1.00 TFO 177.98 2318836.01 90.00 165.74 5173.18 -2626.81 -5418.78 1.00 177.98 1237.87 3T Harper T05 062425 Start DLS 1.00 TFO 179.21 2418917.39 89.19 165.75 5173.76 -2705.68 -5398.74 1.00 179.21 1319.24 Start 939.42 hold at 18917.38 MD 2519856.81 89.19 165.75 5187.10 -3616.11 -5167.54 0.00 0.00 2258.56 Start DLS 1.50 TFO -179.94 2619935.90 88.00 165.75 5189.04 -3692.74 -5148.08 1.50 -179.94 2337.62 3T Harper T06 062425 Start DLS 1.50 TFO -173.77 2719968.21 87.52 165.70 5190.30 -3724.03 -5140.12 1.50 -173.77 2369.90 Start 1138.36 hold at 19968.20 MD 28 21106.57 87.52 165.70 5239.60 -4826.08 -4859.16 0.00 0.00 3507.18 Start DLS 1.50 TFO 1.68 29 21272.09 90.00 165.77 5243.18 -4986.44 -4818.38 1.50 1.68 3672.65 3T Harper T07 062425 Start DLS 1.50 TFO 2.07 3021360.62 91.33 165.82 5242.15 -5072.25 -4796.66 1.50 2.07 3761.17 Start 1748.40 hold at 21360.61 MD 31 23109.02 91.33 165.82 5201.66 -6766.91 -4368.41 0.00 0.00 5509.09 Start DLS 1.00 TFO 177.90 32 23141.74 91.00 165.83 5201.00 -6798.63 -4360.40 1.00 177.90 5541.81 3T Harper T08 062625 Start DLS 1.00 TFO 179.82 33 23181.33 90.60 165.83 5200.45 -6837.01 -4350.71 1.00 179.82 5581.39 Start 1370.01 hold at 23181.32 MD 34 24551.34 90.60 165.83 5186.00 -8165.27 -4015.38 0.00 0.00 6951.32 3T Harper T09 QM TD at 24551.34 FORMATION TOP DETAILS TVDPath Formation 1343.17 Ugnu C 1556.22 Base Perm 1982.50 West Sak 2393.79 West Sak Base 2601.55 C-80 2731.51 C-50 3796.40 C-35 4097.72 Coyote 4178.36 Base Coyote 5046.68 Moraine 5171.56 Mid Moraine By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet lateral tolerance. Prepared by Checked by Accepted by Approved by Plan 12+39 @ 51.00usft (D142) -20000200040006000True Vertical Depth-6000 -4000 -2000 0 2000 4000 6000Vertical Section at 166.00°10-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner1000200030004 0 0 0 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 100001100012000130001400 0 1500016000170001800019000200002100022000 23000 24000 2 4 55 1 0°30°60°7 4 °89°89°90°91 °89°91°89°88°9 1° 91 ° 3T-614 wp14 Ugnu CBase PermWest SakWest Sak BaseC-80C-50C-35CoyoteBase CoyoteMoraineMid Moraine3T-614 wp1416:53, August 12 2025Section View -7500-5000-2500025005000South(-)/North(+)-12500 -10000 -7500 -5000 -2500 0 2500 5000West(-)/East(+)10-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner50010001500200025003000350040004500500051863T-614 wp143T-614 wp14While drilling production section, stay within 100 feet laterally of plan, unless notified otherwise.16:48, August 12 20253ODQ9LHZ 10 text here 10/02/ 0.000.751.502.253.003.754.505.256.006.757.50Separation Factor-1500 0 1500 3000 4500 6000 7500 9000 10500 12000 13500 15000 16500 18000 19500 21000 22500 24000 25500Measured Depth (3000 usft/in)Nuna 1PB13S-6253T-616PB23T-6193T-6213T-615 wp09.13T-618 wp07STOP DrillingTake Immediate ActionCaution - Monitor CloselyNormal OperationsProject: Kuparuk River Unit_2Site: Kuparuk 3T PadWell: 3T-614Wellbore: 3T-614Design: 3T-614 wp14 0 35 Centre to Centre Separation0 500 1000 1500 2000 2500 Partial Measured Depth3T-6123T-6133T-6163T-616PB13T-616PB23T-6173T-611 wp113T-615 wp09.13T-617Equivalent Magnetic Distance 3T-614 wp14 Ladder View 0 150 300 Centre to Centre Separation0 4000 8000 12000 16000 20000 24000 Measured DepthNDST-02NDST-02PB1Nuna 1Nuna 1PB13T-6033T-6053T-6083T-6123T-6133T-6163T-616PB13T-616PB23T-6173T-6193T-619 wp07.23T-6213T-622 wp103T-7313T-602 wp05 v53T-604 wp05 v53T-606 wp083T-607 wp053T-609 wp063T-610 wp053T-611 wp113T-615 wp09.13T-618 wp073T-620 wp05 v53T-623 wp05 v53T-624 wp05 v53T-617Equivalent Magnetic Distance SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 39.00 2780.00 3T-614 wp14 (3T-614) r.5 SDI_URSA1 2780.0011300.00 3T-614 wp14 (3T-614) MWD+IFR2+SAG+MS 11300.00 24551.34 3T-614 wp14 (3T-614) MWD+IFR2+SAG+MS 7:22, August 13 2025 CASING DETAILS TVD MD Name 2489.76 2784.66 10-3/4" Surface Casing 5057.78 11300.007-5/8" Intermediate Casing 5186.00 24551.34 4-1/2" Production Liner 39 500 500 1000 1000 1500 1500 2000 2000 3000 3000 5000 5000 10000 10000 26000 3T-614 wp14 TC View 30 30 60 60 90 90 120 120 150 150 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in] 39100200300400499598697796894 992 1089 3T-608 39100200300400500599699798 897 995 1093 1190 1288 1385 1482 1580 1679 1774 1870 1965 2059 2153 2247 2340 3T-612 39 10020030040050060070080090010001099119912991399149915991699179918991999209921992299239924992599269927982898299730963195 329433933491359136913791 3891 3990 4090 4189 4289 4388 4488 4587 4687 4787 3T-613 39100200300 400 499 597 694 790 885 977 3T-616 39100200300 400 499 597 694 790 885 977 39100200300 400 499 597 694 790 885 977 39 100200 300 400500601701802 9021003110412041305140515061606170718071908200821082207 2307 2406 2504 2602 2700 2797 2891 2984 3075 3T-617 39100200300400499598696 3T-606 wp08 39100200300400500599698796 3T-607 wp05 39100200300400500599698797 895 994 10911189 1286 3T-609 wp06391002003004005005996997988979961095 1194 1292 1390 3T-610 wp05 391002003004005005996987978969941092119012881385148215801678177318681962 3T-611 wp11 39100200300400500600701801901100211021203130414051507160717081811191420172121 22252329 2434 2539 2644 2750 2856 296430723181 3290 3T-615 wp09.1 39100200300400500601701802902100211031203130314041504160417041804190420042104 2204 2304 2404 3T-618 wp07 39 100200300 400500601701802 9021003110412041305140515061606170718071908200821082207 2307 2406 2504 2602 2700 2797 2891 2984 3075 SURVEY PROGRAM Date: 2019-07-03T00:00:00 Validated: Yes Version: From To Tool 39.00 2780.00 r.5 SDI_URSA1 2780.00 11300.00 MWD+IFR2+SAG+MS 11300.00 24551.34 MWD+IFR2+SAG+MS CASING DETAILS TVD MD Name 2489.76 2784.66 10-3/4" Surface Casing 5057.78 11300.00 7-5/8" Intermediate Casing 5186.00 24551.34 4-1/2" Production Liner SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 39.00 0.00 0.00 39.00 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.00 3 500.00 2.00 318.00 499.96 2.59 -2.34 1.00 318.00 -3.08 Start Build 2.00 4 1539.86 22.80 318.00 1510.00 167.61 -150.91 2.00 0.00 -199.14 Start 108.47 hold at 1539.86 MD 5 1648.33 22.80 318.00 1610.00 198.84 -179.04 0.00 0.00 -236.25 Start Build 2.75 6 2701.31 51.75 318.00 2439.00 667.74 -601.24 2.75 0.00 -793.36 Start 20.00 hold at 2701.31 MD 7 2721.31 51.75 318.00 2451.38 679.42 -611.75 0.00 0.00 -807.23 Start DLS 3.00 TFO -0.55 8 3477.79 74.45 317.78 2791.40 1176.55 -1061.27 3.00 -0.55 -1398.35 Start 5152.63 hold at 3477.79 MD 9 8630.42 74.45 317.78 4172.91 4852.81 -4396.86 0.00 0.00 -5772.35 Start DLS 3.75 TFO -106.16 1012160.11 89.00 183.00 5161.32 3866.35 -6818.60 3.75 -106.16 -5401.07 Start 600.00 hold at 12160.11 MD 1112760.11 89.00 183.00 5171.79 3267.26 -6850.00 0.00 0.00 -4827.37 3T Harper T01 062725 Start DLS 3.00 TFO -91.57 1213174.58 88.68 170.57 5180.20 2854.34 -6826.80 3.00 -91.57 -4421.10 Start 236.52 hold at 13174.58 MD 1313411.10 88.68 170.57 5185.62 2621.08 -6788.05 0.00 0.00 -4185.40 Start DLS 2.00 TFO -70.30 1413605.89 90.00 166.90 5187.86 2430.10 -6750.00 2.00 -70.30 -3990.89 3T Harper T02 062525 Start DLS 2.00 TFO -69.42 1513752.99 91.03 164.15 5186.53 2287.69 -6713.23 2.00 -69.42 -3843.81 Start 1441.71 hold at 13752.99 MD 1615194.70 91.03 164.15 5160.52 901.05 -6319.43 0.00 0.00 -2403.10 Start DLS 1.00 TFO 140.42 1715328.82 90.00 165.00 5159.31 771.77 -6283.75 1.00 140.42 -2269.02 3T Harper T03 062425 Start DLS 1.00 TFO 138.66 1815441.06 89.16 165.74 5160.14 663.17 -6255.40 1.00 138.66 -2156.79 Start 1771.57 hold at 15441.05 MD 1917212.63 89.16 165.74 5186.19 -1053.64 -5819.11 0.00 0.00 -385.43 Start DLS 1.00 TFO -0.77 2017296.91 90.00 165.73 5186.81 -1135.31 -5798.35 1.00 -0.77 -301.16 3T Harper T04 062425 Start DLS 1.00 TFO -0.93 21 17349.45 90.53 165.72 5186.57 -1186.23 -5785.39 1.00 -0.93 -248.62 Start 1433.99 hold at 17349.45 MD 2218783.44 90.53 165.72 5173.42 -2575.87 -5431.73 0.00 0.00 1185.30 Start DLS 1.00 TFO 177.98 2318836.01 90.00 165.74 5173.18 -2626.81 -5418.78 1.00 177.98 1237.87 3T Harper T05 062425 Start DLS 1.00 TFO 179.21 2418917.39 89.19 165.75 5173.76 -2705.68 -5398.74 1.00 179.21 1319.24 Start 939.42 hold at 18917.38 MD 2519856.81 89.19 165.75 5187.10 -3616.11 -5167.54 0.00 0.00 2258.56 Start DLS 1.50 TFO -179.94 2619935.90 88.00 165.75 5189.04 -3692.74 -5148.08 1.50 -179.94 2337.62 3T Harper T06 062425 Start DLS 1.50 TFO -173.77 2719968.21 87.52 165.70 5190.30 -3724.03 -5140.12 1.50 -173.77 2369.90 Start 1138.36 hold at 19968.20 MD 28 21106.57 87.52 165.70 5239.60 -4826.08 -4859.16 0.00 0.00 3507.18 Start DLS 1.50 TFO 1.68 29 21272.09 90.00 165.77 5243.18 -4986.44 -4818.38 1.50 1.68 3672.65 3T Harper T07 062425 Start DLS 1.50 TFO 2.07 30 21360.62 91.33 165.82 5242.15 -5072.25 -4796.66 1.50 2.07 3761.17 Start 1748.40 hold at 21360.61 MD 31 23109.02 91.33 165.82 5201.66 -6766.91 -4368.41 0.00 0.00 5509.09 Start DLS 1.00 TFO 177.90 32 23141.74 91.00 165.83 5201.00 -6798.63 -4360.40 1.00 177.90 5541.81 3T Harper T08 062625 Start DLS 1.00 TFO 179.82 33 23181.33 90.60 165.83 5200.45 -6837.01 -4350.71 1.00 179.82 5581.39 Start 1370.01 hold at 23181.32 MD 34 24551.34 90.60 165.83 5186.00 -8165.27 -4015.38 0.00 0.00 6951.32 3T Harper T09 081225 TD at 24551.34 3T-614 wp14AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.00 2780.00 r.5 SDI_URSA12780.00 11300.00 MWD+IFR2+SAG+MS11300.00 24551.34 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2489.76 2784.66 10-3/4" Surface Casing5057.78 11300.00 7-5/8" Intermediate Casing5186.00 24551.34 4-1/2" Production Liner1010202030304040505060600901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [20 usft/in]391002003004005005996997988979951093119012883T-6123910020030040050060070080090010001099119912991399149915991699179918991999209921992299239924992599269927983T-613391002003004004995973T-61639100200300400499597391002003004004995973910020030040050060170180290210031104120413051405150616061707180719082008210822072307240625043T-617391002003004005005996987973T-611 wp11391002003004005006007018019011002110212031304140515061607170818113T-615 wp09.139100200300400500601701802902100311041204130514051506160617071807190820082108220723072406250439 500500 10001000 15001500 20002000 30003000 50005000 1000010000 26000From Colour To MD39.00 To 2800.00MD Azi TFace39.00 0.00 0.00300.00 0.00 0.00500.00 318.00 318.001539.86 318.00 0.001648.33 318.00 0.002701.31 318.00 0.002721.31 318.00 0.003477.79 317.78 -0.558630.42 317.78 0.0012160.11 183.00 -106.1612760.11 183.00 0.0013174.58 170.57 -91.5713411.10 170.57 0.0013605.89 166.90 -70.3013752.99 164.15 -69.4215194.70 164.15 0.0015328.82 165.00 140.4215441.06 165.74 138.6617212.63 165.74 0.0017296.91 165.73 -0.7717349.45 165.72 -0.9318783.44 165.72 0.0018836.01 165.74 177.9818917.39 165.75 179.2119856.81 165.75 0.0019935.90 165.75 -179.9419968.21 165.70 -173.7721106.57 165.70 0.0021272.09 165.77 1.6821360.62 165.82 2.0723109.02 165.82 0.0023141.74 165.83 177.9023181.33 165.83 179.8224551.34 165.83 0.00 3T-614 wp14AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.00 2780.00 r.5 SDI_URSA12780.00 11300.00 MWD+IFR2+SAG+MS11300.00 24551.34 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2489.76 2784.66 10-3/4" Surface Casing5057.78 11300.00 7-5/8" Intermediate Casing5186.00 24551.34 4-1/2" Production Liner454590901351351801802252252702700901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [90 usft/in]3836392540134103419242814370445945484637Nuna 1383639254013410341924281437044594548463727102800289229823T-6122798289829973096319532943393349135913691379138913990409041894289438844884587468747874886498650865185528553855485558456845784588459836083618362826382648265813T-613110341097510924108803T-61610790107543T-616PB1270027972891298430753163324733293T-617271828172914301031053200329533883T-6192717281629153013311132093306340310392104451049210534105723T-619 wp07.22750285629643072318132903399350536043702380038983995409341913T-615 wp09.127032803290330023100319832963T-618 wp072700279728912984307531633247332939 500500 10001000 15001500 20002000 30003000 50005000 1000010000 26000From Colour To MD2700.00 To 11400.00MD Azi TFace39.00 0.00 0.00300.00 0.00 0.00500.00 318.00 318.001539.86 318.00 0.001648.33 318.00 0.002701.31 318.00 0.002721.31 318.00 0.003477.79 317.78 -0.558630.42 317.78 0.0012160.11 183.00 -106.1612760.11 183.00 0.0013174.58 170.57 -91.5713411.10 170.57 0.0013605.89 166.90 -70.3013752.99 164.15 -69.4215194.70 164.15 0.0015328.82 165.00 140.4215441.06 165.74 138.6617212.63 165.74 0.0017296.91 165.73 -0.7717349.45 165.72 -0.9318783.44 165.72 0.0018836.01 165.74 177.9818917.39 165.75 179.2119856.81 165.75 0.0019935.90 165.75 -179.9419968.21 165.70 -173.7721106.57 165.70 0.0021272.09 165.77 1.6821360.62 165.82 2.0723109.02 165.82 0.0023141.74 165.83 177.9023181.33 165.83 179.8224551.34 165.83 0.00 3T-614 wp14AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.00 2780.00 r.5 SDI_URSA12780.00 11300.00 MWD+IFR2+SAG+MS11300.00 24551.34 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2489.76 2784.66 10-3/4" Surface Casing5057.78 11300.00 7-5/8" Intermediate Casing5186.00 24551.34 4-1/2" Production Liner454590901351351801802252252702700901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [90 usft/in]1379913729136581358613514134423T-622 wp1039 500500 10001000 15001500 20002000 30003000 50005000 1000010000 26000From Colour To MD11300.00 To 24552.00MD Azi TFace39.00 0.00 0.00300.00 0.00 0.00500.00 318.00 318.001539.86 318.00 0.001648.33 318.00 0.002701.31 318.00 0.002721.31 318.00 0.003477.79 317.78 -0.558630.42 317.78 0.0012160.11 183.00 -106.1612760.11 183.00 0.0013174.58 170.57 -91.5713411.10 170.57 0.0013605.89 166.90 -70.3013752.99 164.15 -69.4215194.70 164.15 0.0015328.82 165.00 140.4215441.06 165.74 138.6617212.63 165.74 0.0017296.91 165.73 -0.7717349.45 165.72 -0.9318783.44 165.72 0.0018836.01 165.74 177.9818917.39 165.75 179.2119856.81 165.75 0.0019935.90 165.75 -179.9419968.21 165.70 -173.7721106.57 165.70 0.0021272.09 165.77 1.6821360.62 165.82 2.0723109.02 165.82 0.0023141.74 165.83 177.9023181.33 165.83 179.8224551.34 165.83 0.00 3T-614 wp14Spider Plot7:33, August 13 2025 To 24552.00Northing (6500 usft/in)Easting (6500 usft/in)3035404550NDST-023035404550NDST-02PB13035404550Nuna 13035404550Nuna 1PB130 354045503S-6253035403S-740 (I15) wp0330354045503T-61730354045503T-60330354045503T-60530354045503T-60830354045503T-61230354045503T-61330354045503T-61630354045503T-616PB130354045503T-616PB230354045503T-6173035403T-61930354045503T-619 wp07.2303540455 0553T-62130354045503T-622 wp103035403T-7303035403T-7313 0 3 5 4 0 4 5503T-601 wp05 v53 0 3 5 4 0 4 5503T-602 wp05 v530354045503T-604 wp05 v530354045503T-606 wp0830354045503T-607 wp0530354045503T-609 wp0630354045503T-610 wp0530354045503T-611 wp1130354 0 45503T-615 wp09.130354 0 45503T-618 wp073035404 5 503T-620 wp05 v53035404 5 503T-623 wp05 v530354045503T-624 wp05 v530354045503T-625 wp07.13035404 5 503T-626 wp05 v530354045503T-627 wp05 v53 0 3 5 4 0 45 503T-628 wp0630354045503T-629 wp05 v530354045503T-614 wp14 3T-614 wp14Spider Plot7:35, August 13 2025 To 24552.00Northing (2500 usft/in)Easting (2500 usft/in)3035404550NDST-023035404550NDST-02PB13035404550Nuna 13035404550Nuna 1PB13S-62530354045503T-61730354045503T-60330354045503T-605303540453T-60830354045503T-612303540453T-61330354045503T-61630354045503T-616PB130354045503T-616PB230354045503T-6173035403T-61930354045503T-619 wp07.2303540455 0553T-62130354045503T-622 wp103035403T-7303035403T-7313 0 3 5 4 0 4 5503T-601 wp05 v53 0 3 5 4 0 4 5503T-602 wp05 v530354045503T-604 wp05 v530354045503T-606 wp0830354045503T-607 wp0530354045503T-609 wp0630354045503T-610 wp0530354045503T-611 wp1130354 0 45503T-615 wp09.130354 0 45503T-618 wp073035404 5 503T-620 wp05 v53035404 5 503T-623 wp05 v530354045503T-624 wp05 v530354045503T-625 wp07.13035404 5 503T-626 wp05 v53035403T-627 wp05 v53 0 3 5 4 0 4 5 503T-628 wp0630354045503T-629 wp05 v530354045503T-614 wp14 3T-614 wp14Spider Plot7:38, August 13 2025 To 24552.00Northing (750 usft/in)Easting (750 usft/in)3032343638NDST-023032343638NDST-02PB130323436384042444648Nuna 1303234363840424446485052Nuna 1PB13S-62530323436384042444648503T-6173032343T-60330323T-6053032343638403T-60830323436384042444648503T-612303234363T-6133T-6163T-616PB13T-616PB230323436384042444648503T-617303234363840423T-619303234363840423T-619 wp07.2303234363840424446485 052543T-6213032343638404244463T-622 wp10303234363T-73030323436383T-7313T-601 wp05 v53T-602 wp05 v53T-604 wp05 v53T-606 wp083032343638403T-607 wp05303234363840423T-609 wp063032343638403T-610 wp0530323436384042444648503T-611 wp113032343T-615 wp09.13032343T-618 wp0730323436383T-620 wp05 v5303234363T-623 wp05 v53032343638403T-624 wp05 v53032343638403T-625 wp07.13032343T-626 wp05 v53T-627 wp05 v53 0 3 2 3 4 3 63T-628 wp0630323436383T-629 wp05 v530323436383T-614 wp14 3T-614 wp14Spider Plot7:39, August 13 2025 To 24552.00Northing (350 usft/in)Easting (350 usft/in)1416182022NDST-021416182022NDST-02PB114161820222426283032Nuna 114161820222426283032Nuna 1PB11416182022242628303234363840423T-617141618202224263T-60314161820222426283T-605141618202224262830323T-6081416182022242628303234363T-61214161820222426283T-61314163T-61614163T-616PB114163T-616PB21416182022242628303234363840423T-617141618202224262830323T-619141618202224262830323T-619 wp07.214161820222426283T-621141618202224262830323T-622 wp101416182022242 6 28303234363T-7301416182022242 62830 323436383T-73114161 8 2 03T-601 wp05 v51 4 1 6 1 83T-602 wp05 v51416182022243T-604 wp05 v5141618202224263T-606 wp081416182022242628303T-607 wp05141618202224262830323T-609 wp061416182022242628303T-610 wp051416182022242628303234363T-611 wp11141618202224263T-615 wp09.11416182022242628303T-618 wp0714161820222426283T-620 wp05 v514161820222426283T-623 wp05 v51416182022242628303T-624 wp05 v514161820222426283T-625 wp07.1141618202224263T-626 wp05 v53T-627 wp05 v5141618202224262 83T-628 wp061416182022242628303T-629 wp05 v51416182022242628303T-614 wp14 3T-614 wp14Spider Plot7:40, August 13 2025 To 24552.00Northing (150 usft/in)Easting (150 usft/in)10121416NDST-0210121416NDST-02PB114Nuna 114Nuna 1PB124681012141618202224263T-617246810121416183T-6032468101214161820223T-6052468101214161820223T-6082468 1012141618202224263T-612246810121416182022243T-61324681012143T-61624681012143T-616PB124681012143T-616PB224681012141618202224263T-617246810121416182022243T-619246810121416182022243T-619 wp07.224 681012141618203T-62102468101214161820223T-622 wp102681012141618203T-730810121416182022242 62830 3234363T-73124681012141 61 83T-601 wp05 v5246 8 1 0 1 2 1 4 1 63T-602 wp05 v524681012141618203T-604 wp05 v52468101214161820223T-606 wp082468101214161820223T-607 wp052468101214161820223T-609 wp062468101214161820223T-610 wp0524681012141618202224263T-611 wp112468101214161820223T-615 wp09.1246810121416182022243T-618 wp072468101214161820223T-620 wp05 v524681012141618203T-623 wp05 v524681012141618203T-624 wp05 v5246810121416183T-625 wp07.1246810121416183T-626 wp05 v524683T-627 wp05 v5246810121416183T-628 wp0624681012141618203T-629 wp05 v5246810121416182022243T-614 wp14 -9000-6000-3000030006000South(-)/North(+) (3000 usft/in)-15000 -12000 -9000 -6000 -3000 0 3000 6000 9000West(-)/East(+) (3000 usft/in)NDST-02515052005250NDST-02PB15150Nuna 1515052005250Nuna 1PB15150520052503S-6253S-740 (I15) wp0351503T-6173T-6033T-6053T-608515052003T-6123T-613515052003T-6165150520052503T-616PB1515052003T-616PB251503T-6173T-6193T-619 wp07.251505 2 0 05250 3 T -6 2 1 51503T-622 wp103T-7303T-73151503T-601 wp05 v551503T-602 wp05 v53T-604 wp05 v53T-606 wp083T-607 wp0551503T-609 wp063T-610 wp0551503T-611 wp11515052003T-615 wp09.1515052003T-618 wp07515052003T-620 wp05 v5515052003T-623 wp05 v53T-624 wp05 v53T-625 wp07.1515052003T-626 wp05 v551503T-627 wp05 v53T-628 wp063T-629 wp05 v5515052003T-614 wp143T-614 wp14Quarter Mile View8:23, August 13 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T Harper T01 062725 5171.79 Circle (Radius: 100.00)3T Harper T02 062525 5187.86 Circle (Radius: 100.00)3T Harper T03 062425 5159.31 Circle (Radius: 100.00)3T Harper T04 062425 5186.81 Circle (Radius: 100.00)3T Harper T05 062425 5173.18 Circle (Radius: 100.00)3T Harper T06 062425 5189.04 Circle (Radius: 100.00)3T Harper T07 062425 5243.18 Circle (Radius: 100.00)3T Harper T08 062625 5201.00 Circle (Radius: 100.00)3T Harper T09 QM 5186.00 Circle (Radius: 1320.00)3T Harper T01 QM 5171.79 Circle (Radius: 1320.00)3T Harper T05 QM 5173.18 Circle (Radius: 1320.00)3T Harper T09 062625 5186.00 Circle (Radius: 100.00) -9000-6000-3000030006000South(-)/North(+) (3000 usft/in)-15000 -12000 -9000 -6000 -3000 0 3000 6000 9000West(-)/East(+) (3000 usft/in)515052003T-6165150520052503T-616PB1515052003T-616PB210-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner515052003T-614 wp143T-614 wp14Quarter Mile View8:24, August 13 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T Harper T01 062725 5171.79 Circle (Radius: 100.00)3T Harper T02 062525 5187.86 Circle (Radius: 100.00)3T Harper T03 062425 5159.31 Circle (Radius: 100.00)3T Harper T04 062425 5186.81 Circle (Radius: 100.00)3T Harper T05 062425 5173.18 Circle (Radius: 100.00)3T Harper T06 062425 5189.04 Circle (Radius: 100.00)3T Harper T07 062425 5243.18 Circle (Radius: 100.00)3T Harper T08 062625 5201.00 Circle (Radius: 100.00)3T Harper T09 QM 5186.00 Circle (Radius: 1320.00)3T Harper T01 QM 5171.79 Circle (Radius: 1320.00)3T Harper T05 QM 5173.18 Circle (Radius: 1320.00)3T Harper T09 062625 5186.00 Circle (Radius: 100.00) 3T-614 wp14Nuna 1Nuna 1PB13S-6253T-6163T-616PB13T-616PB23T-6193T-6213T-615 wp09.13T-627 wp05 v53-D View3T-614 wp149:33, August 13 2025 3T-614 wp14NDST-02NDST-02PB1Nuna 1Nuna 1PB13S-6253T-6163T-616PB13T-616PB23T-6193T-6213T-615 wp09.13T-618 wp073-D View3T-614 wp149:33, August 13 2025 -350035070010501400South(-)/North(+) (350 usft/in)-1750 -1400 -1050 -700 -350 0 350 700West(-)/East(+) (350 usft/in)NDST-022490Nuna 1249024903T-61724903T-60324903T-60524903T-60824903T-61224903T-6133T-6163T-616PB13T-616PB2249024903T-61924903 T -6 2 1 24903T-622 wp102 4 9 0 3T-73024 9 0 3T-7313T-601 wp05 v53T-602 wp05 v524903T-604 wp05 v524903T-606 wp0824903T-607 wp0524903T-609 wp0624903T-610 wp0524903T-611 wp1124903T-615 wp09.124903T-618 wp0724903T-620 wp05 v524903T-623 wp05 v524903T-624 wp05 v524903T-625 wp07.124903T-626 wp05 v53T-627 wp05 v524903T-628 wp0624903T-629 wp05 v510-3/4" Surface Casing24903T-614 wp143T-614 wp14Surface Casing 500'r9:28, August 13 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T Harper T01 062725 5171.79 Circle (Radius: 100.00)3T Harper T02 062525 5187.86 Circle (Radius: 100.00)3T Harper T03 062425 5159.31 Circle (Radius: 100.00)3T Harper T04 062425 5186.81 Circle (Radius: 100.00)3T Harper T05 062425 5173.18 Circle (Radius: 100.00)3T Harper T06 062425 5189.04 Circle (Radius: 100.00)3T Harper T07 062425 5243.18 Circle (Radius: 100.00)3T Harper T08 062625 5201.00 Circle (Radius: 100.00)3T Harper T09 QM 5186.00 Circle (Radius: 1320.00)3T -614 Srf Csg 2489.76 Circle (Radius: 500.00)3T Harper T01 QM 5171.79 Circle (Radius: 1320.00)3T Harper T05 QM 5173.18 Circle (Radius: 1320.00)3T Harper T09 062625 5186.00 Circle (Radius: 100.00) -350035070010501400South(-)/North(+) (350 usft/in)-1750 -1400 -1050 -700 -350 0 350 700West(-)/East(+) (350 usft/in)24903T-61724903T-61224903T-61324903T-61924 9 0 3T-73110-3/4" Surface Casing24903T-614 wp143T-614 wp14Surface Casing 500'r9:32, August 13 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T Harper T01 062725 5171.79 Circle (Radius: 100.00)3T Harper T02 062525 5187.86 Circle (Radius: 100.00)3T Harper T03 062425 5159.31 Circle (Radius: 100.00)3T Harper T04 062425 5186.81 Circle (Radius: 100.00)3T Harper T05 062425 5173.18 Circle (Radius: 100.00)3T Harper T06 062425 5189.04 Circle (Radius: 100.00)3T Harper T07 062425 5243.18 Circle (Radius: 100.00)3T Harper T08 062625 5201.00 Circle (Radius: 100.00)3T Harper T09 QM 5186.00 Circle (Radius: 1320.00)3T -614 Srf Csg 2489.76 Circle (Radius: 500.00)3T Harper T01 QM 5171.79 Circle (Radius: 1320.00)3T Harper T05 QM 5173.18 Circle (Radius: 1320.00)3T Harper T09 062625 5186.00 Circle (Radius: 100.00) 3T-614 wp14 Surface Location 3T-614 wp14 Surface Location # Schlumberger-Confidential 3T-614 wp14 Surface Casing 3T-614 wp14 Surface Casing # Schlumberger-Confidential 3T-614 wp14 Top Moraine 3T-614 wp14 Top Moraine # Schlumberger-Confidential 3T-614 wp14 Intermediate Csg 3T-614 wp14 Intermediate Csg # Schlumberger-Confidential 3T-614 wp14 TD 3T-614 wp14 TD # Schlumberger-Confidential Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. TOROK OIL 225-090 KRU 3T-614 KUPARUK RIVER WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV U 3T-614Initial Class/TypeSER / PENDGeoArea890Unit11160On/Off ShoreOnProgramSERWell bore segAnnular DisposalPTD#:2250900Field & Pool:KUPARUK RIVER, TOROK OIL - 490169NA1Permit fee attachedYesADL393883 ;ADL025528 ;ADL025544 ;ADL3904342Lease number appropriateYes3Unique well name and numberYesKUPARUK RIVER, TOROK OIL - 490169 - governed by CO 725A4Well located in a defined poolYes5Well located proper distance from drilling unit boundaryYes6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitYesAIO 039A14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15All wells within 1/4 mile area of review identified (For service well only)No16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes81'18Conductor string providedYesSurface casing set at 2785' MD19Surface casing protects all known USDWsYes157% excess cement planned20CMT vol adequate to circulate on conductor & surf csgNo21CMT vol adequate to tie-in long string to surf csgYesCemented production liner with frac sleeves22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYes26Adequate wellbore separation proposedYes27If diverter required, does it meet regulationsYesMax reservoir pressure is 2346 psig(8.6 ppg EMW); will drill w/ 9.0-10.0 ppg EMW28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP 1828 psig; will test BOPs to 5000 psig initially & 4000 psig subsequently30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYes33Is presence of H2S gas probableYes3T-616, 3T-616PB1 and 3T-616PB234Mechanical condition of wells within AOR verified (For service well only)NoH2S present in 3T wells, June '25 reading at 3T-603 56 ppm.35Permit can be issued w/o hydrogen sulfide measuresYesExpected pressure range is 0.447 psi/ft (8.6 ppg EMW)36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprTCSDate10/1/2025ApprVTLDate10/1/2025ApprTCSDate10/1/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 10/2/2025