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Home My WebLink About225-124KƌŝŐŝŶĂƚĞĚ͗ ĞůŝǀĞƌĞĚƚŽ͗dZE^D/dd>d7-Dec-25$ODVND2LO *DV&RQVHUYDWLRQ&RPPLVVLRQdZE^D/dd>η07Dec25-AP01ddE͗'ĂǀŝŶ'ůƵǇĂƐϳϬϭtϴƚŚǀĞŶƵĞŶĐŚŽƌĂŐĞ͕<ϵϵϱϬϭ;ϵϬϳͿϮϳϯͲϭϳϬϬŵ ;ϵϬϳͿϮϳϯͲϰϳϲϬĨĂǆt>>ED W/η^Zs/KZZη&/>ED^Zs/^Z/Wd/KE >/sZ>^Z/Wd/KE ddzW d>K''K>KZWZ/Ed^ ĞͲdZE^dͬ3T-731B 50-103-20905-02-00 225-124 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 27-Nov-25 1WĂƚŚ ͘W&ͲYƚǇ ͘>^ͲYƚǇ ͘>/^ͲYƚǇ ͘WWdͲYƚǇ ͘dydͲYƚǇ͘^sͲYƚǇĂƚĂĨƌŽŵDͬ>tdŽŽůƐĞƉƚŚ ϭ ϭ E dƌƵůŝŶŬͬŝŐŝ^ĐŽƉĞͲ^ƉůŝĐĞĚdŝŵĞͲ>tϬϬϮ ϭ ϭ E dƌƵ>ŝŶŬdŝŵĞͲ>tϬϬϯ ϭ ϭ E ŝŐŝ^ĐŽƉĞWĞƌtĞůů ϰ ϭ ϭ ĂƌĐs/^/KEͬWĞƌŝ^ĐŽƉĞͬĂĚŶs/^/KEͲ^ƉůŝĐĞĚ>tϬϬϮ ϰ Ϯ Ϯ ĂƌĐs/^/KE>tϬϬϯ ϰ Ϯ Ϯ WĞƌŝ^ĐŽƉĞͬĂĚŶs/^/KEZĞĂůdŝŵĞ WĞƌtĞůů ϰ ϭ ϭ ĂƌĐs/^/KEͬWĞƌŝ^ĐŽƉĞͬĂĚŶs/^/KEͲ^ƉůŝĐĞĚϭ E E E ϵ ϭ dĞůĞ^ĐŽƉĞͬdƌƵ>ŝŶŬͬŝŐŝ^ĐŽƉĞZĞĐŽƌĚĞĚDŽĚĞ >tϬϬϯZ/, ϳ ϭ ϭ E E E ^ŽŶŝĐ^ĐŽƉĞͲ/ŶƚĞƌƉƌĞĂƚŝŽŶƌĞƉŽƌƚŝŶĐůƵĚĞĚZĞĐŽƌĚĞĚDŽĚĞ >tϬϬϯ^KK, ϳ ϭ ϭ ϭ E E ^ŽŶŝĐ^ĐŽƉĞͲ/ŶƚĞƌƉƌĞĂƚŝŽŶƌĞƉŽƌƚŝŶĐůƵĚĞĚ$QFKRUDJH$ODVNDĂƚĂĞƐĐƌŝƉƚŝŽŶSidetrack Hole. LWD001 data corresponds to the Surface section drilled in the motherbore 3T-731&ŽƌŵĂƚŝŽŶǀĂůƵĂƚŝŽŶƌŝůůŝŶŐDĞĐŚĂŶŝĐƐE E EZĞĐŽƌĚĞĚDŽĚĞ^ƵƌǀĞǇtĞůůĂƚĂdƌĂŶƐŵŝƚƚĂůZĞĐĞŝƉƚͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺ yͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺWƌŝŶƚEĂŵĞ ^ŝŐŶĂƚƵƌĞ ĂƚĞWůĞĂƐĞƌĞƚƵƌŶǀŝĂĐŽƵƌŝĞƌŽƌƐŝŐŶͬƐĐĂŶĂŶĚĞŵĂŝůĂĐŽƉǇƚŽ^ĐŚůƵŵďĞƌŐĞƌ͘ĂƵƌĂŶĂΛƐůď͘ĐŽŵ^>ƵĚŝƚŽƌͲdƌĂŶƐŵŝƚƚĂůZĞĐĞŝƉƚƐŝŐŶĂƚƵƌĞĐŽŶĨŝƌŵƐƚŚĂƚĂƉĂĐŬĂŐĞ;ďŽǆ͕ĞŶǀĞůŽƉĞ͕ĞƚĐ͘ͿŚĂƐďĞĞŶƌĞĐĞŝǀĞĚĂŶĚƚŚĞĐŽŶƚĞŶƚƐŽĨƚŚĞƉĂĐŬĂŐĞŚĂǀĞďĞĞŶǀĞƌŝĨŝĞĚƚŽŵĂƚĐŚƚŚĞŵĞĚŝĂŶŽƚĞĚĂďŽǀĞ͘dŚĞƐƉĞĐŝĨŝĐĐŽŶƚĞŶƚŽĨƚŚĞƐĂŶĚͬŽƌŚĂƌĚĐŽƉǇƉƌŝŶƚƐŵĂǇŽƌŵĂǇŶŽƚŚĂǀĞďĞĞŶǀĞƌŝĨŝĞĚĨŽƌĐŽƌƌĞĐƚŶĞƐƐŽƌƋƵĂůŝƚǇůĞǀĞůĂƚƚŚŝƐƉŽŝŶƚ͘η^>ͲWƌŝǀĂƚĞ225-124T41193 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 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?KRU 3T-731B Yes No 9. Property Designation (Lease Number): 10. Field: Coyote Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 13118 4181.00 13116 4181.00 1972 None None Casing Collapse Structural Conductor Surface 2470 Intermediate 4790 Intermediate 7850 Liner 9210 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:Rodrigo Ruysschaert Rodrigo Ruysschaert Contact Email:Rodrigo.Ruysschaert@cop.com Contact Phone: 907-621-0671 Authorized Title: Completions Engineer 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 Authorized Name and Digital Signature with Date:Dec 01 2025 AOGCC USE ONLY Suspension Expiration Date: Subsequent Form Required: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 4-1/2" L-80 4926.98 Halliburton TNT Prod Packer Baker SLZXP, No SSSV TNT packer: 4786 ft MD/4076 ft TVD SLZXP packer: 4922 ft MD/4103 ft TVD Dec 10 2025 989 7-5/8"5087.0 4127.00 10860 8194.13 4-1/2"13116.0 4181.00 11590 2585.1 10-3/4"2625.0 2511.00 5210 4060.1 7-5/8"4098.0 3776.00 6890 80 20"119.0 119.0 PRESENT WELL CONDITION SUMMARY MPSP (psi): Plugs (MD): Length Size MD TVD Burst ADL025528 / ADL025544 Kuparuk Field STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ConocoPhillips Alaska Inc. 225-124 P.O. Box 100360, Anchorage, Alaska 99510-0360 50-103-20905-02-00 Will perfs require a spacing exception due to property boundaries? Current Pools:Proposed Pools: m n s _ tc N 2 66 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-732 By Grace Christianson at 9:12 am, Dec 02, 2025 Fracture Stimulate DSR-12325SFD 12/8/2025 10-404 CDW 12/08/2025 Dec 10 2025 VTL 12/8/2025 12/09/25 December 2, 2025 VIA E-MAIL To: Operator and Owners (shown on Exhibit 2) Re: Notice of Operations for 3T-731B Well ADL 025528 & ADL 025544 Kuparuk River Unit, Alaska CPAI Contract No. 203828 Pursuant to 20 AAC 25.283, ConocoPhillips Alaska, Inc. (CPAI) as Operator of the Kuparuk River Unit, hereby notifies you that it intends to submit an Application for Sundry Approvals for stimulation by hydraulic fracturing in accordance with 20 AAC 25.280 (Application) for the 3T- 731B Well (the Well). The Application will be filed with the Alaska Oil and Gas Conservation Commission on or about December 2, 2025. The Well is currently planned to be drilled as a directional horizontal well on lease ADL 025528 and ADL 025544 as depicted on Exhibit 1, and has locations as follows: Location FNL FEL Township Range Section Meridian Surface 3,636 5,147 T12N R7E 1 Umiat Top Open Interval 4,360 4,395 T12N R7E 1 Umiat Bottomhole 1,7903,313 T12N R7E 13 Umiat Exhibit 1 shows the location of the Well and the lands that are within a one-half mile radius of the current proposed trajectory of the Well (Notification Area), which includes the reservoir section. Exhibit 2 is a list of the names and addresses of all owners, landowners, surface owners, and operators of record at the time of this Application for all properties within the Notification Area. Upon your request, CPAI will provide a complete copy of the Application. If you require any additional information, please contact the undersigned. Sincerely, Ryan C. King, CPL Staff Land Negotiator Attachments: Exhibits 1 & 2 Ryan C. King, CPL Staff Land Negotiator Land & Business Development P.O. Box 100630 Anchorage, AK 99510-0360 Office: 907-265-6106 Fax: 907-263-4966 ryan.c.king@cop.com Sincerely, Ryan C. King, CPL BCC: Rodrigo Ruysschaert David Lee Jason Parker John Evans Patrick Perfetta Exhibit 1 Exhibit 2 List of the names and addresses of all owners, landowners, surface owners, and operators of record of all properties within the Notification Area. Operator & Owner: ConocoPhillips Alaska, Inc. 700 G Street, Suite ATO-1480 (Zip 99501) P.O. Box 100360 Anchorage, AK 99510-0360 Attn: GKA Asset Development Manager Owner (Non-Operator): ConocoPhillips Alaska, Inc. II ExxonMobil Alaska Production Inc. 700 G Street, Suite ATO 1226 PO Box 196601 Anchorage, Alaska 99510 Anchorage, AK 99519 Attn: GKA Asset Development Manager Attn: Todd Griffith Landowners: State of Alaska Department of Natural Resources Division of Oil and Gas 550 West 7th Avenue, Suite 1100 Anchorage, AK 99501 Attention: Derek Nottingham, Director Surface Owner: State of Alaska Department of Natural Resources Division of Oil and Gas 550 West 7th Avenue, Suite 1100 Anchorage, AK 99501 Attention: Derek Nottingham, Director 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) 27 wells CDW 12/02/2025 SECTION 3 FRESHWATER AQUIFERS 20 AAC 25.283(a)(3) There are no known underground sources of drinking water within a one-half mile radius of the current or proposed wellbore trajectory. See Conclusion number 5 of the Area Injection Order AIO 45- Coyote Oil Pool, which states An aquifer exemption is not necessary for this project because the total dissolve solids of the water in the COP is over 21,000 mg/l, and the KRU has a valid aquifer exemption from the US EPA under 40 CFR 147.102(b)(3). NOTE: KRU 3T-731B lies within the boundary of the Kuparuk River Unit Aquifer Exemption as currently depicted on EPA Region 10's Alaska Oil & Gas Aquifer Exemptions Interactive Map, available through their web site. However, this well also lies outside of the boundary of the Kuparuk River Unit of 1984 that may form 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 boundary applies to that aquifer exemption. SFD Concur with absence of freshwater aquifers within one-half mile radius of 3T-731B based on examination of well logs and quick-look Pickett Plot analyses of a water-wet sand beneath permafrost in nearby wells Moraine 1 (PTD 214-198) and Colville Delta 3. If the shallowest water-bearing sands in Moraine 1 and Colville Delta 3 have TDS concentrations greater than that of freshwater (3,000 to 10,000 mg/l), it is highly likely that all underlying water-bearing zones are also higher in TDS concentration. SFD 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 pump report on 3/15/2025 shows that the original job pumped as designed. The cement job was pumped with 438 barrels of 11.0 ppg lead cement and 58 barrels 15.8 ppg tail cement, displaced with 9.8 ppg mud. The plug bumped at 950 psi and the floats held. 150 bbls of cement returned to surface. The 7-5/8 casing cement report on 11/20/2025 shows that the job was pumped with 50 BBLS 15.3 ppg Tail Cement. The cement was displaced with 216.2 BBLS 10.0 ppg NAF via rig pumps at 6 BPM. Reduce to 3 BPM for last 12 BBL. Plugs bumped at 2146 stks with 866 psi. (95% efficiency), pressure up to 1380 psi and hold for 5 min. Bleed off pressure, and check floats - floats held. Cement in place @ 0300 hrs on11/20/2025. A sonic log indicated the cement top at 3,733 MD / 3,512 TVD (1270 MD / 606 TVD above the Coyote). The 4-1/2" production liner was cemented on 11/28/2025, the job was pumped with 68 BBLS 10.5 PPG Mud Push spacer, 254 BBLS 15.3 ppg Tail Cement, displaced with 154.8 BBLS of 9.5 PPG CI Brine via rig pumps at 3-1 BPM (adjusted based on losses). Increase rate to 3 BPM for last 6.8 BBL. Plug bumped with 1130 psi, pressured up to 1930 psi and held for 5 min. Bled off pressure & floats checked good. Cement in place @ 13:00 HRS on11/28/2025. Lost 42 BBLS based on pumping 254 BBLS with a gauge hole volume of 172 BBLS & 40 BBLS of cement circulated to surface. Summary All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. SECTION 7 PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 3/17/2025 the 10-3/4 casing was pressure tested to 3,000 psi for 30 minutes On 11/20/2025 the 7-5/8 casing was pressure tested to 3,950 psi for 30 minutes. On 11/30/2025 the 4-1/2 tubing was pressure tested to 4,400 psi for 30 minutes prior to rig down. On 11/30/2025 the 7-5/8 casing by 4-1/2 tubing annulus was pressure tested to 3,850 psi for 30 minutes prior to rig down. The 4-1/2 tubing will be pressure tested to 4,200 psi for 30 minutes and the 7-5/8 casing by 4-1/2 tubing annulus will be pressure tested to 3,850 psi for 30 minutes post-rig. AOGCC Required Pressures [all in psi] Maximum Predicted Treating Pressure (MPTP) 7,075 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 4,075 Electronic PRV 8,075 Highest pump trip 7,575 4,200 MITT of 4200 psi with 3500 psi IA backpressure allows Max. surf frac pressure of 7318 psi. MITT of 4075 psi with 3500 psi IA backpressure allows Max. surf frac pressure of 7204 psi. CDW 12/08/2025 4,075 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 2,474 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 P-110S 11,590 9,210 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 gross Coyote interval, has an average thickness greater than 150 ft TVD over the course of the lateral section of well 3T-731B, from where it intersects the top formation at 5,003 MD to TD of the well. At the heel of the well it has a gross thickness of ~100 thickening to ~215 at the toe of the well. The Coyote interval is comprised of thinly interbedded sandstone and siltstone layers. The sandstone and siltstone components are litharenites, moderately to well sorted, and are of the size range from silt to very fine sand. The estimated fracture pressure for the Coyote interval is approximately 12.9-16.1 ppg based on FIT/LOT data. The overlying confining interval is represented by distal toe of slope (deep marine) claystone with thin siltstone beds of the Cretaceous Seabee Formation. This interval is present in thicknesses of ~250 TVD in the vicinity of the 3T-731B wellbore. The top of the confining intervals starts at ~3,752 TVDSS (4,135 MD). It should be noted that slope to basin shales and siltstones are present from the top of the Seabee formation to the surface casing shoe at ~2,625 MD. This interval acts as a continuation of the upper confining interval. CPAI estimates the fracture closure pressure gradient of the section above the Coyote to range from 0.67 to 0.73 psi/ft based on diagnostic fracture injection testing (DFIT) in the 3S-24B well and recent data collection in the 3S-719 and 3S-721 wells. The data collection in the 3S-719 and 3S-721 wells included LOTs to better understand the fracture gradient of the overlying Seabee formation. Based on this testing the leak off point (LOP) of the overlying Seabee ranges from 0.73 to 0.78 psi/ft, and the fracture breakdown pressure (FBP) ranges from 0.82 0.93 psi/ft. Based on our dynamic fracture modeling, the fracture could propagate into the overlying interval, which was observed in the 3S-24B vertical well. The log results from the 3S-24B showed 34 of potential fracture growth into the overburden compared to the ~250 of TVT of the overlying zone. Additionally, geomechanical testing completed on the overburden core proved there is no remaining conductivity within a fracture that propagates into the overlying zone due to proppant embedment and interaction of the frac fluid with the rock. Post-frac injection will be at or below the fracture closure pressure (Pc) of the overlying seal which is less than the fracture propagation pressure (FPP). The lower confining interval of the Coyote comprises slope to basin floor mudstones of the Torok formation, which are present in thicknesses of ~830 TVD in the vicinity of the 3T-731B wellbore. This same confining zone forms the upper confining interval of the Kuparuk River Unit, Torok Oil Pool. The estimated fracture gradient for this section ranges from 15-18 ppg. The base of the gross Coyote interval is estimated from seismic to be at ~4,163 ft TVDSS at the heel, and ~4,250 ft TVDSS at the toe of the well. The estimated formation pressure within the Coyote interval is 1695 1,817 psi at a depth of 4,100 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-17 & 3S-17A: ConocoPhillips Alaska, Inc. performed Plug and Abandonment operations on 3S-17 and 3S- 17A (sidetrack from 3S-17 on 4/29/2003), commencing operations on 7/30/2022 and completing the Plug and Abandonment on 9/25/2023. A cement retainer was set at 8,333 MD via coil tubing and 27 bbls of cement was pumped below the retainer and 2 bbls on top of the retainer. Cement was tagged at 8,324 SLMD and a passing MIT-T and MIT-IA was performed and witnessed by AOGCC on 8/13/2022. The tubing was then cut at 8,273 MD and the tubing pulled out of hole. A bridge plug was set at 5,883 MD in the 7 casing and the 7 casing was perforated from 5,707-5,857 MD. Coil was utilized to perf wash and cement with 68bbls of 15.8ppg cement pumped into the perforations. TOC was tagged at 5,513 SLMD in the 7 casing and a MIT-T performed to 1500 psi, witnessed by AOGCC (pg. 16 at link below). TOC was determined in the annulus at 5,707 MD / 4,022 TVD / 3,965 TVDSS via log. Coil was used to pump 22 bbls of 15.8ppg cement in the 7 casing. The TOC was tagged at 5,273 MD and a MIT-T performed to 1,500 psi, witnessed by AOGCC (pg. 15 at the link below). The top cement job was performed on 9/5/2023 with 223 bbls of 15.8ppg Class G cement and the 7 casing was cemented to surface. The final abandonment was completed on 9/25/23, witnessed by AOGCC (pg 2 at link below). 203-080 - Laserfiche WebLink 3S-19: ConocoPhillips Alaska, Inc. performed Plug and Abandonment operations on 3S-19, commencing operations on 1/1/2024 and completing the Plug and Abandonment on 3/25/2025. From the original cement job, a CBL was conducted on 12/22/2012 from 9170ft to surface. CBL log indicated good to fair cement from 9170ft to 7350ftMD. A cement retainer was set at 9,620 MD via coil tubing and 35 bbls of cement was pumped below the retainer. Another cement retainer was set at 8,515 MD and 50 bbls of cement was pumped below the retainer and 2 bbls on top. Cement was tagged at 8,274 SLMD and a passing MIT-T was performed and witnessed by AOGCC on 5/17/2023 (pg. 15 at link below). The tubing was then cut at 8,271 MD and the tubing pulled out of hole. A CIBP was set at 6,596 MD in the 7 casing and the 7 casing was perforated from 6,420- 6,570 MD. Coil was utilized to perf wash and cement with 65bbls of 15.8ppg cement pumped into the perforations. TOC was tagged at 6,120 SLMD in the 7 casing. TOC was determined in the annulus at 6,420 MD / 4,033 TVD / 3,977 TVDSS via log. A CIBP was set at 6,598 MD and coil was used to pump 42 bbls of 15.8ppg cement in the 7 casing. The TOC was tagged at 5,474 MD and a MIT-T performed to 1,710 psi, witnessed by AOGCC (pg. 8 at the link below). A top cement job was performed on 12/30/2023 with 210 bbls of 15.8ppg Class G cement and the 7 casing was cemented to surface. Pressure was still observed at surface on the production casing. Cement was milled down to 3,780 MD and a CIBP set at 3,777 MD. The casing was tested against the CIBP to 1,650 psi, witnessed by AOGCC on 3/15/2025 (pg. 1 at the link below). An additional top cement job was completed on 3/16/2025 with 165 bbls of 15.8ppg cement from 3,777 MD to surface. Awaiting final abandonment operations once the rig moves. 203-096 - Laserfiche WebLink 3S-22: ConocoPhillips Alaska, Inc. performed Plug and Abandonment operations on 3S-22, commencing operations on 5/1/2023 and completing the Plug and Abandonment on 3/25/24. Original drilling did not cover the zone of interest. A CBL was run prior to the P&A showing the original cement height at 6255' MD. A cement retainer was set at 7,690 MD via coil tubing and 32 bbls of 15.8ppg cement was pumped below the retainer and 2 bbls on top of the retainer. Cement was tagged at 7,418 SLMD and a passing MIT-T and MIT-IA was performed and witnessed by AOGCC on 5/12/2023 (pg. 12 at link below). The tubing was then cut at 7,420 MD and the tubing pulled out of hole. A CIBP was set at 5,467 MD in the 7 casing and the 7 casing was perforated from 27 wells plus 3S-17 CDW 12/02/2025 AOGCC evaluated 29 wells and wellbores that transect the confining zones within and near the 3T-713B 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. SFD 5,291-5,441 MD. Coil was utilized to perf wash and cement with 68bbls of 15.8ppg cement pumped into the perforations. TOC was tagged at 5,107 SLMD in the 7 casing and TOC was determined in the annulus at 5,291 MD / 4,018 TVD / 3,960 TVDSS via log. Coil was used to pump 38 bbls of 15.8ppg cement in the 7 casing. The TOC was tagged at 4,445 MD and a MIT-T performed to 1,500 psi, witnessed by AOGCC (pg. 5 at the link below). The top cement job was performed on 2/28/2024 with 193 bbls of 15.8ppg Class G cement and the 7 casing was cemented to surface. The final abandonment was completed on 3/25/24, witnessed by AOGCC (pg. 2 at link below). 203-011 - Laserfiche WebLink 3S-610: The 7-5/8 casing cement report on 3/23/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 201 barrels of 15.3 ppg with BM-II (Bridge Maker II), followed with 22 barrels of 15.3 ppg without BMII. The plug did not bump, pressure held at 1140 psi indicating that floats are competent. A cement bond log indicates competent cement with a cement top @ 3,549 MD (3,156 TVD / 3,092 TVDSS). 223-126 - Laserfiche WebLink 3S-611: The 7-5/8 casing cement report on 10/13/2018 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 270 bbls of 15.8 ppg Class G cement and the top plug was dropped. This was chased with 9.4 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 8,228MD/3,967 TVD/3,904 TVDSS (pg. 274 at the link below). 218-103 - Laserfiche WebLink 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 TVD/3,768 TVDSS (pg. 289 at the link below). 218-111 - Laserfiche WebLink 3S-613: The 7-5/8 casing cement report on 5/2/2016 shows that the 2-string job was pumped as designed, indicating competent cementing operations. The first stage consisted of 47bbls of 15.8ppg cement and plugs bumped and floats held. The second stage consisted of 189bbls of 15.8ppg cement and the plug bumped and floats held. Full returns were seen throughout both jobs. A SonicScope was run to determine TOC, but the log began at estimated TOC and no free ringing pipe was logged to help determine a clear TOC. Interpretation shows a potential TOC at 6,095 MD/3,711 TVD/3,646 TVDSS from the log (pg. 35, 192 at the link below). 216-020 - Laserfiche WebLink 3S-615: The 7-5/8 casing cement report on 11/13/2022 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 200 barrels of 15.3 ppg lead cement with BMII, followed with 33 barrels of 15.3 ppg tail cement, displaced with 524 barrels of 9.6 ppg mud. The plug bumped, bled off pressure and pressure and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 5,620 MD (3,340 TVD / 3,279 TVDSS). 222-101 - Laserfiche WebLink 3S-620: The 7-5/8 casing cement report on 2/6/2015 shows that the job was pumped as designed, indicating competent cementing operations. 11.5 ppg Mud Push II was pumped before dropping bottom plug, this was then chased with 181 bbls of 15.8 ppg Class G cement and the top plug was dropped. This was chased with 9.7 ppg mud. The plug bumped, pressured up to 1500 psi and held for 5 min. Floats were checked and they held. 48bbls of fluid was lost during the job. A SonicScope was run to determine TOC, but the log began at estimated TOC and no free ringing pipe was logged to help determine a clear TOC. Interpretation shows potential TOC above 5,400 MD/3,567 TVD/3,514 TVDSS from the log. 214-167 - 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 TVD / 3,908 TVDSS). 222-079 - Laserfiche WebLink 3S-626: The 7-5/8 casing cement report on 06/01/2024 shows the job was pumped as designed, indicating competent cementing operations. The cement job was pumped in two stages utilizing a stage tool. The first stage cement job had 188 bbls of 15.3 ppg cement. Plug bumped and floats held. The second stage cement job had 42 bbls of 15.3 ppg cement. Plug bumped and all indications are the stage tool at 6807 MD closed. A cement bond log run on 06/03/24 indicates competent cement with cement top at 5,908 MD/3,775 TVD/3,711 TVDSS. Due to issues with the freeze protect of the OA, a RWO was performed. The 7-5/8" fish was successfully recovered down to the original cut made with Doyon 142 at 2020 ft MD. A new 7-5/8 casing with a sealing overshot and cementer was installed, and cement was pumped through the cementer to the surface. The 7-5/8" packoff was then installed and tested to 3840 psi, confirming its integrity. 224-007 - Laserfiche WebLink 3S-626PB1: This wellbore was abandoned due to shale collapse in the lateral. A cement retainer was set at 9,198 MD and 33bbls of 15.3ppg cement was pumped. The TOC was tagged at 8,874 MD with 10klbs and was witnessed by AOGCC (pg. 128 at link below). A CIBP was set at 3,454 MD, casing was cut at 3,400 MD, and the casing was pulled out of hole and laid down. A kick off plug was pumped above the CIBP into the 10-3/4 surface casing with 75bbls of 16.3ppg cement. The 10-3/4 was tested to 1,500 psi for 30 minutes, witnessed by AOGCC (pg. 68 at link below). The TOC was tagged at 2,580 MD/2,306 TVD/2,243 TVDSS with 10klbs, tag witness waived by AOGCC. 224-007 - Laserfiche WebLink 3S-719: The 7-5/8 casing cement report on 7/5/2025 shows that the job was pumped with 90 barrels of 15.3ppg cement. The cement was displaced with 9.5ppg mud. The plugs did not bump, but floats were checked and were holding. Full returns were observed throughout the job. A sonic log indicated the cement top at 7,740 MD / 3,766 TVD / 3,702 TVDSS (2088 MD / 343 TVD above the Coyote). 225-058 - Laserfiche WebLink 3S-721: The 7-5/8 casing cement report on 4/29/2025 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 72 barrels of 15.3ppg cement. The cement was displaced with 9.6ppg NAF drilling mud. The plug bumped with 1018 psi and floats held. Full returns were observed during the job. 225-025 - Laserfiche WebLink 3T-603: The 7-5/8 casing cement report on 9/20/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 136 barrels of 14.0 ppg lead cement with BMII, followed with 31 barrels of 15.3 ppg tail cement, displaced with 408.5 barrels of 9.5 ppg FWP. The plug bumped and floats held. A cement bond log run indicates competent cement with a cement top @ 5,692 MD (3,578 TVD/3,527 TVDSS). 224-074 - Laserfiche WebLink 3T-608: The 7-5/8 casing cement report on 10/28/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 203 barrels of 14.0 ppg lead cement with BMII, followed with 31 barrels of 15.3 ppg tail cement, displaced with 463 barrels of 9.5 ppg FWP. The plug bumped, bled off pressure and pressure and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 5,768 MD (3,843 TVD/3,792 TVDSS). 224-094 - Laserfiche WebLink 3T-612: The 7-5/8 casing cement report on 12/07/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 98 barrels of 14.0 ppg lead cement, followed with 58 barrels of 15.3 ppg tail cement. This was displaced with 375 barrels of 9.5 ppg BaraECD 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 @ 4,799 MD (3,489 TVD/3,438 TVDSS). 224-128 - Laserfiche WebLink 3T-616: The 7-5/8 casing cement report on 01/24/2025 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 117 barrels of 14.0 ppg lead cement with BMII, followed with 58 barrels of 15.3 ppg tail cement. This was displaced with 405 barrels of 9.5 ppg BaraECD 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 @ 5,041 MD (3,422 TVD/3,370 TVDSS). The 4-1/2 liner cement report on 03/06/2025 shows the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 310 barrels of 14.8 ppg cement. The cement was displaced with 9.5ppg CI NaCl brine and the plugs bumped and held for 5 minutes. Floats held. 224-138 - Laserfiche WebLink 3T-616PB1: This wellbore was drilled in the Torok pool and was abandoned on 2/21/2025 with 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. 224-138 - Laserfiche WebLink 3T-616PB2: This wellbore is sidetrack from the 3T-616PB1. The TD of this sidetrack is 12,440 MD/4,758 TVD/4,707 TVDSS. This sidetrack did not exit the Torok pool, but did enter the Torok shale. 224-138 - Laserfiche WebLink 3T-621: The 7-5/8 casing cement report on 05/05/2024 shows the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 82 bbls of 15.3 ppg cement. Plugs bumped and floats held. A cement bond log run on 05/06/24 indicates competent cement with cement top at 6,530 MD/3,708 TVD/3,668 TVDSS. 224-022 - Laserfiche WebLink 3T-730: The 7-5/8 x 4-1/2 casing cement report on 4/30/2025 shows that the job was pumped with 60 barrels of 13.5ppg clean cement, 530 bbls of 13.5ppg cement with Bridge Maker II, and 60 bbls of 13.5ppg clean tail cement. The cement was displaced with 9.7ppg CI brine. The plug bumped and pressure was held at 1150 psi for 5 minutes. Pressure was then bled off and floats checked with floats holding. No losses were observed during the job. A cement bond log indicated the cement top at 4,520 MD / 3,949 TVD (507 MD / 153 TVD above the Coyote). 225-010 - Laserfiche WebLink Moraine 1: The cement report on 3/3/2015 shows that the 8-1/2 hole was abandoned with 3x plugs starting at 5,610 MD (TD). A total of 849 sx of 15.8ppg Class G cement was used to set all three plugs. The top cement plug was then tagged at 3,687 MD/3,643 TVD/3,600 TVDSS with 15klbs, witnessed by the AOGCC (pg. 132 at link below). This tag is above the Coyote top at 4,127 MD. A cement retainer was then set at 2,362 MD and 21bbls of 15.8ppg Class G slurry was pumped below and 3 bbls above the retainer. A final plug was laid above a CIBP set at 508 MD to surface using 11ppg AS1 cement. Photos of the final abandonment and marker plate and the submittal to AOGCC are on pages 100-104 at the link below. 214-198 - Laserfiche WebLink NDST-02: According to the Pioneer Natural Resources Operation Summary Report on the AOGCC website, the 7-5/8 casing was cemented on 2/8/2013. The cement report indicates that the job was pumped with 60 bbls of 15.8ppg Premium Cement with 3% Halad (R)-344 low fluid loss control. Full circulation was seen throughout the entire job. A USIT confirmed TOC at 8672' MD/4,841 TVD/4,800 TVDSS. Frac operations could not be completed because a lodged ball damaged the tubing, and 60 bbl of CaCO3 was spotted on 4/13/2013. On 4/14/2013, XX plug was set in nipple at 4,550 WLMD. ConocoPhillips Alaska Inc. re-entered on 1/3/2023, pulled the XX plug at 8,360 CTMD (restriction) instead of at the nipple and performed injectivity test at 0.5 bpm on 1/21/2023. The tubing was cut at 8,316 MD and was removed from the well. On 10/8/2024, coil tubing set a cement retainer at 10,441 MD and pumped 110bbls of 15.8ppg cement into the 4.5 liner. Coil unstung from the retainer and laid an additional 68bbls of 15.8ppg cement on top of the retainer. The cement plug was not tagged due to issues with deviation/thick fluid, but a pressure test was completed to 1700 psi and witness by AOGCC on 10/12/2024 (pg. 2-6 at link below). Another attempt to tag the TOC was completed on 2/8/2025 with coil tubing, tagging at 8,812 MD with 4klbs and witnessed by AOGCC (pg. 1 at link below). The well is currently awaiting perf/wash/cement operations. The Coyote is not currently isolated by cement in the 7-5/8 x 10-3/4 annulus. The outer annulus of this well (7-5/8 x 10-3/4) will be monitored during the stimulation of 3T-731. Given the longitudinal orientation of the planned stimulation operations, it is not foreseen that the hydraulic fractures will intersect the Nuna 1 wellbore in the Coyote sand. 212-163 - Laserfiche WebLink NDST-02 PB1: According to the Pioneer Natural Resources Operation Summary Report on the AOGCC website, on 1/30/2013, the bottom plug was pumped with 52bbls of 15.8ppg premium cement. Plug #2 was placed at 8,600 MD with 52bbls of 15.8ppg premium cement. TOC was tagged at 8,012 MD with 30klbs. On 1/31/2013, the kick off plug was pumped with 60 bbls of 17ppg premium Class G cement. Tagged firm cement at 5,236 MD/3,228 TVD/3,186 TVDSS with 20klbs on 2/2/2013. 212-163 - Laserfiche WebLink Nuna 1: According to the Pioneer Natural Resources job log on the AOGCC website, 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 below). A log was run to interpret TOC which has been indicated as 7,040 MD/4,860 TVD/4,817 TVDSS (pg. 167 at link below). 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. The Coyote is not currently isolated with cement. The outer annulus of this well (7-5/8 x 10-3/4) will be monitored during the stimulation of 3T-731. Given the longitudinal orientation of the planned stimulation operations, it is not foreseen that the hydraulic fractures will intersect the Nuna 1 wellbore in the Coyote sand. 211-155 - Laserfiche WebLink Nuna 1 PB1: According to the Pioneer Natural Resources job log on the AOGCC website, three abandonment plugs were placed on 2/10/2012. The three plugs were set as balanced plugs at the following depths: 7,347- 6,847 MD with 52 bbls of 15.8ppg Class G cement, 6,847-6,285 MD with 60bbls of 15.8ppg Class G cement, and 6,285-5,800 MD with 49bbls of 17.0ppg Class G cement. The top plug was tagged with 25klbs at 5,790 MD/4,192 TVD/4,149 TVDSS prior to kick off for the main wellbore (pg. 186-187 at link below). 211-155 - 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 three faults transect the Coyote reservoir within one half mile radius of the 3T-731B wellbore trajectory. The first of these faults intersects the 3T-731B wellbore at ~5,711 MD. This fault is interpreted to have minimal throw at this location (< 5 feet). This fault has an interpreted W E strike and is downthrown to the South. There is no mapped offset at the Top Coyote based on seismic in the area where it is picked in the 3T-731B wellbore. The second mapped fault intersected the original 3T-731 wellbore at 11,700 MD, however there was no clear evidence from logs that this fault was present in the 3T-731B wellbore. The fault at 11,700 MD was interpreted to have a throw of 10 20 where it intersected the original 3T-731 wellbore. This fault has an interpreted ~W E strike and is downthrown to the south. The third fault is east of the heel of the 3T-731B wellbore. This fault is a west - east striking feature. It is questionable as to whether it is an actual fault at the top Coyote level. If it exists, it has minimal throw at the top Coyote (5 to 10 feet). It has maximum potential offset of ~65 in the Seabee section ~370 above the Coyote. It loses throw both upward and downward from this point to near zero at the Coyote level and upward to no throw within in the slope deposits of the upper Seabee formation ~650 above top Coyote. These faults are interpreted to lose throw into the confining intervals above and below the Coyote reservoir. The interpreted faults should not affect overburden integrity and therefore their presence should not interfere with containment. If there is any indication that a propagated fracture has intersected the 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-731 B was completed in 2025 as a horizontal producer in the Coyote formation. The well is a re-drill from the original 3T-731, the well was sidetracked from the 10-3/4 shoe of the original wellbore and completed as a 3- string well. The well was completed with a 4.5 tubing upper completion and 4-1/2 production liner with dart actuated sliding sleeves in the lateral. Injection will be established into the well and the first stage treated. A dart will be dropped for stage 2 to initiate treatment. Once each stage is complete, a dart will be dropped for each subsequent stage. These darts will provide isolation from the previous stage and allow fracturing from the toe of the well towards the heel. 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 on the 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 ~2,000 TVD. 4. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 5. MIRU 25 clean insulated Frac tanks, with a berm surrounding the tanks that can hold a single tank volume plus 10%. Load tanks with 100ºF seawater. 6. MIRU HES Frac Equipment. 7. PT Surface lines to 10,000 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 the frac job per the attached Halliburton pump schedule at 20-22 bpm with a maximum expected treating pressure of 7,075 psi. 11. RDMO Halliburton Equipment. Freeze Protect the tubing and wellhead if not able to complete following the flush. 12. The well is ready for post-frac well prep/production tree installation and flowback (after Slickline and Coiled Tubing Cleanout). Patina tracers Will be pumped in the toe and Resmetrics oil and gas tracers will be pumped in remaining stages. See Halliburton chemical disclosure sheet which includes this other chemicals. 7,075 psi Frac Model Result Hydraulic Fracturing Fluid Product Component Information Disclosure 2025-12-01 Alaska HARRISON BAY 50-103-2090502-00 CONOCOPHILLIPS 3T 731B -150.26922564 70.41991874 NAD83 none Oil 4200 984816 Hydraulic Fracturing Fluid Composition: Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Ingredient Mass lbs Comments Company First Name Last Name Email Phone SEAWATER Operator Base Fluid Density = 8.34 BA-20 BUFFERING AGENT Halliburton Buffer BC-140 X2 Halliburton Initiator BE-6(TM) Bactericide Halliburton Microbiocide CAT-3 ACTIVATOR Halliburton Activator CL-28M CROSSLINKER Halliburton Crosslinker CLA-WEB(TM) Halliburton Clay Stabilizer Legend LD-6450 MultiChem Completion/Stimulatio n LoSurf-300D Halliburton Non-ionic Surfactant MO-67 Halliburton pH Control OPTIFLO-HTE Halliburton Breaker OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker OPTIFLO-III DELAYED RELEASE BREAKER Halliburton Breaker ResMetrics Oil Phase Tracer ResMetrics Tracer ResMetrics Water Phase Tracer ResMetrics Tracer SP BREAKER Halliburton Breaker WG-36 GELLING AGENT Halliburton Gelling Agent Ceramic Proppant - Wanli Wanli Proppant SAND, COMMON BROWN 100 MESH Halliburton Proppant Calcium Chloride Customer Salt Solution CarboLite 16/20 Carbo Ceramics Proppant Flow Insurance Brass Patina Energy Tracer Patina Energy Flow Insurance Copper Patina Energy Tracer Ingredients Water 7732-18-5 100.00%69.63774%8213366 Ceramic Materials and Wares, Chemicals 66402-68-4 100.00%29.65810%3498000 Sodium chloride 7647-14-5 5.00%3.48189%410669 Water 7732-18-5 100.00%0.24312%28675 Guar gum 9000-30-0 100.00%0.22389%26407 Calcium Chloride 10043-52-4 100.00%0.08479%10000 Calcium chloride, dihyrate 10035-04-8 60.00%0.05324%6279 EDTA/Copper chelate Proprietary 30.00%0.04149%4894 Denise Tuck, Halliburton, 3000 N. Sam Houston Pkwy E., Houston, TX 77032, 281-871- 6226 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Ethanol 64-17-5 60.00%0.03781%4460 Monoethanolamine borate 26038-87-9 100.00%0.03515%4146 Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.01891%2230 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.01891%2230 Ammonium persulfate 7727-54-0 100.00%0.01659%1957 Sodium hydroxide 1310-73-2 30.00%0.01220%1440 Ethylene glycol 107-21-1 70.00%0.01134%1337 Ammonium chloride 12125-02-9 5.00%0.00692%816 Oxyalkylated phenolic resin Proprietary 10.00%0.00630%744 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Corundum 1302-74-5 60.00%0.00509%600 Oxylated phenolic resin Proprietary 30.00%0.00498%588 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Copolymer of acrylamide and sodium acrylate 25085-02-3 5.00%0.00444%524 Mullite 1302-93-8 40.00%0.00339%400 Naphthalene 91-20-3 5.00%0.00315%372 Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega-hydroxy-, branched 127087-87-0 5.00%0.00315%372 Crystalline silica, quartz 14808-60-7 100.00%0.00167%198 Ammonia 7664-41-7 1.00%0.00138%164 2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00125%147 Glycol Ether Proprietary 80.00%0.00091%107 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 1,2,4 Trimethylbenzene 95-63-6 1.00%0.00063%75 Sodium chloride 7647-14-5 1.00%0.00041%49 Proprietary Non-Hazardous Proprietary 100.00%0.00037%45 Patina Energy Julie Harrish julie@patinae nergy.com 8327140836 Flow Insurance Brass Proprietary 100.00%0.00037%44 Patina Energy Julie Harrish julie@patinae nergy.com 8327140836 Proprietary1 Proprietary 20.00%0.00034%41 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 C.I. pigment Orange 5 3468-63-1 1.00%0.00017%20 Polymer Proprietary 0.10%0.00009%11 MultiChem Ana Djuric Ana.Djuric@H alliburton.com 281-871- 5747 Ammonium acetate 631-61-8 100.00%0.00008%10 Borate salts Proprietary 60.00%0.00005%7 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Ammonium salt Proprietary 60.00%0.00005%6 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 2,7-Naphthalenedisulfonic acid, 3- hydroxy-4-[(4-sulfor-1- naphthalenyl) azo] -, trisodium salt 915-67-3 0.10%0.00004%5 Acetic acid 64-19-7 30.00%0.00002%3 Sodium persulfate 7775-27-1 100.00%0.00001%1 Walnut hulls NA 100.00%0.00001%1 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Inorganic mineral 1317-65-3 5.00%0.00000%1 Potassium chloride 7447-40-7 5.00%0.00000%1 Polyamine Proprietary 30.00%0.00000%1 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Inorganic mineral Proprietary 1.00%0.00000%1 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Polymer Proprietary 1.00%0.00000%1 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Gluteraldehyde 111-30-8 1.00%0.00000%1 Calcium magnesium carbonate 16389-88-1 1.00%0.00000%1 Hemicellulase 9025-56-3 5.00%0.00000%1 Methanesulfonic acid, 1-hydroxy-, sodium salt 870-72-4 0.10%0.00000%1 Sodium bisulfate 7681-38-1 0.10%0.00000%1 Cured acrylic resin Proprietary 1.00%0.00000%1 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 C.I. Pigment Red 5 6410-41-9 1.00%0.00000%1 Quaternary amine Proprietary 0.10%0.00000%1 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 Amine salts Proprietary 0.10%0.00000%1 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871- 6226 2-Methyl-4-isothiazolin-3-one 2682-20-4 0.01%0.00000%1 5-Chloro-2-methyl-3(2H)- Isothaiazolone 26172-55-4 0.01%0.00000%1 Magensium chloride 7786-30-3 0.01%0.00000%1 Magnesium nitrate 10377-60-3 0.01%0.00000%1 Sodium sulfate 7757-82-6 0.10%0.00000%1 * Total Water Volume sources may include fresh water, produced water, and/or recycled water ** Information is based on the maximum potential for concentration and thus the total may be over 100% Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided.Version web 1.5 All component information listed was obtained from the suppliers Material Safety Data Sheets (MSDS). As such, the Operator is not responsible for inaccurate and/or incomplete information. Any questions regarding the content of the MSDS should be directed to the supplier who provided it. The Occupational Safety and Health Administrations (OSHA) regulations govern the criteria for the disclosure of this information. Please note that Federal Law protects "proprietary", "trade secret", and "confidential business information" and the criteria for how this information is reported on an MSDS is subject to 29 CFR 1910.1200(i) and Appendix D. Production Type: True Vertical Depth (TVD): Total Water Volume (gal)*: MSDS and Non-MSDS Ingredients are listed below the green line Well Name and Number: Longitude: Latitude: Long/Lat Projection: Indian/Federal: Fracture Date State: County: API Number: Operator Name: Proprietary chemicals are on file at AOGCC CDW 12/02/2025 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.41991874LEASE3T-731 L2SALES ORDERBHST (°F)105LONG-150.2692256FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 LD-6450 WG-36 OPTIFLO-IIBE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Clay ControlInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)1-1 Shut-In Shut-In 1:59:54 1-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:59:54 1-3 Shut-In Shut-In 1:55:08 1-4 27# Linear DFIT 10 1,680 40 40 0:04:00 1:55:08 1.00 2.00 1.00 27.00 2.000.151-5 Shut-In Shut-In 1:51:08 1-6 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:51:08 0.45 1.00 0.50 2.00 1.00 27.00 2.000.151-7 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:37:48 0.45 1.00 0.50 2.00 1.00 27.00 2.000.151-8 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 1:18:15 0.45 1.00 0.50 2.00 1.00 27.00 2.000.151-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.151-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.151-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.151-12 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 0.50 2.00 1.00 27.00 2.000.151-13 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 0.50 2.00 1.00 27.00 2.000.151-14 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 0.50 2.00 1.00 27.00 2.000.151-15 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 0.50 2.00 1.00 27.00 2.000.151-16 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 1.00 27.00 2.00 0.152-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:18 1.00 2.00 1.00 27.00 2.000.152-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:47:48 0.45 1.00 0.50 2.00 1.00 27.00 2.000.152-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:37:48 0.45 1.00 0.50 2.00 1.00 27.00 2.000.152-4 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 1:18:15 0.45 1.00 0.50 2.00 1.00 27.00 2.000.152-5 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.152-6 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.152-7 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.152-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 0.50 2.00 1.00 27.00 2.000.152-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 0.50 2.00 1.00 27.00 2.000.152-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 0.50 2.00 1.00 27.00 2.000.152-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 0.50 2.00 1.00 27.00 2.000.152-12 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 1.00 27.00 2.00 0.153-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:18 1.00 2.00 1.00 27.00 2.000.153-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:47:48 0.45 1.00 0.50 2.00 1.00 27.00 2.000.153-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:37:48 0.45 1.00 0.50 2.00 1.00 27.00 2.000.153-4 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 1:18:15 0.45 1.00 0.50 2.00 1.00 27.00 2.000.153-5 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.153-6 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.153-7 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.153-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 0.50 2.00 1.00 27.00 2.000.153-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 0.50 2.00 1.00 27.00 2.000.153-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 0.50 2.00 1.00 27.00 2.000.153-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 0.50 2.00 1.00 27.00 2.000.153-12 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 1.00 27.00 2.00 0.154-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 2:03:31 1.00 2.00 1.00 27.00 2.000.154-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 2:01:01 0.45 1.00 0.50 2.00 1.00 27.00 2.000.154-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:51:01 0.45 1.00 0.50 2.00 1.00 27.00 2.000.154-4 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 1:31:27 0.45 1.00 0.50 2.00 1.00 27.00 2.000.154-5 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:24:09 0.45 1.00 0.50 2.00 1.00 27.00 2.000.154-6 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:19:09 0.45 1.00 0.50 2.00 1.00 27.00 2.000.154-7 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:10:08 0.45 1.00 0.50 2.00 1.00 27.00 2.000.154-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 1:00:44 0.45 1.00 0.50 2.00 1.00 27.00 2.000.154-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:45:30 0.45 1.00 0.50 2.00 1.00 27.00 2.000.154-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:31:22 0.45 1.00 0.50 2.00 1.00 27.00 2.000.154-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:21:18 0.45 1.00 0.50 2.00 1.00 27.00 2.000.154-12 27# Linear Flush 20 7,317 174 174 0:08:43 0:14:43 1.00 2.00 1.00 27.00 2.000.154-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 4-14 Shut-In Shut-In5-1 Shut-In Shut-In 2:07:01 5-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:07:01 5-3 Shut-In Shut-In 2:02:15 5-4 27# Linear Spacer and Dart Drop 15 6,999 167 167 0:11:07 2:02:15 1.00 2.00 1.00 27.00 2.000.155-5 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:51:08 0.45 1.00 0.50 2.00 1.00 27.00 2.000.155-6 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:37:48 0.45 1.00 0.50 2.00 1.00 27.00 2.000.155-7 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 1:18:15 0.45 1.00 0.50 2.00 1.00 27.00 2.000.155-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.155-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.155-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.155-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 0.50 2.00 1.00 27.00 2.000.155-12 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 0.50 2.00 1.00 27.00 2.000.155-13 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 0.50 2.00 1.00 27.00 2.000.155-14 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 0.50 2.00 1.00 27.00 2.000.155-15 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 1.00 27.00 2.00 0.156-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:18 1.00 2.00 1.00 27.00 2.00 0.156-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:47:48 0.45 1.00 0.50 2.00 1.00 27.00 2.00 0.156-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:37:48 0.45 1.00 0.50 2.00 1.00 27.00 2.00 0.156-4 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 1:18:15 0.45 1.00 0.50 2.00 1.00 27.00 2.00 0.156-5 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 0.50 2.00 1.00 27.00 2.00 0.15Interval 1Coyote@ 12983 - 12987 ft 104.7 °FInterval 2Coyote@ 12440 - 12444 ft 104.7 °FInterval 3Coyote@ 11944 - 11948 ft 104.7 °FInterval 4Coyote@ 11447 - 11451 ft 104.7 °FInterval 5Coyote@ 10949 - 10953 ft 104.6 °F6eft 104.6 °FLiquid Additives Dry Additives50-103-20905-01Conoco Phillips - 3T-731 Planned Design 1 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.41991874LEASE3T-731 L2SALES ORDERBHST (°F)105LONG-150.2692256FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 LD-6450 WG-36 OPTIFLO-IIBE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Clay ControlInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid Additives Dry Additives50-103-20905-016-6 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 0.50 2.00 1.00 27.00 2.00 0.156-7 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.156-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 0.50 2.00 1.00 27.00 2.000.156-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 0.50 2.00 1.00 27.00 2.000.156-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 0.50 2.00 1.00 27.00 2.000.156-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 0.50 2.00 1.00 27.00 2.000.156-12 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 1.00 27.00 2.00 0.157-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:50:18 1.00 2.00 1.00 27.00 2.000.157-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:47:48 0.45 1.00 0.50 2.00 1.00 27.00 2.000.157-3 27# Delta Frac Pad 20 16,430 391 391 0:19:34 1:37:48 0.45 1.00 0.50 2.00 1.00 27.00 2.000.157-4 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 1:18:15 0.45 1.00 0.50 2.00 1.00 27.00 2.000.157-5 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.0000 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.157-6 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.157-7 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.157-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 0.50 2.00 1.00 27.00 2.000.157-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 0.50 2.00 1.00 27.00 2.000.157-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 0.50 2.00 1.00 27.00 2.000.157-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 0.50 2.00 1.00 27.00 2.000.157-12 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 1.00 27.00 2.00 0.158-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:14 1.00 2.00 1.00 27.00 2.000.158-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:44 0.45 1.00 0.50 2.00 1.00 27.00 2.000.158-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:44 0.45 1.00 0.50 2.00 1.00 27.00 2.000.158-4 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.5000 20 6,000 143 146 3,000 0:07:18 0:43:35 0.45 1.00 0.50 2.00 1.00 27.00 2.000.158-5 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:16 0.45 1.00 0.50 2.00 1.00 27.00 2.000.158-6 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:41 0.45 1.00 0.50 2.00 1.00 27.00 2.000.158-7 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:10 0.45 1.00 0.50 2.00 1.00 27.00 2.000.158-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:28 0.45 1.00 0.50 2.00 1.00 27.00 2.000.158-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:16:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.158-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:09:52 0.45 1.00 0.50 2.00 1.00 27.00 2.000.158-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:04:50 0.45 1.00 0.50 2.00 1.00 27.00 2.000.158-12 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 1.00 27.00 2.00 0.159-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:13:33 1.00 2.00 1.00 27.00 2.000.159-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:11:03 0.45 1.00 0.50 2.00 1.00 27.00 2.000.159-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 1:01:03 0.45 1.00 0.50 2.00 1.00 27.00 2.000.159-4 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 0:54:54 0.45 1.00 0.50 2.00 1.00 27.00 2.000.159-5 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:47:35 0.45 1.00 0.50 2.00 1.00 27.00 2.000.159-6 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:45:00 0.45 1.00 0.50 2.00 1.00 27.00 2.000.159-7 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:40:29 0.45 1.00 0.50 2.00 1.00 27.00 2.000.159-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:35:47 0.45 1.00 0.50 2.00 1.00 27.00 2.000.159-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:28:15 0.45 1.00 0.50 2.00 1.00 27.00 2.000.159-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:21:11 0.45 1.00 0.50 2.00 1.00 27.00 2.000.159-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:16:09 0.45 1.00 0.50 2.00 1.00 27.00 2.000.159-12 27# Linear Flush 20 5,726 136 136 0:06:49 0:12:49 1.00 2.00 1.00 27.00 2.000.159-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 9-14 Shut-In Shut-In10-1 Shut-In Shut-In 1:13:09 10-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:13:09 10-3 Shut-In Shut-In 1:08:24 10-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:08:24 1.00 2.00 1.00 27.00 2.000.1510-5 27# Linear Pre-Pad 15 2,100 50 50 0:03:20 1:06:24 1.00 2.00 1.00 27.00 2.000.1510-6 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:03:04 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1510-7 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:44 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1510-8 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 0:43:35 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1510-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:16 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1510-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:41 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1510-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:10 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1510-12 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:28 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1510-13 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:16:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1510-14 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:09:52 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1510-15 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:04:50 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1510-16 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 1.00 27.00 2.00 0.1511-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:14 1.00 2.00 1.00 27.00 2.000.1511-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:44 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1511-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:44 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1511-4 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 0:43:35 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1511-5 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:16 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1511-6 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:41 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1511-7 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:10 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1511-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:28 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1511-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:16:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1511-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:09:52 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1511-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:04:50 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1511-12 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 1.00 27.00 2.00 0.1512-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:14 1.00 2.00 1.00 27.00 2.00 0.15Interval 9Coyote@ 8958 - 8962 ft 104.5 °FInterval 10Coyote@ 8460 - 8464 ft 104.5 °FInterval 11Coyote@ 7962 - 7966 ft 104.5 °FInterval Coyote@ 10451 - 10455 Interval 7Coyote@ 9954 - 9958 ft 104.6 °FInterval 8Coyote@ 9456 - 9460 ft 104.5 °FConoco Phillips - 3T-731 Planned Design 2 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.41991874LEASE3T-731 L2SALES ORDERBHST (°F)105LONG-150.2692256FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 LD-6450 WG-36 OPTIFLO-IIBE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Clay ControlInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid Additives Dry Additives50-103-20905-0112-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:44 0.45 1.00 0.50 2.00 1.00 27.00 2.00 0.1512-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:44 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1512-4 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 0:43:35 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1512-5 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:16 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1512-6 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:41 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1512-7 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:10 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1512-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:28 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1512-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:16:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1512-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:09:52 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1512-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:04:50 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1512-12 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 1.00 27.00 2.00 0.1513-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:14 1.00 2.00 1.00 27.00 2.000.1513-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:44 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1513-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:44 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1513-4 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 0:43:35 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1513-5 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:16 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1513-6 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:41 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1513-7 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:10 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1513-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:28 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1513-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:16:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1513-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:09:52 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1513-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:04:50 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1513-12 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 1.00 27.00 2.00 0.1514-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:14 1.00 2.00 1.00 27.00 2.000.1514-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 0:59:44 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1514-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:49:44 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1514-4 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 0:43:35 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1514-5 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:16 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1514-6 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:33:41 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1514-7 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:10 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1514-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:28 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1514-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:16:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1514-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:09:52 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1514-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:04:50 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1514-12 27# Linear Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 1.00 2.00 1.00 27.00 2.00 0.1515-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:02:44 1.00 2.00 1.00 27.00 2.000.1515-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:00:14 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1515-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:50:14 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1515-4 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 0:44:05 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1515-5 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:36:46 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1515-6 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:34:11 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1515-7 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:29:40 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1515-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:24:58 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1515-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:17:26 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1515-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:10:22 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1515-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:05:20 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1515-12 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 0:02:00 1.00 2.00 1.00 27.00 2.00 0.1516-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:10:54 1.00 2.00 1.00 27.00 2.000.1516-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:08:24 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1516-3 27# Delta Frac Pad 20 5,165 123 123 0:06:09 0:58:24 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1516-4 27# Delta Frac Conditioning Pad 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 0:52:15 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1516-5 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 2.00 20 2,000 48 52 4,000 0:02:36 0:44:56 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1516-6 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 4.00 20 3,200 76 90 12,800 0:04:30 0:42:21 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1516-7 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 6.00 20 3,100 74 94 18,600 0:04:42 0:37:50 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1516-8 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 7.00 20 4,800 114 150 33,600 0:07:32 0:33:08 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1516-9 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 8.00 20 4,350 104 141 34,800 0:07:04 0:25:36 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1516-10 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 9.00 20 3,000 71 100 27,000 0:05:02 0:18:32 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1516-11 27# Delta Frac Proppant Laden Fluid 16/20 Ceramic 10.00 20 1,920 46 66 19,200 0:03:20 0:13:30 0.45 1.00 0.50 2.00 1.00 27.00 2.000.1516-12 27# Linear Flush 20 3,500 83 83 0:04:10 0:10:10 1.00 2.00 1.00 27.00 2.000.1516-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 16-14 Shut-In Shut-In984,816 23,448 27,163 3,498,000Design Total (gal)Design Total (lbs)BC-140X2 Losurf-300D MO-67 CAT-3 LD-6450 WG-36 OPTIFLO-II BE-6905,775 3,498,000(gal) (gal) (gal) (gal) (gal) (lbs) (lbs) (lbs)72,261Initial Design Material Volume 407.6 978.0 452.9 1,956.1 978.0 26,407.0 1,956.1 146.7-6,780 - Whole Units to be ordered- -BC-140X2 Losurf-300D MO-67 CAT-3 LD-6450 WG-36 OPTIFLO-II BE-6-(gpm) (gpm) (gpm) (gpm) (gpm) ppm ppm ppm- Max Additive Rate 0.4 0.8 0.4 1.7 0.8 22.7 1.7 0.1- Min Additive Rate23:23:07 Interval 12Coyote@ 7465 - 7469 ft 104.5 °FInterval 13Coyote@ 6969 - 6973 ft 104.4 °FInterval 14Coyote@ 6471 - 6475 ft 104.4 °FInterval 15Coyote@ 5973 - 5977 ft 104.4 °FInterval 16Coyote@ 5475 - 5479 ft 104.4 °FProppant Type16/20 Ceramic100M---Fluid Type27# Delta Frac27# LinearSeawaterFreeze Protect----Conoco Phillips - 3T-731 Planned Design 3 SECTION 13 POST-FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.283(a)(13) After the fracture stimulation, ConocoPhillips (CPAI) plans to flowback the well for cleanup purposes for an estimated 7 to 14 days. The flowback liquids will be routed through a portable test separator then onto either CPF3 or Drill Site 3Ts facilities. Once the wells flowback liquids meet CPF3 criteria all liquids will be routed to CPF3. CPAI plans to limit the flowback time to what is necessary to achieve conforming production liquids. 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:Davies, Stephen F (OGC) To:"Ruysschaert, Rodrigo" Cc:Loepp, Victoria T (OGC); Dewhurst, Andrew D (OGC); Starns, Ted C (OGC); Wallace, Chris D (OGC) Subject:RE: 3T-731 B (PTD 225-124) Frac Sundry Submission Date:Monday, December 8, 2025 9:32:00 AM Hello Rodrigo, Thank you for the notification. CPAI's application to frac-stimulate 3T-731B is currently under AOGCC review. Yes, the original 3T-731 documents were helpful for expediting this process. We can't provide a guaranteed decision date, but it should be soon. Thanks Again for Your Help and Be Well, Steve Davies Senior Petroleum Geologist AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Ruysschaert, Rodrigo <Rodrigo.Ruysschaert@conocophillips.com> Sent: Monday, December 8, 2025 9:25 AM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: 3T-731 B (PTD 225-124) Frac Sundry Submission Good morning Steve, I am writing to inquire about the status of the Sundry application for the frac of well 3T-731 B. During the past days, we have made quick progress on the well work ahead of the frac, and it has been completed earlier than anticipated. Our frac unit is now pretty much ready to start. Could you please let us know if there is any chance of receiving the Sundry application back soon? As mentioned in the Sundry documentation submitted, this well is a lateral replacement of the original 3T-731, which was approved for fracture stimulation in the spring, and I was hoping this information can serve as a helpful reference for a quicker review. Please feel free to reach out if you need any additional information. Thank you for your assistance. Kind regards, Rodrigo Ruysschaert | Completions Engineer | ConocoPhillips O: + 1 907-263-3709| M: +1 907-621-0671 | 700 G Street, ATO-1586, Anchorage, AK 99501 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-731B (PTD No. 225-124; Sundry No. 325-732) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 December 9, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. SFD 12/3/2025 (a)(2) Plat Provided with application. SFD 12/3/2025 (a)(2)(A) Well location Provided with application. Well lies in Sections 1, 2, 12 and 13 of T12N, R7E, UM. SFD 12/3/2025 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNRs Alaska Mapper application (accessed online December 3, 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-731B. There are no subsurface water rights or temporary subsurface water rights within 5 miles of the surface location of KRU 3T-731B. SFD 12/3/2025 (a)(2)(C) Identify all well types within ½ mile Provided with application. SFD 12/3/2025 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. KRU 3T-731B lies within the boundary of the Kuparuk River Unit Aquifer Exemption as currently depicted on EPA Region 10's Alaska Oil & Gas Aquifer Exemptions Interactive Map, available through EPA Region 10s web site. However, this well also lies outside of the boundary of the Kuparuk River Unit of 1984 that may form 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 boundary applies to that aquifer exemption. AIO 45 states that a sample of the produced water from the 3S-24B well shows the total dissolved solids in the water produced from the Coyote Oil Pool is over 21,000 mg/l. SFD 12/8/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-731B (PTD No. 225-124; Sundry No. 325-732) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 December 9, 2025 Additional evidence for absence of freshwater sands beneath the surface casing shoes of wells drilled in the 3T Pad area is based on examination of well logs and a quick-look Pickett Plot analysis by AOGCC of a water-wet sand beneath permafrost in nearby well Moraine 1 (PTD 214-198, located 500 to the W), which has open-hole resistivity and porosity well logs. Two sands that lie between 1,996 and 2,069 MD (-1,914 to -1,986 TVDSS) yielded TDS values of about 16,500 mg/l. These sands correlate to the sand-interval in 3T-731B between about 2,092' and 2,126' MD (-1,958' to -1,990' TVDSS), which lies between the base of permafrost and the surface casing shoe. If the shallowest water-bearing sands in Moraine 1 have TDS concentrations greater than that of freshwater (3,000 to 10,000 mg/l), it is highly likely that all underlying water-bearing zones are also higher in TDS concentration. SFD 12/8/2025 (a)(4) Baseline water sampling plan None required. SFD 12/4/2025 (a)(5) Casing and cementing information Provided with application. As Run 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 150 bbl cement returns to surface. 7-5/8 casing shoe at 5087 ft MD. TOC by sonic log 3733 ft. 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 4922 ft MD, production packer 4786 ft MD. Liner cemented with 42 bbl losses of 254 bbl pumped (212 bbl in place) with gauge hole of 172 bbl caalc and 40 CDW 12/08/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-731B (PTD No. 225-124; Sundry No. 325-732) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 December 9, 2025 bbl cement circulated off liner top indicating cement to liner top. Uppermost frac sleeve 5475 ft MD. (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers present. (See Section (a)(3), above.) SFD 12/4/2025 (a)(6)( B) Each hydrocarbon zone is isolated Yes, cement isolates each hydrocarbon zone. Surface casing was set at 2,625 MD (-2,460 TVDSS) and cemented. Plug bumped and floats held. 150 barrels of cement returns to surface. The 7-5/8 intermediate casing shoe is set at 5,087 MD (-4,076 TVDSS). Top of good-quality cement interpreted from the USIT is at 3,733 MD (-3,461 TVDSS). The top of the Coyote interval lies at 5,006 MD (-4,065 TVDSS), so cement isolates the Coyote from overlying strata. The 4-1/2 production liner was set at 13,116 MD (-4,130 TVDSS) and 253 barrels of Class G 15.3 ppg cement were pumped, which (assuming 30% hole washout) is more than sufficient to reach the top of the liner at 4,922 MD (-4,052 TVDSS). SFD 12/4/2025 VTL 12/8/2025 (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 7575 and ePRV 8075 psi., tree test 10000 psi, lines test 10000 psi. CDW 12/08/2025 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone Upper confining zone: Seabee deep marine claystones with thin siltstones beds that have a top of 4,135 (-3,752 TVDSS) 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-731B (PTD No. 225-124; Sundry No. 325-732) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 December 9, 2025 (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 thickness of about 250 TVT. The fracture gradient is estimated to be more than 0.67 psi/ft from DFIT measurements that resulted in fracture closure pressure gradient of about 0.73 to 0.78 psi/ft (14.1 to 15.1 ppg EMW) and formation break-down pressure is estimated to be 0.82 to 0.93 psi/ft (15.8 to 17.9 ppg EMW). Fracturing Zone: The Coyote interval has top of about 5,003 MD (-4,065 TVDSS) and a thickness ranging from about 100 to 215 TVT. It is comprised of thinly interbedded sandstone and siltstone layers. The estimated fracture gradient is expected to be about 0.62 psi/ft (11.9 ppg EMW) but may range upward to 0.67 psi/ft to 0.84 psi/ft (12.9 to 16.1 ppg EMW). Induced fractures may penetrate a short distance into the overlying or underlying confining zones but will certainly not penetrate through them. The Coyote formation pressure is estimated to be 8.0 to 8.5 ppg. Lower confining zone: Torok basin floor mudstones present in thicknesses of about 830 TVT. The estimated base of the Coyote interval is estimated from seismic data to be -4,163 TVDSS at the heel of the well to -4,250 TVDSS at the toe of the well. The estimated fracture gradient ranges from 0.78 psi/ft to 0.94 psi/ft (15 to 18 ppg EMW). SFD 12/4/2025 (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 hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory 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. AOGCC evaluated 29 wells and wellbores that may transect the confining zones within and near the 3T-713B 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. SFD 12/8/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-731B (PTD No. 225-124; Sundry No. 325-732) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 December 9, 2025 (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 Two faults intersect the horizontal production section of the 3T-731 well and a third fault lies nearby. However, it is unlikely that these 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 first fault has 5 of vertical displacement and intersects 3T-731 and about 5,711 MD (-4,095 TVDSS) and has no seismic offset in the reservoir. The second intersects the well at 11,700 MD (-4,124 TVDSS), has 10 to 20 of vertical displacement, and dies out in the confining intervals above and below the Coyote. The third fault trends east-west, and the western tip of this fault appears to die out about 300 east of 3T-731. It appears to have only 5 to 10 of vertical displacement at the top of the Coyote reservoir, may have 65 of vertical displacement within the lower part of the overlying Seabee Shale, but it then dies out further upward in the Seabee. This fault is not expected to affect the integrity of the upper confining layer. SFD 12/4/2025 (a)(12) Proposed program for fracturing operation Provided with application. CDW 12/08/2025 (a)(12)(A) Estimated volume Provided with application. 16 stages. 27K bbl total dirty vol. 3.5Million 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-731B (PTD No. 225-124; Sundry No. 325-732) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 December 9, 2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 7075 psi. Max. 7318 psi allowable treating pressure. Max pressure is 7575 psi to 8075 psi to Pump shutdown. With 3500 psi back pressure IA (IA popoff set 3600 psi), max tubing differential should be 3575 psi. CDW 12/08/2025 (a)(12)(F) Fractures height, length, MD and TVD to top, description of fracturing model None of the induced fractures will penetrate through the confining intervals. The modeled half-lengths of the induced fractures range from 290' to 460' according to the Operator's Computer simulation. Computer simulation indicates the anticipated height of the induced fractures will range from 105' to 210', with a shallowest TVDSS of about -4,012 and deepest TVDSS of about -4,315. The top of the Coyote is about 4,065 TVDSS. The thickness of the reservoir varies from about 100 at the heel of the well (base Coyote at 4,225 TVDSS) to about 250 at the toe of the well (base Coyote at about 4,315 TVDSS). Some of the induced fractures may penetrate a short distance into the overlying Seabee and some may penetrate a short distance into the underlying Torok, but none of the induced fractures will penetrate through either of these thick, confining intervals. SFD 12/8/2025 (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. 4786 ft with sleeve planned for 5475 ft. TOC in 7-5/8 casing at 3733 ft so packer set > 100 ft below TOC and USIT conservatively shows good cement at area of interest so no cement concerns. CDW 12/08/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-731B (PTD No. 225-124; Sundry No. 325-732) Paragraph Sub-Paragraph Section Complete? AOGCC Page 7 December 9, 2025 Liner cemented with 42 bbl losses of 254 bbl pumped (212 bbl in place) with gauge hole of 172 bbl caalc and 40 bbl cement circulated off liner top indicating cement to liner top. (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 4200 psi. Max pressure differential is estimated as 3575 psi (7075 with 3500 psi backpressure) so test of 4200 psi satisfies > 110% CDW 12/08/2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 10000 psi line pressure test, pump knock out 7575 psi with max. global kickout 8075 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). SFD 12/8/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist KRU 3T-731B (PTD No. 225-124; Sundry No. 325-732) Paragraph Sub-Paragraph Section Complete? AOGCC Page 8 December 9, 2025 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. SFD 12/8/2025 (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. 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 Cameron Johnson Senior Drilling Engineer Conoco Phillips Alaska, Inc. 700 G Street Anchorage, AK, 99501 Re: Kuparuk River Field, Coyote Oil Pool, KRU 3T-731B Conoco Phillips Alaska, Inc. Permit to Drill Number: 225-124 Surface Location: 1634 FSL, 5151 FEL, S1 T12N R7E, UM Bottomhole Location: 3494 FSL, 3308 FEL, S13 T12N R7E, UM Dear Mr. Johnson: 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, Gregory Wilson Commissioner DATED this 14th day of November 2025. 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 13,118 TVD: 4182 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 51 15. Distance to Nearest Well Open Surface: x- 467338 y- 6003362 Zone- 4 12 to Same Pool: 275' to 3T-731 16. Deviated wells: Kickoff depth: 2841 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# H40 Welded 80 40 40 120 120 13-1/2" 10-3/4" 45.5# L80 H563 2585 40 40 2625 2511 9-7/8" 7-5/8" 29.7# L80 H563 4186 40 40 4226 3839 9-7/8" 7-5/8" 33.7# P110-S H563 800 4226 3839 5026 4111 6-1/2" 4-1/2" 12.6# P110-S H563 8092 4876 4080 13118 4182 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: Cameron Johnson Contact Email:cameron.johnson2@cop.com Senior Drilling Engineer Contact Phone: 907-223-6277 Date: Permit to Drill API Number: Permit Approval Number: Date: Conditions of approval : 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 Kuparuk River Field Coyote Oil Pool 11/16/2025 3309' to ADL380107 Cemented to surface with ~10 yds slurry 949 sx of 11.0 ppg Class G + Add's + 281 sx of 15.8 ppg Class G + Add's. Returns at surface 1343 Perforation Depth TVD (ft): 10 yards 2425' 2320 Cement Volume MD 1761 If checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: 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: Cameron Johnson Commission Use Only See cover letter for other requirements. Production Perforation Depth MD (ft): Intermediate Liner Surface 2,586.00 10-3/4" Lead: 438 bbls of 11.0 ppg ArcticCem Tail: 58 bbls of 15.8 ppg Class G Surface Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Conductor/Structural 80.00 20" 3000 2872 2425' MD to 3000' MD Casing Length Size P.O. Box 100360 Anchorage, Alaska, 99510-0360 1634 FSL, 5151 FEL, S1 T12N R7E, UM ADL025528 / ADL025544 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ConocoPhillips Alaska Inc 59-52-180 KRU 3T-731B 189 sx of 15.3 ppg Class G + Add's 989 sx of 15.3 ppg Class G + Add's 1001 FSL, 4434 FEL, S1 T12N R7E, UM LONS 01-013 3494 FSL, 3308 FEL, S13 T12N R7E, UM 2560 / 2560 GL / BF Elevation above MSL (ft): 18. Casing Program:Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks (including stage data) Total Depth MD (ft): Total Depth TVD (ft): ons of approval : 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 If checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: to Drill API Number: Permit Approval er:Date: See cover letter for other requirements. Commission Use Only pe of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Lateral Stratigraphic Test Development - Oil Service - W inj Single Zone Coalbed Gas Gas Hydrates Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas rator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. ress:6. Proposed Depth:12. Field/Pool(s): MD: 13,118 TVD: 4182 cation of Well (Governmental Section):7. Property Designation: e: Productive Horizon:8. DNR Approval Number:13. Approximate Spud Date: Depth:9.Acres in Property:14.Distance to Nearest Property: cation of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 51 15. Distance to Nearest Well Open e: x- 467338 y- 6003362 Zone- 4 12 to Same Pool: 275' to 3T-731 viated wells: Kickoff depth: 2841 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90° degrees Downhole: Surface: ole Casing Weight Grade Coupling Length MD TVD MD TVD 2" 20" 94# H40 Welded 80 40 40 120 120H40 1/2" 10-3/4" 45.5# L80 H563 2585 40 40 2625 2511L80 7/8" 7-5/8" 29.7# L80 H563 4186 40 40 4226 383929.7# L80 7/8" 7-5/8" 33.7# P110-S H563 800 4226 3839 5026 411133.7# P110-S /2" 4-1/2" 12.6# P110-S H563 8092 4876 4080 13118 418212.6# P110-S PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD ulic Fracture planned?Yes No tachments: Property Plat BOP Sketch Drhilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketchh Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Cameron Johnson Contact Email:cameron.johnson2@cop.com Senior Drilling Engineer Contact Phone:907-223-6277 Date: Kuparuk River Field Coyote Oil Pool 11/16/2025 3309' to ADL380107 Cemented to surface with ~10 yds slurry 949 sx of 11.0 ppg Class G + Add's + 281 sx of 15.8 ppg Class G + Add's. Returns at surface 1343 Perforation Depth TVD (ft): 10 yards 2425' 2320 Cement Volume MD 1761 hereby certify that the foregoing is true and the procedure approved herein will not be ed from without prior written approval. ized Name: ized Title: ized Signature: Cameron Johnson Production ation Depth MD (ft): Intermediate Liner Surface 2,586 10-3/4" Lead: 438 bbls of 11.0 ppg2,586.00 ArcticCem Tail: 58 bbls of 15.8 ppg Class G Surface Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): nductor/Structural 80.00 20"80.00 3000 2872 2425' MD to 3000' MD Casing Length Size ox 100360 Anchorage, Alaska, 99510-0360 1634 FSL, 5151 FEL, S1 T12N R7E,UM ADL025528 / ADL025544 oPhillips Alaska Inc 59-52-180 KRU 3T-731B 189 sx of 15.3 ppg Class G + Add's 989 sx of 15.3 ppg Class G + Add's 1001 FSL, 4434 FEL, S1 T12N R7E, UM LONS 01-013 3494 FSL, 3308 FEL, S13 T12N R7E, UM 2560 / 2560 GL /BF El ti b MSL (ft) sing Program:Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks (including stage data) al Depth MD (ft): Total Depth TVD (ft): Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 225-124 By Grace Christianson at 2:24 pm, Nov 13, 2025 A.Dewhurst 13NOV25 VTL 11/14/2025 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 2,625 120 120 X 2,511 50-103-20905-02-00 JLC 11/14/2025 11/14/25 11/14/25 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. CPAIs 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 November 13, 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill KRU 3T-731B Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill to re-drill the 3T-731A well from a cement kick-off plug under the surface casing shoe The intended kick-off date for this well is November 16, 2025. Doyon 142 will perform the work. The 3T-731A wellbore will be abandoned by placing a cement retainer above the window in the 7-5/8 casing and squeezing cement below the retainer to abandon the rat hole. A cement retainer will be set in the 7-5/8 casing below the surface casing shoe. The 7-5/8 casing will be cut above this retainer. A cement kick off plug will be set on this cement retainer with a top ~200 inside the surface casing shoe. This abandonment is covered with a separate sundry. The 3T-731B wellbore will kick off this plug. A 9-7/8 intermediate hole section will be drilled. 7-5/8 casing will be run and cemented. A 6-1/2 production lateral will be drilled in the Coyote formation to a total depth of ~13118 MD. The production lateral will be completed with a cemented 4-1/2 Liner containing frac sleeves. The upper completion will include a production packer with GLMs and a downhole gauge 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. This variance allows for effective drilling and completion of problematic zones and longer intervals in the well construction process. 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. Proposed drilling program 3. Proposed drilling fluids program summary 4. Proposed completion diagram 5. Pressure information as required by 20 ACC 25.005 (c) (4) (a-c) 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 Cameron Johnson at 907-223-6277 (Cameron.johnson2@conocophillips.com). Sincerely, cc: 3T-731B Well File / Jenna Taylor ATO 1804 Will Earhart ATO 1552 Cameron Johnson Drilling Engineer Patrick Perfetta ATO-1408 3T-731B AOGCC 10-401 APD 11/13/2025 3T-731B AOGCC 10-401 APD 1 | 11 3T-731B Well Plan Application for Permit to Drill Table of Contents 1. Well Name ......................................................................................................................................... 2 2. Location Summary ............................................................................................................................. 2 3. Proposed Drilling Program ................................................................................................................. 4 4. BOP and Diverter Information ........................................................................................................... 4 5. MASP Calculations ............................................................................................................................. 6 6. Procedure for Conducting Formation Integrity Tests ........................................................................ 7 7. Casing and Cementing Program......................................................................................................... 7 8. Drilling Fluid Program ........................................................................................................................ 8 9. Abnormally Pressured Formation Information .................................................................................. 9 10. Seismic Analysis ................................................................................................................................. 9 11. Seabed Condition Analysis ................................................................................................................. 9 12. Evidence of Bonding .......................................................................................................................... 9 13. Discussion of Mud and Cuttings Disposal and Annular Disposal ........................................................ 9 14. Drilling Hazards Summary ................................................................................................................ 10 15. Proposed Completion Schematic ..................................................................................................... 11 16. Attachments .................................................................................................................................... 11 3T-731B AOGCC 10-401 APD 11/13/2025 3T-731B AOGCC 10-401 APD 2 | 11 1. Well Name Requirements of 20 AAC 25.005 (f) The well for which this application is submitted will be designated as KRU 3T-731B 2. Location Summary Requirements of 20 AAC 25.005(c)(2) Location at Surface 1634 FSL, 5151 FEL, S1 T12N R7E, UM NAD27 Northing: 6003362.00 Easting: 467338.00 RKB Elevation 51.1AMSL Pad Elevation 12AMSL Top of Productive Horizon (Heel) 1001 FSL, 4434 FEL, S1 T12N R7E, UM NAD27 Northing: 6002421.30 Easting: 468053.06 Measured Depth, RKB: 4961 Total Vertical Depth, RKB: 4100 Total Vertical Depth, SS: 4049 Total Depth (Toe) 3494 FSL, 3308 FEL, S13 T12N R7E, UM NAD27 Northing: 5994655.65 Easting: 469148.88 Measured Depth, RKB: 13118 Total Vertical Depth, RKB: 4182 Total Vertical Depth, SS: 4131 Pad Layout 3T-731B AOGCC 10-401 APD 11/13/2025 3T-731B AOGCC 10-401 APD 3 | 11 Well Plat 3T-731B AOGCC 10-401 APD 11/13/2025 3T-731B AOGCC 10-401 APD 4 | 11 3. Proposed Drilling Program Requirements of 20 AAC 25.005(c)(13) 1. Continue operations from 3T-731A Sundry 2. MU 9-7/8 Intermediate drilling assembly 3. Kick off cement kick-off plug under the surface casing shoe 4. Drill 9-7/8 Intermediate hole section to TD in the Coyote formation (LWD Program: GR/RES) 5. Run 7-5/8 casing 6. Cement 7-5/8 casing with cement 250 TVD above the top of the Coyote 7. Change upper pipe rams to VBRs and test UPR 8. MU 6-1/2 Production drilling assembly 9. Drill out 7-5/8 Surface casing shoe and 20 of new formation 10. Perform FIT to 16.0 ppg max. Minimum acceptable leak off value is 10.5 ppg 11. Drill 6 1/2 hole to section TD of ~13118 MD (LWD Program: GR/RES/Den/Neu). 12. Circulate the hole clean and POOH. 13. Run 4 1/2 liner with toe valve, frac sleeves and liner hanger to TD. 14. Perform 4-1/2 liner cement job 15. Run 4 1/2 upper completion with glass plug, production packer, downhole gauge, and gas lift mandrels. Space out and land tubing hanger. 16. Pressure test hanger seals to 5000 psi. 17. Pressure up against the glass plug to set production packer, test tubing to 4200 psi, chart test. 18. Bleed tubing pressure to 2200 psi and test IA to 3,850 psi, chart test. 19. Install HP-BPV and test to 1500 psi. 20. Nipple down BOP. 21. Install tubing head adapter assembly. N/U tree and test to 10000 psi/10 minutes. 22. Freeze protect down tubing and annulus. 23. Secure well. Rig down and move out. Please note This well will be fracd 4. BOP and Diverter Information 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, 7-5/8 solid body rams, blind/shear rams, and variable bore rams while drilling and casing for the intermediate section of 3T-731B. Doyon 142 will use a BOPE stack equipped with an annular preventer, variable bore rams, blind/shear rams, and variable bore rams while drilling and running liner for the production hole section of 3T-731B. 3T-731B has a MASP of 1321 psi in the intermediate hole section and 1343 psi in the production hole section using the methodology in section 5 MASP calculations. With a MASP less than 3000 psi ConocoPhillips classifies the operation as a Class 2. Per 20AAC 25.035.e.a.A: 3T-731B AOGCC 10-401 APD 11/13/2025 3T-731B AOGCC 10-401 APD 5 | 11 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 Annular Preventer (iii) 7-5/8 fixed rams Blind/Shear Rams (ii) 3-1/2 x 6VBRs (i) Production Drilling/Casing: Annular Preventer (iii) 3-1/2 x 6VBRs (i) Blind/Shear Rams (ii) 3-1/2 x 6VBRs (i) 3T-731B AOGCC 10-401 APD 11/13/2025 3T-731B AOGCC 10-401 APD 6 | 11 5. MASP Calculations Requirements of 20 AAC 25.005(c)(4) (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 = [( × 0.052 ) ] × = ( ) × 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 INT1 9-7/8" 10-3/4" 2625 2511 14 8.1 1,058 5026 4111 8.1 1,732 1,321 1,577 1,321 PROD 6-1/2" 7-5/8" 5026 4111 14 8.1 1,732 13118 4182 8.1 1,761 1,343 2,582 1,343 (B) data on potential gas zones; The planned wellbore 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 3T-731B AOGCC 10-401 APD 11/13/2025 3T-731B AOGCC 10-401 APD 7 | 11 6. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) Drill out window and perform LOT test or FIT in accordance with the LOT/FIT procedure that ConocoPhillips Alaska has on file with the Commission. 7. 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 7-5/8 9-7/8 29.7 33.7 L80 P110-S Hyd 563 42 bbls => 189 sx of 15.3 ppg Class G + Add's + Add's @ 1.24 ft³/sk 4 1/2 6 1/2 12.60 P110-S Hyd563 231 bbls => 989 sx of 15.3 ppg Class G + Add's + Add's @ 1.31 ft³/sk 7-5/8 Intermediate Casing: 5026' MD/ 4111' TVD Top of slurry is designed to be at 4247' MD/ 3850' TVD, which is 250 TVD above the prognosed 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 40% excess annular volume. Tail 42 bbls => 189 sx of 15.3 ppg Class G + Add's + Add's @ 1.24 ft³/sk 4 1/2 Production Liner: 13118' MD/ 4182' TVD Top of slurry is designed to be at the liner top at 4876' MD/ 4080' TVD, Assume 30% excess annular volume in the open hole and 0% Excess in the 7-5/8 Intermediate Casing. Tail 231 bbls => 989 sx of 15.3 ppg Class G + Add's + Add's @ 1.31 ft³/sk OD Hole Size Depth (MD) Weight Grade Conn. 20 42 120 94 H-40 Welded 10 3/4 13 1/2 2625 45.5 L-80 Hyd563 Cement Program 10 yds 949 sx of 11.0 ppg Lead and 281 sx of 15.8 ppg Tail (cement returned to surface) Casing and Cement In Place 3T-731B AOGCC 10-401 APD 11/13/2025 3T-731B AOGCC 10-401 APD 8 | 11 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) Intermediate Production Hole Size in. 9-7/8 6 1/2 Casing Size in. 7-5/8 4 1/2 Density PPG 9.0 - 9.5 9.0 10.5 PV cP <22 <20 YP lb./100 ft2 20-30 10-20 Funnel Viscosity s/qt. 40-60 35-50 Initial Gels lb./100 ft2 8 - 15 5- 10 10 Minute Gels lb./100 ft2 <20 7 - 15 API Fluid Loss cc/30 min. <10 < 6.0 HPHT Fluid Loss cc/30 min. Not Measured < 10.0 pH 9.0-10.0 NA OWR NA 75:25 80:20 E-Stability NA 400 1000 9-7/8 Intermediate Hole: A Fresh water polymer mud system will be used in the intermediate hole section. Ensure good hole cleaning by pumping regular sweeps and maximizing fluid annular velocity. Mud weight may be adjusted formation stability. Lost circulation material will be available and added if needed. 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 drilling fluid weighted to 9.0 10.5 ppg. MPD will be available for adding backpressure during connections if necessary. Diagram of Doyon 142 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. 3T-731B AOGCC 10-401 APD 11/13/2025 3T-731B AOGCC 10-401 APD 9 | 11 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) N/A - Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) N/A - Application is not for an offshore well. 12. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. 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. 3T-731B AOGCC 10-401 APD 11/13/2025 3T-731B AOGCC 10-401 APD 10 | 11 14. Drilling Hazards Summary 9-7/8 Hole / 7-5/8 Casing Intermediate Interval Event Risk Level Mitigation Strategy Sloughing shale Medium Maintained planned mud weight. Be prepared to weight up if needed. Use good hole cleaning practices to remove cuttings/cavings from hole Hole swabbing on trips Low Reduce trip speeds, condition mud properties prior to trips, ensure proper hole fill, pump out of hole Lost circulation Medium Monitor ECD while drilling ahead. Follow trip schedules to minimize surge. Be prepared with lost circulation material Abnormal Reservoir Pressure Low Well control drills, check for flow during connections, be prepared to increase mud weight 6 1/2 Hole / 4 1/2 Liner - Horizontal Production Interval Event Risk Level Mitigation Strategy Lost circulation Medium Reduce pump rates, real time ECD monitoring, maintain mud rheology, add lost circulation material as needed Hole swabbing on trips Medium 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 Medium Uniform reservoir pressure along lateral, keep pipe moving, control mud weight Running Liner to Bottom Medium 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 To be posted in Rig Floor Doghouse Prior to Spud Well Proximity Risks: 3T is a multi-well pad. Directional drilling / collision avoidance information as required by AOGCC 20 ACC 25.050 (b) is provided in the following attachments. 3T-731B AOGCC 10-401 APD 11/13/2025 3T-731B AOGCC 10-401 APD 11 | 11 15. Proposed Completion Schematic 16. Attachments 3T-731B wp04.1 Plan Summary 0 3 2000 4000 6000 8000 10000 12000 Measured Depth 10-3/4" Surface 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] 290030003100 319932993399349935993699 3799 38983T-731 290030003100 319932993399349935993699 3799 38983T-731A 0 2250 0 1000 2000 3000 4000 5000 6000 7000 Vertical Section at 167.99° 20" Conductor Casing 7-5/8" Intermediate Casing 0 20 40 Centre to Centre Separation2925 3150 3375 3600 3825 4050 4275 4500 Measured Depth Equivalent Magnetic Distance DDI 6.837 SURVEY PROGRAM Date: 2025-08-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 118.75 167.27 3T-713 Srvy 1 - SLB MWD Inc only r.5 MWD 258.69 2558.05 3T-731 Srvy 2 - SLB Srvy - IPM IFR MWD+IFR2+SAG+MS 2651.74 2840.64 3T-731 Srvy 3 - SLB Srvy - IPM IFR MWD+IFR2+SAG+MS 2840.64 3600.00 3T-731B wp04.1 (3T-731B) r.5 GYD_Quest_GWD 3600.00 13118.19 3T-731B wp04.1 (3T-731B) r.5 MWD+IFR2+SAG+MS Ground / 12.00 CASING DETAILS TVD MD Name 4111.00 5025.73 7-5/8" Intermediate Casing 4182.00 13118.19 4-1/2" Production Liner Mag Model & Date: BGGM2025 25-Nov-25 Magnetic North is 13.47° East of True North (Magnetic Declinatio Mag Dip & Field Strength: 80.59° 57146.39nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 2840.64 15.91 95.81 2718.11 507.98 -99.50 0.00 0.00 -517.56 Start DLS 2.68 TFO 102.40 2 2900.00 15.64 101.57 2775.24 505.55 -83.57 2.68 102.40 -511.87 Start DLS 3.00 TFO 40.00 3 3150.00 21.91 114.57 3011.91 479.35 -8.01 3.00 40.00 -470.54 Start DLS 3.75 TFO 47.92 4 4731.70 75.03 155.92 4043.80 -422.89 630.23 3.75 47.92 544.74 Start 88.75 hold at 4731.70 MD 5 4820.45 75.03 155.92 4066.73 -501.16 665.21 0.00 0.00 628.57 Start DLS 3.75 TFO 49.67 6 5399.50 89.50 172.30 4145.00 -1050.00 820.00 3.75 49.67 1197.61 Start DLS 3.75 TFO 7.65 7 5405.57 89.73 172.33 4145.04 -1056.01 820.81 3.75 7.65 1203.65 Start 7712.62 hold at 5405.57 MD 813118.19 89.73 172.33 4182.00 -8699.55 1850.14 0.00 0.00 8894.11 3T-731A T02 111125 TD at 13118.19 FORMATION TOP DETAILS TVDPath Formation 3731.00 C-35 4070.00 K-3 4100.00 Coyote 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 3T-731 actual @ 51.00usft (D142) 0150030004500True Vertical Depth0 1500 3000 4500 6000 7500 9000Vertical Section at 167.99°20" Conductor Casing7-5/8" Intermediate Casing4-1/2" Production Liner3T-7 31 10-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner2000300040005000600070008000900010000110001200013000131180°30°90°3T-731A wp04.1Start DLS 3.00 TFO 40.00Start DLS 3.75 TFO 47.92Start 88.75 hold at 4731.70 MDStart DLS 3.75 TFO 49.67Start DLS 3.75 TFO 7.65Start 7712.62 hold at 5405.57 MDTD at 13118.19C-35K-3Coyote3T-731 wp04.112:26, November 12 2025Section View -8000-6000-4000-20000South(-)/North(+)-6000 -4000 -2000 0 2000 4000 6000 8000West(-)/East(+)3T-731A T01 1111253T-731A T02 1111257-5/8" Intermediate Casing4-1/2" Production Liner20" Conductor Casing10-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner20002 5 0 0 40003T-731 wp04.1While drilling production section, stay within 100 feet laterally of plan, unless notified otherwise.12:26, November 12 2025 0.000.501.001.502.002.503.003.504.004.505.005.50Separation Factor3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500Measured Depth (1500 usft/in)Moraine 13S-6123S-7193S-740 (I13) wp063T-731STOP DrillingTake Immediate ActionCaution - Monitor CloselyNormal OperationsProject: Kuparuk River Unit_2Site: Kuparuk 3T PadWell: 3T-731Wellbore:3T-731Design: 3T-731 wp04.1 0 30 60 Centre to Centre Separation2800 3150 3500 3850 4200 4550 Partial Measured Depth Equivalent Magnetic Distance 3T-731 wp04.1 Ladder View 0 150 300 Centre to Centre Separation3000 4500 6000 7500 9000 10500 12000 Measured Depth Equivalent Magnetic Distance SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 118.75 167.27 3T-713 Srvy 1 - SLB MWD Inc only r.5 MWD 258.69 2558.05 3T-731 Srvy 2 - SLB Srvy - IPM IFR MWD+IFR2+SAG+MS 2651.74 2840.64 3T-731 Srvy 3 - SLB Srvy - IPM IFR MWD+IFR2+SAG+MS 2840.64 3600.00 3T-731A wp04.1 (3T-731A) r.5 GYD_Quest_GWD 3600.0013118.19 3T-731A wp04.1 (3T-731A) r.5 MWD+IFR2+SAG+MS 12:38, November 12 2025 CASING DETAILS TVD MD Name 4111.00 4888.46 7-5/8" Intermediate Casing 4178.13 13118.19 4-1/2" Production Liner 3T-731 wp04.1 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] 284128602880290029202940 29602980300030203040306030803100 31203140315931793199321932393259327932993319333933593379339934193439345934793499351935393559357935993619363936593679369937193739375937793799381938383858387838983918393839583977399740174037405740774096411641364156417641964216423642564276429643164336435643764396441644373T-731 SURVEY PROGRAM Date: 2025-08-26T00:00:00 Validated: Yes Version: From To Tool 118.75 167.27 r.5 MWD 258.69 2558.05 MWD+IFR2+SAG+MS 2651.74 2840.64 MWD+IFR2+SAG+MS 2840.64 3600.00 r.5 GYD_Quest_GWD 3600.00 13118.19 r.5 MWD+IFR2+SAG+MS CASING DETAILS TVD MD Name 4111.00 4888.46 7-5/8" Intermediate Casing 4178.13 13118.19 4-1/2" Production Liner SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 2840.64 15.91 95.81 2718.11 507.98 -99.50 0.00 0.00 -517.56 Start DLS 2.68 TFO 102.40 2 2900.00 15.64 101.57 2775.24 505.55 -83.57 2.68 102.40 -511.87 Start DLS 3.00 TFO 40.00 3 3150.00 21.91 114.57 3011.91 479.35 -8.01 3.00 40.00 -470.54 Start DLS 3.75 TFO 47.92 4 4731.70 75.03 155.92 4043.80 -422.89 630.23 3.75 47.92 544.74 Start 88.75 hold at 4731.70 MD 5 4820.45 75.03 155.92 4066.73 -501.16 665.21 0.00 0.00 628.57 Start DLS 3.75 TFO 49.67 6 5399.50 89.50 172.30 4145.00 -1050.00 820.00 3.75 49.67 1197.61 Start DLS 3.75 TFO 7.65 7 5405.57 89.73 172.33 4145.04 -1056.01 820.81 3.75 7.65 1203.65 Start 7712.62 hold at 5405.57 MD 813118.19 89.73 172.33 4182.00 -8699.55 1850.14 0.00 0.00 8894.11 3T-731A T02 111125 TD at 13118.19 3T-731 wp04.1Spider Plot12:43, November 12 20252840.64 To 13118.19Northing (1500 usft/in)Easting (1500 usft/in)2 6272830343536373839404142 2730313233343539404 1 4 227303132333435394041 4 227303132333435394041 4 2 2 6272 82931323338393031333438394026272626262728292627 2 8 2 9 3 0 3 1 3 2 3 3 3 4 3 5 3 6 3 7 3 826272930313233343536373839 2930313233343536373839402728293031323334353637383940272829303132333435363738394041262728293031323334353637383935363940423536394042282931323536373842273031343839404142262728293031323 334 282930323334353738404228293032333435373840422627282930313234353637394042262728 2930313233343536373839 4041 4226272829303132333435373940422728293233363726272930313435373940412728293233353637384041422627283132343536373840414226272830333435383940414226272829303132333435363738394041422627293031333739402627282930313334353738394042262932343536383940422627282930 31323334353637383940262930313 233 3738262728293132333435363738 3 9 4041262728293132333435363738 3 9 40412627 28 29 303 1 323334353637383 92627282930313334353637383941282933262728293031272930323537394042 293031323335363741 3T-731 wp04.1Spider Plot12:45, November 12 20252840.64 To 13118.19Northing (200 usft/in)Easting (200 usft/in)2 6272830 3133343839402 627282930 31323335363741 3T-731A wp04.1Moraine 1NDST-02PB1Nuna 1PB13T-616PB23T-6213T-7303T-7313S-173S-6103S-6113S-611PB13S-6123S-6133S-6153S-6173S-6203S-6253S-6263S-626PB13S-73S-7053S-740 (I13) wp063S-741 (P13) wp013-D View3T-731 wp04.112:50, November 12 2025 3T-731A wp04.1Moraine 1NDST-02PB13T-7303T-73133S-173S-17A3S-6023S-6063S-6103S-6113S-6123S-6133S-6173S-6203S-6243S-6263S-626PB13S-7033S-7053S-740 (I13) wp063S-741 (P13) wp013-D View3T-731 wp04.112:51, November 12 2025 -10000-8000-6000-4000-20000South(-)/North(+) (2000 usft/in)-6000 -4000 -2000 0 2000 4000 6000 8000 10000West(-)/East(+) (2000 usft/in)41004200M o r a in e 1 NDST-02NDST-02PB1Nuna 13T-614 wp143T-6033T-6083T-609 wp08.13T-611 wp14.13T-6123T-614 wp144 1 0 0 4 1 5 0 4 2 0 04100 4 1 5 0 4 2 0 0 3T-616PB14 1 0 0 4 1 5 0 4 2 0 03T-6193T -6 21 41503T-7303T-731A4100415042003T-624 wp05 v54 1 00 4 15 0 4 20 03T-628 wp06410041504100415041004150410041503S-0341004150410041503S-073S-083S-08A3S-08B3S-08CL13S-08CL1PB13S-09410042003S-1441504200410041504100415042003S-174100415042004100415042003S-184100415042003S-193S-214 1 0 041504200 3 S -2 2 3 S -2 33S-243S-24A3S-24B4 1 0 0415042003S-2 6 410041504200PALM 1415042004100415042004100415042003S-611PB14100415042003S-6124100415042003S-6134100415042003S-615410041503S-617410041504200410041503S-62441004150 4200 3S-625415042004100415042004100415042003S-7013S-701A41003S-7033S-704410041004150415041003S-719PB141003S-72141503S-72341003S-709 (I05) wp013S-727 (P23A) wp0341003S-734 (P04) wp034100415042003S-740 (I13) wp06410041503T-731A wp04.13T-731 wp04.1Quarter Mile View12:54, November 12 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T-731A T02 111125 4182.00 Circle (Radius: 100.00)3T-731A T01 111125 4141.00 Circle (Radius: 1320.00)3T-731A T01 QM 4141.00 Circle (Radius: 100.00)3T-731A T02 QM 4182.00 Circle (Radius: 1320.00) -10000-8000-6000-4000-20000South(-)/North(+) (2000 usft/in)-6000 -4000 -2000 0 2000 4000 6000 8000 10000West(-)/East(+) (2000 usft/in)41004200M o r a in e 1410041504200 3S-6124100415042003S-615415041003S-719PB141003S-72120" Conductor Casing10-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner410041503T-731A wp04.13T-731 wp04.1Quarter Mile View12:57, November 12 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T-731A T02 111125 4182.00 Circle (Radius: 100.00)3T-731A T01 111125 4141.00 Circle (Radius: 1320.00)3T-731A T01 QM 4141.00 Circle (Radius: 100.00)3T-731A T02 QM 4182.00 Circle (Radius: 1320.00) 3T-731 wp04.1 Surface Location 3T-731 wp04.1 Surface Location # Schlumberger-Confidential 3T-731 wp04.1 Surface Casing 3T-731 wp04.1 Surface Casing # Schlumberger-Confidential 3T-731 wp04.1 KOP 3T-731 wp04.1 KOP # Schlumberger-Confidential 3T-731 wp04.1 Top Coyote 3T-731 wp04.1 Top Coyote # Schlumberger-Confidential 3T-731 wp04.1 Intermediate Csg 3T-731 wp04.1 Intermediate Csg # Schlumberger-Confidential 3T-731 wp04.1 TD 3T-731 wp04.1 TD # Schlumberger-Confidential 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:Johnson, Cameron To:Loepp, Victoria T (OGC) Cc:Dewhurst, Andrew D (OGC) Subject:RE: [EXTERNAL]CPAI_KRU 3T-731B Please check cement calcs for production liner Date:Friday, November 14, 2025 7:50:57 AM Victoria, Please see production liner cement details below. Production Liner Cement Lateral TD 13118 7-5/8" Intermediate Shoe 5026 Top of Liner 4876 OH ID 6.5 7-5/8" Casing ID 6.765 Liner OD 4.5 Liner ID 3.958 4-1/2" X 6-1/2" Annular Capacity 0.02137 4-1/2" x 6-1/2" Footage 8092 4-1/2" x 6-1/2" Volume 172.94 30% Excess 51.8819 Total Volume 224.821 4-1/2" x 7-5/8" Annular Capacy 0.02479 4-1/2" x 7-5/8" Footage 150 4-1/2" x 7-5/8" Volume 3.71798 Shoe track length 120 Shoe track capacity 0.01522 Shoe track volume 1.8262 Total Cement Volume (bbls) 230.366 Total cement Volume (ft^3) 1293.41 Yield (ft^3/sx) 1.31 Total Cement (sacks) 987.333 Cam Johnson | Drilling Engineer | ConocoPhillips Alaska M: 907.223.6277 | M: 907.720.3162 | ATO-1540, 700 G Street, Anchorage, AK From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Friday, November 14, 2025 6:49 AM To: Johnson, Cameron <Cameron.Johnson2@conocophillips.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL]CPAI_KRU 3T-731B Please check cement calcs for production liner 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. Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 From:Loepp, Victoria T (OGC) To:Cameron Johnson Subject:Re: KRU 3T-731A (PTD 225-103) Sundry Application - Plug for Re-Drill - APPROVAL Date:Wednesday, November 12, 2025 9:45:21 PM Cameron, Approval is granted to proceed as outlined below. Victoria Sent from my iPhone On Nov 12, 2025, at 9:22PM, Johnson, Cameron <Cameron.Johnson2@conocophillips.com> wrote: Victoria, Schlumberger loaded out 50 bbls of 16.5 ppg cement. The rig will pump all 50 bbls. Placing ~35 bbls below the cement retainer and leave ~15 bbls on top of the retainer. Cam Johnson | Drilling Engineer | ConocoPhillips Alaska M: 907.223.6277 | M: 907.720.3162 | ATO-1540, 700 G Street, Anchorage, AK From: Johnson, Cameron Sent: Wednesday, November 12, 2025 8:54 PM To: 'Loepp, Victoria T (OGC)' <victoria.loepp@alaska.gov>; 'Guhl, Meredith D (OGC' <meredith.guhl@alaska.gov>; 'Dewhurst, Andrew D (OGC)' <andrew.dewhurst@alaska.gov>; 'Davies, Stephen F (OGC)' <steve.davies@alaska.gov>; 'Starns, Ted C (OGC)' <ted.starns@alaska.gov>; 'AOGCC Permitting (CED sponsored)' <aogcc.permitting@alaska.gov> Cc: Taylor, Jenna <Jenna.L.Taylor@conocophillips.com>; Earhart, Will C <William.C.Earhart@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: KRU 3T-731A (PTD 225-103) Sundry Application - Plug for Re-Drill Victoria, As discussed on the phone, the rig was unable to get to the originally planned set depth of the retainer for the lower abandonment. The plan forward for the rig is outlined below. Set cast iron cement retainer at current depth of 4135 MD. Pump the abandonment cement plug as previously planned Pump 35 bbls 16.5 ppg cement. Bullhead 20 bbls below the retainer, leaving 15 bbls on top of the retainer. The volume below the retainer to TD of the rat hole is 16.4 bbls (14.8 bbls inside 7-5/8 casing and 1.6 bbls in the open hole). Please reply to this email with approval to proceed. Thank you, Cam Johnson | Drilling Engineer | ConocoPhillips Alaska M: 907.223.6277 | M: 907.720.3162 | ATO-1540, 700 G Street, Anchorage, AK From: Johnson, Cameron Sent: Wednesday, November 12, 2025 12:33 PM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Guhl, Meredith D (OGC <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Taylor, Jenna <Jenna.L.Taylor@conocophillips.com>; Earhart, Will C <William.C.Earhart@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: KRU 3T-731A (PTD 225-103) Sundry Application - Plug for Re-Drill Good afternoon Attached is the sundry package for plugging back the KRU 3T-731A well to be re-drilled from under the surface casing shoe. As noted in the email below, verbal approval has been given to begin the abandonment process. This work is anticipated to start on this evening around 18:00 hrs. An application for a permit to drill will be submitted for the re-drill of this well. Please let me know if you have any questions regarding the sundry application. Cam Johnson | Drilling Engineer | ConocoPhillips Alaska M: 907.223.6277 | M: 907.720.3162 | ATO-1540, 700 G Street, Anchorage, AK From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Tuesday, November 11, 2025 6:53 PM To: Johnson, Cameron <Cameron.Johnson2@conocophillips.com> Subject: Re: [EXTERNAL]Re: 3T-731A_PTD 225-103_Status Update and Proposed Abandonment APPROVAL Yes Sent from my iPhone On Nov 11, 2025, at 3:18 PM, Johnson, Cameron <Cameron.Johnson2@conocophillips.com> wrote: Victoria, Thank you for the quick response. Just to confirm, you have given verbal approval to perform the lower abandonment tonight (cement retainer and Plug #1) if the wellbore cannot be recovered. A 10-403 will be submitted tomorrow if we move forward with abandonment. A 10-401 will follow for the new PTD. Notification will be made to the AOGCC inspectors for the tag and pressure test if we do move forward with abandonment. Thank you, Cam Johnson | Drilling Engineer | ConocoPhillips Alaska M: 907.223.6277 | M: 907.720.3162 | ATO-1540, 700 G Street, Anchorage, AK From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Tuesday, November 11, 2025 3:13 PM To: Johnson, Cameron <Cameron.Johnson2@conocophillips.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov> Subject: [EXTERNAL]Re: 3T-731A_PTD 225-103_Status Update and Proposed Abandonment APPROVAL 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. Cameron, A state witnessed tag and pressure test is required on the plug 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. back. Abandonment is approved if the existing well bore cannot be recovered. A change of approved sundry must be submitted before proceeding with further operations. A new 10-401 PTD will be required for the redrill. Victoria Sent from my iPhone On Nov 11, 2025, at 2:18 PM, Johnson, Cameron <Cameron.Johnson2@conocophillips.com> wrote: Victoria, To summarize our conversation: Previous Ops: 1. 4-1/2 upper completion was pulled from the pre-rig cut 2. The whipstock was set, and a window was milled in the 7-5/8 Casing 1. Top of Window: 4469' MD / 3968' TVD 2. Bottom of Window: 4483' MD / 3974' TVD 3. 20 of new formation was drilled in the C35 formation 4. A LOT was performed to 12.9 ppg EMW 5. A mud motor BHA was picked up and run in hole. 6. Pack-off tendencies were observed when drilling began and overpull was observed while pulling back into the window Current operation: 1. A milling assembly is being made up and run in hole to dress the window and clean up the rat hole. Plan forward (successful milling run) 2. If the milling assembly is successful in cleaning up the window/rat hole, a kick-off assembly will be run back in hole and the well will continue as originally planned. Plan forward (unsuccessful milling run). The rig will begin the plug back process to re-drill the well from under the surface casing shoe. 1. A 7-5/8 Cement Retainer will be set above the window in the 7-5/8 casing 2. Cement will be squeezed into the open hole to abandon the rat-hole. 1. A small amount of cement will be left on top of the retainer 3. A 7-5/8 Cast Iron Bridge Plug will be set 300-500 below the surface casing shoe 4. The 7-5/8 Casing will be cut above this bridge plug 5. The 7-5/8 Casing will be pulled from this cut 6. A cement kick-off plug will be spotted on the cast iron bridge plug up into the surface casing shoe 7. The well will be re-drilled after kicking off this plug 1. A 9-7/8 Intermediate section will be drilled and 7-5/8 casing will be run. 2. The 6-1/2 Production section will be drilled as previously planned and completed with a cemented 4-1/2 liner with frac sleeves. Please find two schematics attached to this email. The first being the current status of the well, the second being the proposed abandonment. As discussed, the decision to move forward with the abandonment will likely be late tonight. Does the AOGCC give approval to proceed with the abandonment, if attempts at recovering the existing wellbore are not successful? Please do not hesitate to reach out if you have any questions. Thank you, Cam Johnson | Drilling Engineer | ConocoPhillips Alaska M: 907.223.6277 | M: 907.720.3162 | ATO-1540, 700 G Street, Anchorage, AK 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. COYOTE OILKUPARUK RIVER KRU 3T-731B 225-124 WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV UNIT 3T-731BInitial Class/TypeDEV / PENDGeoArea890Unit11160On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2251240Field & Pool:KUPARUK RIVER, COYOTE OIL - 490120NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberYes KUPARUK RIVER, COYOTE OIL - 490120 - governed by CO 8194 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA18 Conductor string providedNA19 Surface casing protects all known USDWsNA20 CMT vol adequate to circulate on conductor & surf csgNo21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes PTD 225-103, Sundry 325-69525 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes Max reservoir pressure is 1761 psig(8.1 ppg EMW); will drill w/ 9.0-10.5 ppg EMW28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP is 1343 psig; will test BOPs to 4000 psig; 21 day BOP testing approved30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes33 Is presence of H2S gas probableNo34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated35 Permit can be issued w/o hydrogen sulfide measuresYes Expected reservoir pressure is 8.1 ppg EMW36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate11/13/2025ApprVTLDate11/14/2025ApprADDDate11/13/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 11/14/2025